Inclusion of Delaware and New Jersery in the Clean Air Interstate Rule - Private Sector, Mandatory

ECMPS Reporting Instructions
Monitoring Plan

United States Environmental Protection Agency
Office of Air and Radiation
Clean Air Markets Division
1310 L Street, NW
Washington, DC 20005

June 17, 2009

Table of Contents

June 17, 2009

Table of Contents
Page
1.0 Introduction: The Monitoring Plan .................................................................................... 1
2.0 Monitoring Plan (Root Element) .......................................................................................... 5
2.1 Monitoring Plan Comment Data ........................................................................................ 7
2.2 Unit Stack Configuration Data........................................................................................... 9
2.3 Monitoring Location Data................................................................................................ 11
3.0 Stack Pipe Data .................................................................................................................... 13
4.0 Unit Data ............................................................................................................................... 17
4.1 Unit Capacity Data........................................................................................................... 19
4.2 Unit Control Data............................................................................................................. 21
4.3 Unit Fuel Data .................................................................................................................. 25
5.0 Monitoring Location Attribute Data.................................................................................. 29
6.0 Monitoring Method Data .................................................................................................... 33
7.0 Component Data .................................................................................................................. 41
7.1 Analyzer Range Data ....................................................................................................... 49
7.2 Calibration Standard Data ................................................................................................ 53
8.0 Monitoring System Data...................................................................................................... 57
8.1 Monitoring System Fuel Flow Data................................................................................. 67
8.2 Monitoring System Component Data .............................................................................. 71
9.0 Monitoring Formula Data ................................................................................................... 73
10.0 Monitoring Default Data ................................................................................................... 95
11.0 Monitoring Span Data ..................................................................................................... 113
12.0 Rectangular Duct WAF Data .......................................................................................... 123
13.0 Monitoring Load Data ..................................................................................................... 127

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Table of Contents

Table of Contents (cont.)
Page
14.0 Monitoring Qualification Data ....................................................................................... 135
14.1 Monitoring Qual LME Data......................................................................................... 139
14.2 Monitoring Qual Percent Data ..................................................................................... 145

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June 17, 2009

List of Tables
Page
Table 1:
Table 2:
Table 3:
Table 4:
Table 5:
Table 6:

Stack Pipe ID Prefixes ................................................................................................... 14
Parameter Codes and Descriptions ................................................................................ 22
Control Codes and Descriptions .................................................................................... 22
Fuel Codes and Descriptions ......................................................................................... 26
Indicator Codes and Descriptions .................................................................................. 27
Demonstration Method to Qualify for Monthly Fuel Sampling for
GCV Codes and Descriptions ........................................................................................ 27
Table 7: Demonstration Method to Qualify for Daily or Annual Fuel
Sampling for %S (ARP) Codes and Descriptions.......................................................... 28
Table 8: Material Codes and Description .................................................................................... 31
Table 9: Shape Codes and Descriptions....................................................................................... 31
Table 10: Parameter Codes and Descriptions for Monitoring Methods ...................................... 34
Table 11: Measured Parameters and Applicable Monitoring Methods ....................................... 35
Table 12: Substitute Data Codes and Descriptions ...................................................................... 37
Table 13: Bypass Approach Codes and Descriptions .................................................................. 38
Table 14: Component Type Codes and Descriptions .................................................................. 43
Table 15: Sample Acquisition Method Codes ............................................................................. 44
Table 16: Basis Codes and Descriptions...................................................................................... 46
Table 17: Analyzer Range Codes and Descriptions .................................................................... 50
Table 18: Calibration Standard Codes and Descriptions ............................................................. 54
Table 19: Calibration Source Codes and Descriptions ................................................................ 55
Table 20: System Type Codes and Descriptions ......................................................................... 58
Table 21: System Designation Code and Descriptions ................................................................ 60
Table 22: Fuel Codes and Descriptions ....................................................................................... 61
Table 23: Units of Measure for Maximum Fuel Flow Rate Codes and
Descriptions ................................................................................................................ 68
Table 24: Parameter Codes and Descriptions for Monitoring Formula ....................................... 74
Table 25: F-Factor* Reference Table .......................................................................................... 76
Table 26: SO2 Formula References.............................................................................................. 78
Table 27: SO2 Emission Formulas ............................................................................................... 78
Table 28: NOx Emission Rate Formula Reference Table ............................................................ 80
Table 29: NOx Emission Rate Formulas (lb/mmBtu) .................................................................. 81
Table 30: Moisture Formulas ....................................................................................................... 82
Table 31: CO2 Formula Reference Table..................................................................................... 82
Table 32: CO2 Concentration and Mass Emission Rate Formulas .............................................. 83
Table 33: Heat Input Formula Reference Table .......................................................................... 85
Table 34: Heat Input Formulas .................................................................................................... 87
Table 35: Apportionment and Summation Formulas................................................................... 89
Table 36: NOx Mass Emissions Formulas (lbs/hr) ...................................................................... 90
Table 37: Miscellaneous Formula Codes ..................................................................................... 91
Table 38: Representations for Electronic Reporting .................................................................... 92
Table 39: Parameter Codes and Descriptions for Monitoring Default ........................................ 98
Table 40: Rounding Rules for Default Values ........................................................................... 100
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List of Tables (cont.)
Page
Table 41: Fuel-Specific Minimum Default Moisture Values for SO2, NOx,
CO2, and Heat Input Rate Calculations ..................................................................... 102
Table 42: Fuel-Specific Maximum Default Moisture Values for NOx
Emission Rate Calculations ....................................................................................... 102
Table 43: NOx Emission Factors (lb/mmBtu) for Low Mass Emissions Units ......................... 103
Table 44: SO2 Emission Factors (lb/mmBtu) for Low Mass Emissions Units .......................... 103
Table 45: CO2 Emission Factors (ton/mmBtu) for Low Mass Emissions Units ....................... 103
Table 46: Units of Measure Codes by Parameter ...................................................................... 104
Table 47: Default Purpose Codes and Descriptions .................................................................. 105
Table 48: Fuel Codes and Descriptions ..................................................................................... 105
Table 49: Operating Condition Codes and Descriptions ........................................................... 109
Table 50: Default Source Codes and Descriptions .................................................................... 109
Table 51: Component Type Codes and Descriptions for Monitor Span.................................... 114
Table 52: Provision for Calculating MPC/MEC/MPF Codes and
Descriptions ............................................................................................................... 115
Table 53: Criteria for MPC/MEC/MPF Determinations ........................................................... 116
Table 54: Flow Span Calibration Units of Measure .................................................................. 119
Table 55: WAF Method Code and Descriptions........................................................................ 125
Table 56: Maximum Load Value Codes and Descriptions ........................................................ 129
Table 57: Qualification Type Codes and Descriptions .............................................................. 136
Table 58: Data Requirements for Monitoring Qual LME ......................................................... 140
Table 59: Qualification Data Type Code and Descriptions ....................................................... 146
Table 60: Example Data for Qualification Based on Historical and
Projected Data ............................................................................................................ 148
Table 61: Example of Gas-Fired Qualification Based on Unit Operating Data ........................ 149

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List of Figures
Page
Figure 1: Monitoring Plan XML Schema Complex Elements....................................................... 3
Figure 2: MONITORING PLAN XML Elements ................................................................................ 5
Figure 3: MONITORING PLAN COMMENT DATA XML Elements .................................................... 7
Figure 4: UNIT STACK CONFIGURATION DATA XML Elements ..................................................... 9
Figure 5: MONITORING LOCATION DATA Elements ..................................................................... 11
Figure 6: STACK PIPE DATA Elements ......................................................................................... 13
Figure 7: UNIT DATA XML Elements .......................................................................................... 17
Figure 8: UNIT CAPACITY DATA XML Elements ......................................................................... 19
Figure 9: UNIT CONTROL DATA XML Elements.......................................................................... 21
Figure 10: UNIT FUEL DATA XML Elements ............................................................................... 25
Figure 11: MONITORING LOCATION ATTRIBUTE DATA XML Elements ...................................... 29
Figure 12: MONITORING METHOD DATA XML Elements ............................................................ 33
Figure 13: COMPONENT DATA XML Elements ............................................................................ 41
Figure 14: ANALYZER RANGE DATA XML Elements .................................................................. 49
Figure 15: Calibration Standard Data XML Elements ................................................................ 53
Figure 16: MONITORING SYSTEM DATA XML Elements ............................................................. 57
Figure 17: MONITORING SYSTEM FUEL FLOW DATA XML Elements .......................................... 67
Figure 18: MONITORING SYSTEM COMPONENT DATA XML Elements ........................................ 71
Figure 19: MONITORING FORMULA DATA XML Elements .......................................................... 73
Figure 20: MONITORING DEFAULT DATA XML Elements ........................................................... 95
Figure 21: MONITORING SPAN DATA XML Elements ............................................................... 113
Figure 22: RECTANGULAR DUCT WAF DATA XML Elements .................................................. 123
Figure 23: MONITORING LOAD DATA XML Elements ............................................................... 127
Figure 24: MONITORING QUALIFICATION DATA XML Elements ............................................... 135
Figure 25: MONITORING QUAL LME DATA XML Elements ..................................................... 139
Figure 26: MONITORING QUAL PERCENT DATA XML Elements ............................................... 145

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1.0 Introduction: The Monitoring Plan

June 17, 2009

ECMPS Reporting Instructions
Monitoring Plan
1.0 INTRODUCTION: The Monitoring Plan
About This Document
In the Emissions Collection and Monitoring Plan System (ECMPS), data must be submitted to
the EPA through the Client Tool using extensible-markup language (XML) format. XML files
must contain certain data elements, which are defined in the XML schema. (Note: More
information about the ECMPS XML Schemas can be found in the XML Schema Description
Documents.)
The purpose of the reporting instructions is to provide the necessary information for owners and
operators to meet the reporting requirements for sources affected by:
1) The Acid Rain Program (ARP);
2) The Clean Air Interstate Rule (CAIR); and
3) Other programs required to report data using these XML schemas.
These instructions explain how to report the required data for the applicable regulations. Owners
and operators of units should refer to the applicable regulations for information about what data
are required to be reported.
The Monitoring Plan XML Schema is made up of a root element, complex elements, and simple
elements. A simple element is a single piece of data. A complex element is a group of simple
elements which are logically grouped together. The root element is the base of the XML
schema.
The elements are related to each other in parent-child relationships. The root element is the
parent element of the entire schema. Complex elements are children of the root element, and
complex elements can also be children of other complex elements. If a complex element is
dependent on a parent complex element, the child complex element cannot be included in the
XML file unless the appropriate parent complex element is also included. Figure 1 below
illustrates the relationships between the monitoring plan root element and the complex elements.
This document provides instructions on how the required data should be reported using this data
structure. A separate section is provided for each complex element, its dependencies, and its
simple elements. In addition, there are "specific considerations" that apply to particular types of
monitoring plan configurations.
About Monitoring Plan Data
The Monitoring Plan describes how a monitoring configuration monitors its emissions.
Monitoring plan data define relationships between stacks, pipes, and units, specify locations at a

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1.0 Introduction: The Monitoring Plan

facility from which emissions are monitored, and identify systems of monitoring equipment by
detailing the individual system components. Monitoring plan data also provide operational
characteristics and qualifications for certain special types of monitoring (e.g., Low Mass
Emissions monitoring).

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1.0 Introduction: The Monitoring Plan

June 17, 2009

Figure 1
Monitoring Plan XML Schema Complex Elements
LEGEND
2.0 Monitoring Plan

Root
Element

Parent
and
Child

Child Only

2.1
Monitoring
Plan Comment

2.3
Monitoring
Location

2.2
Unit Stack
Configuration

4.1
Unit
Capacity
3.0
Stack Pipe
Data

4.0
Unit Data

4.2
Unit
Control
4.3
Unit Fuel

5.0
Monitoring
Location
Attribute

6.0
Monitoring
Method

9.0
Monitoring
Formula

11.0
Monitoring
Span

10.0
Monitoring
Default

12.0
Rectangular
Duct WAF

14.1
Monitoring
Qualification
Percent

14.0
Monitoring
Qualification

7.1
Analyzer
Range
8.0
Monitoring
System

7.0
Component
7.2
Calibration
Standard

14.2
Monitoring
Qualification
LME

8.1
Monitoring
System
Fuel Flow

Environmental Protection Agency

13.0
Monitoring
Load

8.2
Monitoring
System
Component

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1.0 Introduction: The Monitoring Plan

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2.0 Monitoring Plan

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2.0 MONITORING PLAN (Root Element)
Figure 2
MONITORING PLAN XML Elements

Description of Data
The MONITORING PLAN root element defines the configuration of the monitoring plan and is the
"keystone" record for building a monitoring plan. Hence the MONITORING PLAN record includes
essential identifying information for a complete monitoring plan. Submit one MONITORING PLAN
record for each monitoring plan and ensure that it is the first data record reported.
Dependencies for MONITORING PLAN
The MONITORING PLAN record is not dependent on any other elements of the monitoring plan.
The following complex elements specify additional monitoring plan data and are dependent on
the MONITORING PLAN record:
● MONITORING PLAN COMMENT DATA
● UNIT STACK CONFIGURATION DATA
● MONITORING LOCATION DATA
These complex elements cannot be submitted for a monitoring plan unless an applicable
MONITORING PLAN record is included.

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2.0 Monitoring Plan

MONITORING PLAN Elements
Instructions for completing each element of the MONITORING PLAN section are provided below:
ORIS Code
Element Name: ORISCode
Report the code that indicates the unique identifying number given to a plant by the Energy
Information Administration (EIA) and remains unchanged under ownership changes.
Version
Element Name: Version
Report the XML schema version number. Note that this is a numeric field -- do not include a "v"
before the number.

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2.1 Monitoring Plan Comment Data

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2.1 MONITORING PLAN COMMENT DATA
Figure 3
MONITORING PLAN COMMENT DATA XML Elements

Description of Data
If necessary, you may submit a MONITORING PLAN COMMENT DATA record with each monitoring
plan submission or revision. The MONITORING PLAN COMMENT DATA record allows you to
include comments regarding the monitoring plan submission. If you do not have any comments
on the plan, omit the MONITORING PLAN COMMENT DATA complex element entirely.
Dependencies for MONITORING PLAN COMMENT DATA
The MONITORING PLAN COMMENT DATA record is dependent on the MONITORING PLAN record.
No other records are dependent upon the MONITORING PLAN COMMENT DATA record.
MONITORING PLAN COMMENT DATA Elements
Instructions for completing each element of the MONITORING PLAN COMMENT DATA section are
provided below:
Monitoring Plan Comment
Element Name: MonitoringPlanComment
Report any comments concerning the monitoring plan.
Begin Date
Element Name: BeginDate
Report the date on which the comment became effective.
End Date
Element Name: EndDate
If applicable, report the last date on the comment was effective. This value should be left blank
for active records.

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2.1 Monitoring Plan Comment Data

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2.2 Unit Stack Configuration Data

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2.2 UNIT STACK CONFIGURATION DATA
Figure 4
UNIT STACK CONFIGURATION DATA XML Elements

Description of Data
Submit a UNIT STACK CONFIGURATION DATA record for each unit-stack relationship defined in
the monitoring plan. Each UNIT STACK CONFIGURATION DATA record identifies a specific
configuration or relationship between a unit and a monitored stack through which it exhausts, or
a unit and a pipe that serves the unit. This relationship defines the configuration and methods
used for monitoring. See the instructions for the STACK PIPE DATA record for more information
about when and how to define multiple and common stacks and pipes.
Dependencies for UNIT STACK CONFIGURATION DATA
The UNIT STACK CONFIGURATION DATA record is dependent on the MONITORING PLAN record.
No other records are dependent upon the UNIT STACK CONFIGURATION DATA record.
Unit Stack Configuration Data Elements
Instructions for completing each element of the UNIT STACK CONFIGURATION DATA section are
provided below:
Stack Pipe ID
Element Name: StackPipeID
Report the Stack Pipe ID that corresponds to the monitoring location. This is the alphanumeric
code assigned by a source to identify a multiple or common stack or pipe at which emissions are
determined.
Unit ID
Element Name: UnitID
Report the applicable Unit ID for the unit that is linked to the stack or pipe. This is the one to six
alphanumeric character code assigned by a source to identify a unit.

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2.2 Unit Stack Configuration Data

Begin Date
Element Name: BeginDate
Report the date on which some or all of the emissions from the unit were first measured at the
common or multiple stack/pipe. This data should be equal to or later than the ActiveDate for the
StackPipe, as reported in the STACK PIPE DATA record.
End Date
Element Name: EndDate
If the unit is no longer linked to the stack or pipe in terms of monitored emissions, report the last
date on which the emissions from the unit were measured at the common or multiple stack/pipe.
For an active relationship, leave this field blank.

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2.3 Monitoring Location Data

June 17, 2009

2.3 MONITORING LOCATION DATA
Figure 5
MONITORING LOCATION DATA Elements

Description of Data
The MONITORING LOCATION DATA record is used to identify the unit(s) in the monitoring plan,
as well as any stack(s) or pipe(s) defined as a monitoring location. Submit a MONITORING
LOCATION DATA record for each stack, pipe, and unit in the monitoring plan. See instructions for
the STACK PIPE DATA record for more information about defining stacks and pipes.
Dependencies for Monitoring Location Data
The MONITORING LOCATION DATA record is dependent on the MONITORING PLAN record.
The following complex elements specify additional monitoring location data and are dependent
on the MONITORING LOCATION DATA record:
● STACK PIPE DATA
● UNIT DATA
These complex elements cannot be submitted for a monitoring location unless an applicable
MONITORING LOCATION DATA record is included.
MONITORING LOCATION DATA Elements
Instructions for completing each element of the MONITORING LOCATION DATA section are
provided below:
Stack Pipe ID
Element Name: StackPipeID
If this record is for a stack or pipe, report the Stack Pipe ID that corresponds to the monitoring
location. This is the alphanumeric code assigned by a source to identify the stack or pipe. If this
record is for a unit, leave this field blank.
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2.3 Monitoring Location Data

Unit ID
Element Name: UnitID
If this record is for a unit, report the Unit ID that corresponds to the monitoring location being
described. This is the alphanumeric code assigned by a source to identify a unit. If this record is
for a Stack or Pipe, leave this field blank.

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3.0 Stack Pipe Data

June 17, 2009

3.0 STACK PIPE DATA
Figure 6
STACK PIPE DATA Elements

Description of Data
Submit a STACK PIPE DATA record describing each stack or pipe at which emissions from more
than one unit are measured or determined (i.e., a common stack or pipe) or stacks from which
partial emissions from a unit are measured (i.e., a multiple stack). Bypass stacks should be
defined as monitoring locations only if the emissions from the bypass are monitored (as opposed
to using maximum potential or other appropriate substitute data values).

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3.0 Stack Pipe Data

Types of Stacks and Pipes
When assigning IDs to stacks or pipes, consider the following types of stacks and pipes and the
associated ID prefix:
● Common Stacks: If a stack serves more than one unit and emissions are monitored at
that stack, it must be defined as a "common stack" for reporting purposes. Assign a
common stack ID beginning with the prefix "CS" followed by one to four alphanumeric
characters.
● Common Pipes: If a fuel pipe serves more than one unit and fuel flow is monitored at
that common pipe header, it must be defined as a "common pipe" for reporting purposes.
Assign a pipe ID beginning with the prefix "CP" followed by one to four additional
alphanumeric characters. If more than one fuel type is associated with the same group of
units, it is not necessary to report a common pipe for each fuel type; rather, define one
"common pipe" and define separate fuel flow monitoring systems for each fuel type at the
pipe.
● Multiple Ducts or Stacks: A multiple stack defines two or more ducts or stacks in
which CEMS are located for a single unit. (It also defines any additional monitoring
location(s) for a single unit that is also monitored at a common stack or common pipe.) If
a unit has a CEMS located in more than one duct or stack from the unit, assign a multiple
stack ID to each monitoring location. Assign a stack ID beginning with the prefix "MS"
followed by one to four alphanumeric characters.
● Multiple Pipes: For a combined cycle (CC) peaking unit with a combustion turbine and
duct burner for which: (1) Appendices D and E are used; and (2) fuel flow is measured
separately for the turbine and duct burner, define multiple pipes, i.e., one for each fuel
flowmeter location. Assign a pipe ID beginning with the prefix "MP" followed by one to
four alphanumeric characters. Consult with the EPA Clean Air Markets Division or state
agency prior to initial monitoring plan submission if a facility has this configuration.
Table 1 summarizes the information above:

Table 1
Stack Pipe ID Prefixes
Prefix

Description

CS

Common Stack

CP

Common Pipe

MS

Multiple Stack or Duct

MP

Multiple Pipe

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3.0 Stack Pipe Data

June 17, 2009

Dependencies for STACK PIPE DATA
The STACK PIPE DATA record is dependent on the MONITORING LOCATION DATA record.
The following complex elements specify additional monitoring plan data and are dependent on
the STACK PIPE DATA record:
●
●
●
●
●
●
●
●
●
●

MONITORING LOCATION ATTRIB DATA
MONITORING METHOD DATA
MONITORING FORMULA DATA
MONITORING DEFAULT DATA
MONITORING SPAN DATA
MONITORING LOAD DATA
COMPONENT DATA
MONITORING SYSTEM DATA
MONITORING QUALIFICATION DATA
RECTANGULAR DUCT WAF DATA

These complex elements cannot be submitted for a stack or pipe unless an applicable STACK PIPE
DATA record is included.
STACK PIPE DATA Elements
Instructions for completing each element of the STACK PIPE DATA section are provided below:
Active Date
Element Name: ActiveDate
Report either the date emissions first went through the stack or, for a stack or pipe existing prior
to the date that the associated unit(s) became subject to the applicable program, report that
program effective date. For a stack or pipe that became operational after the associated unit's
program effective date, report the actual date on which emissions first exited the stack or fuel
was combusted at the pipe or stack location by an affected unit.
Retire Date
Element Name: RetireDate
If applicable, report the actual date the stack or pipe was last used for emissions measurement or
estimation purposes. Do not report estimated dates in this field. For active stacks and pipes,
leave this field blank.

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3.0 Stack Pipe Data

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4.0 Unit Data

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4.0 UNIT DATA
Figure 7
UNIT DATA XML Elements

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4.0 Unit Data

Description of Data
The UNIT DATA record is used to define, for each unit identified in the MONITORING LOCATION
DATA record, whether that unit is a non-load-based unit under Part 75. Submit a UNIT DATA
record for each unit that is part of the monitoring plan configuration, whether or not monitoring
is to be performed at the unit level. Information regarding the unit's heat input capacity,
associated controls, and available fuels will be linked to each unit identified by a UNIT DATA
record.
Dependencies for UNIT DATA
The UNIT DATA record is dependent on the MONITORING LOCATION DATA record.
The following complex elements specify additional unit data and are dependent on the UNIT
DATA record:
●
●
●
●
●
●
●
●
●
●
●
●
●

MONITORING LOCATION ATTRIBUTE DATA
UNIT CAPACITY DATA
UNIT CONTROL DATA
UNIT FUEL DATA
MONITORING METHOD DATA
MONITORING FORMULA DATA
MONITORING DEFAULT DATA
MONITORING SPAN DATA
MONITORING LOAD DATA
COMPONENT DATA
MONITORING SYSTEM DATA
MONITORING QUALIFICATION DATA
RECTANGULAR DUCT WAF DATA

These complex elements cannot be submitted for a unit unless an applicable UNIT DATA record
is included. See the instructions for each complex element to determine whether or not to
include it for a particular unit.
UNIT DATA Elements
Instructions for completing each element of the UNIT DATA section are provided below:
Non Load Based Indicator
Element Name: NonLoadBasedIndicator
Report a non load-based indicator value of "1" if the unit does not produce electrical or steam
load. Report a "0" if the unit does produce electrical or steam load.

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4.1 Unit Capacity Data

June 17, 2009

4.1 UNIT CAPACITY DATA
Figure 8
UNIT CAPACITY DATA XML Elements

Description of Data
Report a UNIT CAPACITY DATA record for each unit defined in a UNIT DATA record of the
monitoring plan. This record is used to specify the maximum hourly heat input capacity for each
unit. Update this record only if the maximum hourly heat input capacity changes based on the
design of the unit or its observed data over the past five years.
For more information on derated, combined cycle, and Low Mass Emission (LME) units for this
record see the "Specific Considerations" section below.
Dependencies for UNIT CAPACITY DATA
The UNIT CAPACITY DATA record is dependent on the UNIT DATA record.
No other records are dependent upon the UNIT CAPACITY DATA record.
UNIT CAPACITY DATA Elements
Instructions for completing each element of the UNIT CAPACITY DATA section are provided
below:
Maximum Hourly Heat Input Capacity
Element Name: MaximumHourlyHeatInputCapacity
Report the design heat input capacity (in mmBtu/hr) for the unit or the highest hourly heat input
rate observed in the past five years, whichever is greater.
Begin Date
Element Name: BeginDate
Report the date on which the reported maximum hourly heat input capacity for a unit became
effective.

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4.1 Unit Capacity Data

End Date
Element Name: EndDate
Report the last date on which the reported maximum hourly heat input capacity for a unit was
valid. This value should be left blank for active records.
Specific Considerations
Derated Units
● If a unit has been derated, report the derated maximum heat input capacity.
Combined Cycle Units
● For combined cycle units without duct burners, report the maximum heat input of the unit
combustion turbine. For combined cycle units with duct burners, report the combined
maximum heat input for the combustion turbine and duct burner, unless, in agreement
with EPA, the duct burner has been defined as a separate unit.
Low Mass Emission (LME) Units
● Enter the maximum rated hourly heat input for units using the LME methodology as
defined in §72.2 or modified according to §75.19(c)(2)(i).

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4.2 Unit Control Data

June 17, 2009

4.2 UNIT CONTROL DATA
Figure 9
UNIT CONTROL DATA XML Elements

Description of Data
The UNIT CONTROL DATA record is used to identify emissions controls that are utilized or
planned for the specified unit. Submit a UNIT CONTROL DATA record for each type of NOx, SO2,
or particulate control equipment in place or planned for each unit defined in the monitoring plan.
These data include information describing the parameter emitted and the corresponding control
type. For controls with co-benefits (e.g., flue gas desulfurization systems (FGD)), just list the
control once using the parameter code that corresponds to the primary pollutant controlled.
Do not report UNIT CONTROL DATA for any parameter (NOX, SO2, or PART) for which the unit
is uncontrolled. Similarly, do not report unit control data for a parameter if emissions of that
parameter are controlled only by limiting production or by switching fuels.
Dependencies for UNIT CONTROL DATA
The UNIT CONTROL DATA record is dependent on the UNIT DATA record.
No other records are dependent upon the UNIT CONTROL DATA record.

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4.2 Unit Control Data

UNIT CONTROL DATA Elements
Instructions for completing each element of the UNIT CONTROL DATA section are provided
below:
Parameter Code
Element Name: ParameterCode
Report the parameter being controlled by using one of the following uppercase codes as shown
in Table 2:

Table 2
Parameter Codes and Descriptions
Code

Description

NOX

Nitrogen Oxides

SO2

Sulfur Dioxide

PART

Particulates (opacity)

Control Code
Element Name: ControlCode
Report the code for the corresponding control device by reporting the uppercase control code as
shown in Table 3:

Table 3
Control Codes and Descriptions

Parameter
NOX

Control
Code

Description

CM

Combustion Modification/Fuel Reburning

DLNB

Dry Low NOx Premixed Technology (turbines only)

H2O

Water Injection (turbines and cyclone boilers only)

LNB

Low NOx Burner Technology (dry bottom wall-fired boilers or
process heaters only)

LNBO

Low NOx Burner Technology with Overfire Air (dry bottom wallfired boilers, dry bottom turbo-fired boilers, or process heaters only)
(cont.)

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Environmental Protection Agency

4.2 Unit Control Data

June 17, 2009

Table 3
Control Codes and Descriptions (cont.)
Control
Code

Parameter
NOX (cont.)

SO2

PART

Description

LNC1

Low NOx Burner Technology with Close-Coupled Overfire Air
(OFA) (tangentially fired units only)

LNC2

Low NOx Burner Technology with Separated OFA (tangentially
fired units only)

LNC3

Low NOx Burner Technology with Close-Coupled and Separated
OFA (tangentially fired units only)

LNCB

Low NOx Burner Technology for Cell Burners

NH3

Ammonia Injection

O

Other

OFA

Overfire Air

SCR

Selective Catalytic Reduction

SNCR

Selective Non-Catalytic Reduction

STM

Steam Injection

DA

Dual Alkali

DL

Dry Lime FGD

FBL

Fluidized Bed Limestone Injection

MO

Magnesium Oxide

O

Other

SB

Sodium Based

WL

Wet Lime FGD

WLS

Wet Limestone

B

Baghouse(s)

ESP

Electrostatic Precipitator

HESP

Hybrid Electrostatic Precipitator

WESP

Wet Electrostatic Precipitator

WS

Wet Scrubber

O

Other

C

Cyclone

Environmental Protection Agency

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4.2 Unit Control Data

Original Code
Element Name: OriginalCode
For each record, indicate whether or not the control equipment was installed and operational as
part of the original unit design. The number "1" indicates the equipment was a part of the
original unit, and "0" indicates that it was not.
Install Date
Element Name: InstallDate
Report the approximate date on which controls were installed or will be installed at the unit, if
the control equipment was not part of the original installation. If the equipment was part of the
original installation, leave this field blank.
Optimization Date
Element Name: OptimizationDate
Report the approximate date on which optimization of the control equipment was completed and
the equipment was fully operational at the unit, if the control equipment was not part of the
original installation. If the equipment was part of the original installation, leave this field blank.
Seasonal Controls Indicator
Element Name: SeasonalControlsIndicator
Report a "1" in the Seasonal Control Indicator field for NOx Budget Program units if the NOx
control equipment is used only during the ozone season. If not, report "0" (zero).
Retire Date
Element Name: RetireDate
Report the date on which the control equipment was removed or retired from the unit. This value
should be left blank if the control equipment is still in use.

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Environmental Protection Agency

4.3 Unit Fuel Data

June 17, 2009

4.3 UNIT FUEL DATA
Figure 10
UNIT FUEL DATA XML Elements

Description of Data
For each unit identified in the UNIT DATA record of the monitoring plan, submit a UNIT FUEL
DATA record for each type of fuel combusted by the unit. The UNIT FUEL DATA record is used to
indicate the primary, secondary, emergency, and startup fuels combusted by each unit, to report
changes in the types of fuels combusted and to indicate when such changes occurred.
Dependencies for UNIT FUEL DATA
The UNIT FUEL DATA record is dependent on the UNIT DATA record.
No other records are dependent upon the UNIT FUEL DATA record.

Environmental Protection Agency

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June 17, 2009

4.3 Unit Fuel Data

UNIT FUEL DATA Elements
Instructions for completing each element of the UNIT FUEL DATA section are provided below:
Fuel Code
Element Name: FuelCode
Report one of the following uppercase codes to indicate the types of fuel combusted by a unit as
shown in Table 4:

Table 4
Fuel Codes and Descriptions
Code

Description

C

Coal

CRF

Coal Refuse (culm or gob)

DSL

Diesel Oil*

LPG

Liquefied Petroleum Gas

NNG

Natural Gas

OGS

Other Gas

OIL

Residual Oil

OOL

Other Oil

OSF

Other Solid Fuel

PNG

Pipeline Natural Gas
(as defined in §72.2)

PRG

Process Gas

PRS

Process Sludge

PTC

Petroleum Coke

R

Refuse

TDF

Tire Derived Fuel

W

Wood

WL

Waste Liquid

* Diesel oil is defined in §72.2 as low sulfur fuel oil of grades 1-D or 2-D, as defined by ASTM D-975-91,
grades 1-GT or 2-GT, as defined by ASTM D2880-90a, or grades 1 or 2, as defined by ASTM D396-90.
By those definitions (specifically ASTM D396-90) and for the purposes of this program, kerosene and
ultra-low sulfur diesel fuel (ULSD) are considered subsets of diesel oil and therefore should be identified
with the code DSL. If a fuel does not qualify as one of these types, do not report the code DSL.

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4.3 Unit Fuel Data

June 17, 2009

Indicator Code
Element Name: IndicatorCode
Report whether the fuel type listed is the primary fuel (as defined in §72.2), a backup
(secondary) fuel, a startup fuel, or an emergency fuel for this unit by using one of the uppercase
codes shown in Table 5:

Table 5
Indicator Codes and Descriptions
Code

Description

E

Emergency

I

Ignition (startup)

P

Primary

S

Backup (secondary)

Ozone Season Indicator
Element Name: OzoneSeasonIndicator
Report "1" in the Ozone Season Indicator for the secondary fuel(s) record(s) if fuel switching (to
a secondary fuel or fuels) is used for seasonal control of ozone. If not, report "0" (zero).
Demonstration Method to Qualify for Monthly Fuel Sampling for GCV
Element Name: DemGCV
If applicable, report the method used to demonstrate that a unit using Appendix D qualifies for
monthly GCV fuel sampling (see Section 2.3.5 of Appendix D) by using one of the following
uppercase codes as shown in Table 6:

Table 6
Demonstration Method to Qualify for Monthly Fuel Sampling for GCV Codes and
Descriptions
Code

Environmental Protection Agency

Description

GHS

720 Hours of Data Using Hourly
Sampling

GGC

720 Hours of Data Using an Online
Gas Chromatograph

GOC

720 Hours of Data Using an Online
Calorimeter

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June 17, 2009

4.3 Unit Fuel Data

Demonstration Method to Qualify for Daily or Annual Fuel Sampling for %S (ARP)
Element Name: DemSO2
If applicable, report the method used to demonstrate that an Acid Rain unit using Appendix D
qualifies for daily or annual percent sulfur sampling (see Section 2.3.6 of Appendix D) using one
of the uppercase codes shown in Table 7:

Table 7
Demonstration Method to Qualify for Daily or Annual Fuel Sampling
for %S (ARP) Codes and Descriptions
Code

Description

SHS

720 Hours of Data Using Manual
Hourly Sampling

SGC

720 Hours of Data Using Online Gas
Chromatograph

Begin Date
Element Name: BeginDate
Report the first date on which the unit combusted this fuel type (or the best available estimate if
the exact date is not known). The fuel type Begin Date must precede or coincide with the date of
any monitoring system certifications while combusting the fuel.
End Date
Element Name: EndDate
Report the last date on which a given fuel type was combusted at the unit if the combustion of
this fuel type has been permanently discontinued at this unit. This value should be left blank for
fuels that are still being used.

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Environmental Protection Agency

5.0 Monitoring Location Attribute Data

June 17, 2009

5.0 MONITORING LOCATION ATTRIBUTE DATA
Figure 11
MONITORING LOCATION ATTRIBUTE DATA XML Elements

Description of Data
The MONITORING LOCATION ATTRIBUTE DATA record provides a description of the physical
characteristics of a specified monitoring location. Submit a MONITORING LOCATION ATTRIBUTE
DATA record for each multiple or common stack defined in a monitoring plan. Also report a
MONITORING LOCATION ATTRIBUTE DATA record for each unit in the monitoring plan if
emissions are monitored or determined there. Do not report this record for pipes.
For multiple stack (MS) configurations, if the monitors are located on the stacks, report the
height, elevation and inside cross-sectional area (CSA) information for each stack (i.e., stack exit
CSA and, if applicable, the CSA at the flow monitor location). If the monitors are located at
breechings or ducts rather than on the stack, in the MONITORING LOCATION ATTRIBUTE record for
each multiple stack report the stack exit height, base elevation and inside CSA information for
the exhaust stack, and report the CSA at the stack exit and, if applicable, the inside CSA at the
flow monitor location in the ductwork.
For units that are part of a common pipe (CP) or multiple (MP) configuration and use Appendix
D estimation procedures for heat input, CO2, or SO2, report (using the appropriate Unit ID or
Stack ID) the stack height, elevation and inside cross-sectional area of the stack through which
emissions are discharged to the atmosphere. This can be a single unit stack or a stack serving
more than one unit. If the unit emits through more than one stack, report information for the
stack typically associated with higher emissions for the unit.
Environmental Protection Agency

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June 17, 2009

5.0 Monitoring Location Attribute Data

Dependencies for MONITORING LOCATION ATTRIBUTE DATA
The MONITORING LOCATION ATTRIBUTE DATA record is dependent on the UNIT DATA record or
the STACK PIPE DATA record.
No other records are dependent upon the MONITORING LOCATION ATTRIBUTE DATA record.
MONITORING LOCATION ATTRIBUTE DATA Elements
Instructions for completing each element of the MONITORING LOCATION ATTRIBUTE DATA
section are provided below:
Duct Indicator
Element Name: DuctIndicator
Report a "1" or a "0" indicating whether the monitoring location is a duct, with "1" meaning yes
and "0" meaning no.
Bypass Indicator
Element Name: BypassIndicator
Report a "1" or a "0" indicating whether the monitoring location is a bypass stack, with "1"
meaning yes and "0" meaning no.
Ground Elevation
Element Name: GroundElevation
Report the elevation of the ground level, in feet above sea level, at the base of a stack or unit.
Stack Height
Element Name: StackHeight
Report the height of the stack exit, in feet above ground level.

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5.0 Monitoring Location Attribute Data

June 17, 2009

Material Code
Element Name: MaterialCode
If applicable (i.e., there is a stack flow monitor at this location), report a code from Table 8 that
most accurately describes the material from which the inner wall of the duct or stack is
constructed at the flow monitoring location:

Table 8
Material Codes and Description
Code

Description

BRICK

Brick and mortar

OTHER

Any material other than brick and
mortar

Shape Code
Element Name: ShapeCode
If applicable (i.e., there is a stack flow monitor at this location), report a code from Table 9 that
most accurately describes the shape of a duct or stack at the flow monitoring location:

Table 9
Shape Codes and Descriptions
Code

Description

RECT

Rectangular

ROUND

Round

Cross Area Flow
Element Name: CrossAreaFlow
If applicable (i.e., there is a stack flow monitor at this location), report the inside cross-sectional
area, in square feet, of the stack at the flow monitoring location.
Cross Area Stack Exit
Element Name: CrossAreaStackExit
Report the inside cross-sectional area, in square feet, of the stack at the flue exit.

Environmental Protection Agency

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June 17, 2009

5.0 Monitoring Location Attribute Data

Begin Date
Element Name: BeginDate
Report the date on which these physical characteristics first applied to the location. If this is the
first or only MONITORING LOCATION ATTRIBUTE DATA record for the location, this date should
equal the Active Date in the STACK PIPE DATA record (for common or multiple stacks), or the
date that a unit first became subject to any applicable program (for units). If this is an updated
MONITORING LOCATION ATTRIBUTE DATA record showing a change in one or more attribute
value(s), this date should be the date on which the change took place.
End Date
Element Name: EndDate
Report the last date on which these physical characteristics applied to the location. This value
should be left blank for active attribute information.

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Environmental Protection Agency

6.0 Monitoring Method Data

June 17, 2009

6.0 MONITORING METHOD DATA
Figure 12
MONITORING METHOD DATA XML Elements

Description of Data
The MONITORING METHOD DATA record describes the emissions monitoring methodologies used
at each monitoring location identified in the monitoring plan. A separate MONITORING METHOD
DATA record must be included for each parameter (NOX, SO2, CO2, etc.) monitored or
calculated at each identified monitoring location. Note that when heat input is not monitored at
the unit level, a MONITORING METHOD DATA record for heat input must be included for both the
monitoring location and at the unit level.
For example, if all emissions are monitored at a common stack for Units 1 and 2, report one set
of monitor method records for the common stack location, which includes a single record for
each parameter monitored, and (if heat input monitoring is required) two additional records (i.e.,
one each for Units 1 and 2) indicating the method by which heat input is determined at the unit
level.
Report only one active method for each parameter monitored at the location. For locations with
an unmonitored bypass stack, use the Bypass Approach Code field in the applicable method
record(s) to report whether or not a fuel-specific default value will be used for bypass hours. For
information on particular usages of this record for moisture, heat input, ARP units, NBP units,
LME units and Alternative Monitoring System (AMS), refer to "Specific Considerations" below.
Also, for information on how to update this record, refer to the "Updating the MONITORING
METHOD DATA Record" section below.

Environmental Protection Agency

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6.0 Monitoring Method Data

Dependencies for MONITORING METHOD DATA
The MONITORING METHOD DATA record is dependent on the UNIT DATA record or the STACK
PIPE DATA record.
No other records are dependent upon the MONITORING METHOD DATA record.
MONITORING METHOD DATA Elements
Instructions for completing each element of the MONITORING METHOD DATA section are
provided below:
Parameter Code
Element Name: ParameterCode
Report the appropriate Parameter Code as shown in Table 10:

Table 10
Parameter Codes and Descriptions for Monitoring Methods
Code

Description (Units)

CO2

CO2 Mass Emissions Rate (tons/hr)

CO2M

CO2 Mass Emissions (tons)

H2O

Moisture (%H2O)

HI

Heat Input Rate (mmBtu/hr)

HIT

Heat Input Total (mmBtu) (LME only)

NOX

NOx Mass Emissions Rate (lb/hr)

NOXM

NOx Mass Emissions (lb) (LME only)

NOXR

NOx Emissions Rate (lb/mmBtu)

OP

Opacity (percent)

SO2

SO2 Mass Emissions Rate (lb/hr)

SO2M

SO2 Mass Emissions (lb) (LME only)

Monitoring Plan Reporting Instructions -- Page 34

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6.0 Monitoring Method Data

June 17, 2009

Monitoring Method Code
Element Name: MonitoringMethodCode
Report the Monitoring Method Code that identifies the methodology employed to monitor the
specified parameters at the specified monitoring location. Report the appropriate uppercase code
as shown in Table 11:

Table 11
Measured Parameters and Applicable Monitoring Methods
Parameter
CO2

CO2M

H2O

HI

HIT

Method Code

Description

AD

Appendix D Gas and/or Oil Flow System(s) (Formula G-4)

AMS

Alternative Monitoring System*

CEM

CO2 Continuous Emission Monitor

FSA

Fuel Sampling and Analysis (Formula G-1)

LME

Low Mass Emissions (§75.19)

MMS

Continuous Moisture Sensor

MDF

Moisture Default

MTB

Moisture Lookup Table

MWD

H2O System with Wet and Dry O2 Analyzers

AD

Appendix D Gas and/or Oil Flow System(s)

ADCALC

Appendix D Gas and/or Oil Flow System at location (unit)
and different Oil or Gas Measured at Common Pipe. (Heat
Input at the unit is determined by adding the appropriate value
apportioned from the Common Pipe to the unit value)

AMS

Alternative Monitoring System*

CALC

Calculated from Values Measured at Other Locations.
(Used for three situations: (1) this is the method at a unit
when heat input is determined at a common stack or common
pipe and then apportioned to the constituent units; or (2) this
is the method at a unit when heat input is determined at
multiple stacks and then summed to the unit; or (3) this is the
method at a common stack if heat input is determined at the
units and then summed to the common stack in order to
calculate NOx mass)

CEM

Flow and O2 or CO2 Continuous Emission Monitors

EXP

Exempt from Heat Input monitoring

LTFF

Long-Term Fuel Flow (Low Mass Emissions -- §75.19)
(cont.)

Environmental Protection Agency

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June 17, 2009

6.0 Monitoring Method Data

Table 11
Measured Parameters and Applicable Monitoring Methods (cont.)
Parameter
HIT (cont.)

Method Code

Description

LTFCALC

Long-Term Fuel Flow (Low Mass Emissions -- §75.19) at the
unit and different Long Term Fuel Flow at the common pipe.
(Heat Input at the unit is determined by adding the appropriate
value apportioned from the Common Pipe to the unit value)

MHHI

Maximum Rated Hourly Heat Input (Low Mass Emissions)

CALC

Calculated from values measured at the common pipe. (This
is the method at a unit when heat input is determined at a
common pipe and apportioned to the constituent units)

AMS

Alternative Monitoring System*

CEM

NOx Concentration times Stack Flow rate

CEMNOXR

NOx Concentration times Stack Flow rate and NOx Emission
Rate times Heat Input Rate (one as a primary method and the
other as secondary). This method is not permitted after
December 31, 2007

NOXR

NOx Emission Rate times Heat Input Rate

NOXM

LME

Low Mass Emissions (§75.19)

NOXR

AMS

Alternative Monitoring System*

AE

Appendix E

CEM

NOx Emission Rate CEMS

PEM

Predictive Emissions Monitoring System (as approved by
petition)

COM

Continuous Opacity or Particulate Matter Monitor

EXP

Exempted

AD

Appendix D Gas and/or Oil Flow System(s)

AMS

Alternative Monitoring System*

CEM

SO2 Continuous Emission Monitor

CEMF23

SO2 Continuous Emission Monitor, and Use of F-23 Equation
during hours when only very low sulfur fuel is burned per
§§75.11(e) and 75.11(e)(4)

F23

Use of F-23 Equation if only very low sulfur fuel is burned
per §§75.11(e) and 75.11(e)(4)

LME

Low Mass Emissions (§75.19)

NOX

OP

SO2

SO2M

* Use of this method requires EPA approval

Monitoring Plan Reporting Instructions -- Page 36

Environmental Protection Agency

6.0 Monitoring Method Data

June 17, 2009

Substitute Data Code
Element Name: SubstituteDataCode
Report the Substitute Data Code that designates the methodology used to determine substitute
values during periods of missing data. Leave this field blank when NOX Mass is calculated
from NOX Rate and HI (Method Code NOXR and Parameter Code NOX). Also, leave this field
blank for parameter code OP and all LME methods, with the following exception. When using
long-term fuel flow as the heat input methodology for an LME unit, report a Substitute Data
Code of MHHI only if it will ever be necessary to report the unit's maximum rated hourly heat
input rate as the heat input rate for any hour. This may be necessary for either of two reasons:
(1) for any hour when burning a secondary fuel that is not measured by a long-term fuel flow
system, or (2) if a unit operated for only a very short period or used only a very limited amount
of fuel during a quarter or reporting period, so that a tank drop measurement will not yield an
accurate estimate of the fuel combusted during the reporting period. Report the appropriate
uppercase code as shown in Table 12:

Table 12
Substitute Data Codes and Descriptions
Code

Description

Appropriate For Parameter Codes

SPTS

Standard Part 75

NOXR, NOX, SO2, CO2, H2O, and HI

FSP75

Fuel-Specific Part 75

NOXR, NOX, SO2, CO2, H2O, and HI

FSP75C

Fuel-Specific Part 75 with separate NOXR, NOX, SO2, CO2, H2O, and HI
co-fired database

OZN75

Ozone vs. Non-Ozone Season

NOX, NOXR

NLB

Non-Load Based

NOXR, NOX, and HI

NLBOP

Non-Load Based with Operational NOXR, NOX, and HI
Bins

REV75

Reverse of Standard Part 75

H2O

MHHI

Maximum Rated Hourly Heat
Input Rate for LME Units using
Long Term Fuel Flow
methodology

HIT

Environmental Protection Agency

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June 17, 2009

6.0 Monitoring Method Data

Bypass Approach Code
Element Name: BypassApproachCode
Report the Bypass Approach Code used to calculate emissions for an unmonitored bypass stack
whose method of determining emissions is based on a default value. The Bypass Approach Code
is not required if a bypass stack is directly monitored or valid data are calculated from monitors
at other locations (e.g., at a control device inlet). This code is only applicable for parameters
SO2, NOX, and NOXR with CEM, CEMF23, and NOXR method codes. Report the appropriate
uppercase codes as shown in Table 13:

Table 13
Bypass Approach Codes and Descriptions
Code

Description

BYMAX

MPC or MER* for Highest Emitting
Fuel

BYMAXFS

Fuel-Specific MPC or MER*

* Note that MEC or MCR may be used for documented controlled hours.

Begin Date
Element Name: BeginDate
Report the date on which the methodology was first used to determine emissions or heat input
rate for the monitoring location. For opacity, report the same starting date as for emission
reporting, whether the applicable units are exempted from opacity monitoring or not.
For new units, report the first date on which the methodology is expected to be used to determine
emissions or heat input rate. Correct as needed when the actual begin date is known.
Begin Hour
Element Name: BeginHour
Report the hour in which the methodology was first used to determine emissions or heat input
rate for the monitoring location.
End Date
Element Name: EndDate
Report the date on which the methodology was last used to determine emissions or heat input
rate for the monitoring location. This value should be left blank for active records.

Monitoring Plan Reporting Instructions -- Page 38

Environmental Protection Agency

6.0 Monitoring Method Data

June 17, 2009

End Hour
Element Name: EndHour
Report the hour in which the methodology was last used to determine emissions or heat input
rate for the monitoring location. This value should be left blank for active records.
Specific Considerations
Moisture
● If required to correct for moisture (H2O) when calculating emissions or heat input at a
monitoring location, report a separate monitor method record for the H2O parameter. Do
this for each location at which moisture is needed, defining the methodology used to
determine hourly moisture for emissions calculations.
Heat Input
● If heat input monitoring is required, there must be a separate monitor method record for
heat input (HI) data for each unit, even if the monitor location is not at the unit level. For
example, if SO2, CO2, NOx, and Flow monitors are installed at CS001, which serves Unit
1, 2, and 3, there will be a full set of monitor method records for CS001 and only one
monitor method record for HI at each unit. The unit records for monitor method should
indicate that the heat input is calculated for the unit, using the "CALC" monitoring
method code.
Acid Rain Program Units
● If a location which has an SO2 monitor combusts both high sulfur fuel (e.g., coal or oil)
and a low sulfur fuel, and uses a default SO2 emission rate in conjunction with Equation
F-23 for hours in which very low sulfur fuel is combusted (see §75.11(e)(1)), report one
monitor method record for parameter SO2 with a monitoring methodology code
CEMF23. If only low-sulfur fuel is combusted and the F-23 calculation is used for every
hour, report the SO2 monitoring method as F23.
● If a unit or stack is exempt from opacity monitoring, report a monitor method record for
the unit or stack defining the parameter OP with a monitor method code of EXP.
● If opacity is monitored at a common stack or multiple stacks, but no other parameters are
monitored at that location, do not define the stack(s). Instead, report the opacity method
and system data at the unit level.
● If a unit is also subject to Subpart H, be sure to include the appropriate method record(s)
indicating how NOx mass is determined.

Environmental Protection Agency

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6.0 Monitoring Method Data

NOx Budget Program Units
● Report a monitor methodology record for parameter NOX at each applicable location.
● Report the method code as NOXR if NOx mass emissions are calculated by determining
NOx emission rate and heat input rate. Report method code CEM if NOx mass is
calculated as the product of NOx concentration and stack gas flow rate.
● If applicable, report methodology records for NOx emission rate and/or heat input.
Low Mass Emissions (LME) Units
For all LME units as under the methodology in §75.19:
● For Acid Rain Program LME units: Submit separate monitor methodology records for
parameters SO2M, NOXM, CO2M, HIT, and, if applicable OP.
● For Non-Acid Rain, NOx Budget Program LME Units: Submit monitor method records
to describe the methodologies for both NOx mass (NOXM) and heat input (HIT).
Part 75 Alternative Monitoring System (AMS)
● The use of method code AMS for determining average hourly emissions for parameters
CO2, HI, NOX, NOXR, or SO2 is granted through petition based on meeting the
requirements of Subpart E of Part 75.
Updating the MONITORING METHOD DATA Record
When changing monitoring methodologies for a parameter, report both the old and new
MONITORING METHOD DATA records. First, close out the existing monitoring methodology
record by entering the date and hour that the methodology was discontinued (EndDate,
EndHour). Second, create a new monitoring method record for that parameter indicating the date
and hour during which use of the replacement methodology began (BeginDate, BeginHour). For
the new method, leave the values for End Date and End Hour blank.
In order to correct a previously submitted record that contains erroneous information, resubmit
that MONITORING METHOD DATA record with the corrected information. For example, if the SO2
Monitoring Method Code was previously submitted as "CEM" and the correct code should have
been "CEMF23," the record should be updated and resubmitted. Note that the BeginDate and
BeginHour elements should not be updated, unless the BeginDate and/or BeginHour are the
elements to be corrected.

Monitoring Plan Reporting Instructions -- Page 40

Environmental Protection Agency

7.0 Component Data

June 17, 2009

7.0 COMPONENT DATA
Figure 13
COMPONENT DATA XML Elements

Description of Data
The COMPONENT DATA record describes each of the components used to make up the monitoring
systems defined in the monitoring plan. A component can be either a hardware component, such
as a NOx analyzer, or a software component, such as a DAHS. Under most circumstances, only
one COMPONENT DATA record is required for components that are shared by multiple monitoring
systems defined at that location. For example, an O2 monitor that is used in both the NOx
emissions rate system and the moisture monitoring system needs only to be identified in one
COMPONENT DATA record. The exception exists for a combined cycle combustion unit using a
"time-share" CEMS configuration to monitor emissions from both the main and bypass stacks.
Please refer to "Specific Considerations" below for more information.
Information describing the monitoring system of which the component is a part is not needed for
this record. The relationship between components and monitoring systems is defined by the
MONITORING SYSTEM COMPONENT DATA record.
For information on defining DAHS components, how to report fuel flowmeter data when using
flowmeter rotation, and how to represent manufacturer and serial number information, refer to
"Specific Considerations" below.

Environmental Protection Agency

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June 17, 2009

7.0 Component Data

Dependencies for COMPONENT DATA
The COMPONENT DATA record is dependent on the UNIT DATA record or the STACK PIPE DATA
record.
The following records are dependent upon the COMPONENT DATA record:
● ANALYZER RANGE DATA
● MONITORING SYSTEM COMPONENT DATA
● CALIBRATION STANDARD DATA
COMPONENT DATA Elements
Instructions for completing each element of the COMPONENT DATA section are provided below:
Component ID
Element Name: ComponentID
Report the three-character ID assigned to the component. This ID is assigned by a source and
must be unique to a stack, pipe, or unit. For example, two different monitored units or stacks,
e.g., CS1 and CS2, could each have an O2 monitor with the same assigned Component ID of 123.
However, no two components at the same monitored location (in this case, either CS1 or CS2)
are allowed to have the same Component ID. For temporary like-kind analyzer replacements
under §75.20(d), the component ID of the like-kind analyzer must begin with the prefix "LK"
(e.g., "LK1," "LK2," etc.).
Note that components are linked to each system that the component serves using the
MONITORING SYSTEM COMPONENT record. The MONITORING SYSTEM COMPONENT record
includes a begin date and hour to track when a particular component is placed into service as part
of the system, and an end date and hour to indicate when the component is removed or is
replaced.
Do not close out primary monitoring components that are temporarily removed from service for
maintenance, e.g., when a like-kind monitoring component is placed into service while the
primary component is being repaired.
Also, do not close out temporary like-kind replacement analyzer ("LK") components unless a
particular like-kind analyzer will never be used again at the unit or stack location. You may
represent the "LK" analyzer in the monitoring plan as an active component of the primary
monitoring system, for the entire useful life of the LK analyzer.

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7.0 Component Data

June 17, 2009

Component Type Code
Element Name: ComponentTypeCode
Report the code indicating the function of the component. The code does not necessarily
correspond to the function of the monitoring system as a whole in which a component is
included. Report the Component Type Code by using the appropriate uppercase code as shown
in Table 14:

Table 14
Component Type Codes and
Descriptions
Code

Description

BGFF

Billing Gas Fuel Flowmeter

BOFF

Billing Oil Fuel Flowmeter

CALR

Calorimeter

CO2

Carbon Dioxide Concentration
Analyzer

DAHS

Data Acquisition and Handling System

DL

Data Logger or Recorder

DP

Differential Pressure
Transmitter/Transducer

FLC

Flow Computer

FLOW

Stack Flow Monitor

GCH

Gas Chromatograph

GFFM

Gas Fuel Flowmeter

H2O

Percent Moisture (Continuous
Moisture System only)

NOX

Nitrogen Oxide Concentration
Analyzer

O2

Oxygen Concentration Analyzer

OFFM

Oil Fuel Flowmeter

OP

Opacity Measurement

PLC

Programmable Logic Controller

PM

Particulate Matter Measurement

PRB

Probe
(cont.)

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7.0 Component Data

Table 14
Component Type Codes and
Descriptions (cont.)
Code

Description

PRES

Pressure Transmitter/Transducer

SO2

Sulfur Dioxide Concentration
Analyzer

TANK

Oil Supply Tank

TEMP

Temperature Transmitter/Transducer

Sample Acquisition Method Code
Element Name: SampleAcquisitionMethodCode
Report the appropriate concentration/diluent codes, operational principle (volumetric flow
codes), or type of fuel flowmeter (fuel flowmeter type codes). Leave this field blank if a sample
acquisition method is not applicable to the component type (e.g., for a DAHS component). For
LME long-term fuel flow components, leave this field blank unless using a certified fuel
flowmeter to quantify heat input. Report the Sample Acquisition Method Code by using the
appropriate uppercase codes as shown in Table 15:

Table 15
Sample Acquisition Method Codes
Component
For CEMS

Code

Description

DIL

Dilution

DIN

Dilution In-Stack

DOD

Dry Out-of-Stack Dilution

DOU

Dilution Out-of-Stack

EXT

Dry Extractive

IS

In Situ

ISP

Point/Path in Situ

ISC

Cross Stack in Situ

O

Other

WXT

Wet Extractive
(cont.)

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7.0 Component Data

June 17, 2009

Table 15
Sample Acquisition Method Codes (cont.)
Component

Code

For Volumetric Stack Flow Monitor DP

For Fuel Flowmeter Types

Environmental Protection Agency

Description
Differential Pressure

O

Other

T

Thermal

U

Ultrasonic

COR

Coriolis

DP

Differential Pressure (e.g., Annubar)

NOZ

Nozzle

O

Other

ORF

Orifice

PDP

Positive Displacement

T

Thermal Mass Flowmeter

TUR

Turbine

U

Ultrasonic

VCON

V-Cone

VEN

Venturi

VTX

Vortex

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7.0 Component Data

Basis Code
Element Name: BasisCode
For CEM analyzer components, report a code indicating whether the applicable components
sample on a wet or dry basis or use both wet and dry methods. Use the appropriate uppercase
codes as shown in Table 16:

Table 16
Basis Codes and Descriptions
Code

Description

W

Wet

D

Dry

B

Both wet and dry (O2 only)

* For sample acquisition method (SAM) codes IS, ISP, ISC, DIN, DOU, DIL, and WXT = wet extractive;
EXT = dry extractive, located under Component. Exceptions are possible. For all stack flow monitors -wet basis. Check with vendor if uncertain.

Manufacturer
Element Name: Manufacturer
Report the name or commonly used acronym for the manufacturer or developer of the
component. Do not use this field to identify the unit or location of the component. For LME
long-term fuel flow components, leave this field blank unless using a certified fuel flowmeter to
quantify heat input.
Model Version
Element Name: ModelVersion
Report the manufacturer designated model name or number of any hardware component or the
version number of a software component. For LME units using long-term fuel flow, leave this
field blank unless using a certified fuel flowmeter to quantify heat input.
Serial Number
Element Name: SerialNumber
Report the serial number for each component. For hardware or analytical components, the serial
number should be unique and should allow identification of the instrument or device in the field.
For flow monitors, provide a single component serial number that represents the control unit of
the monitor. Leave this field blank for LME long-term fuel flow components, unless using a
certified fuel flowmeter to quantify heat input.

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7.0 Component Data

June 17, 2009

Specific Considerations
Essential DAHS Components (Software and Hardware)
● Identify the software component(s) of the Data Acquisition and Handling System
(DAHS) as individual components. Any software program that calculates emissions or
heat input rate, or implements missing data substitution algorithms or quarterly reporting
functions should be defined as a component. Identify the programmable logic controller
(PLC) or automated data logger (DL) as a system component if it performs any of those
functions.
Non-Essential Software or Hardware Components
● Software or hardware components that perform the following functions do not have to be
identified as part of the DAHS and therefore do not need component definitions 1:
-- Calculation of RATA results;
-- Calculation of flow-to-load results (that are merged with the final quarterly report); or
-- Recording of operating parameters (that are merged with the final quarterly report),
e.g., unit load.
Rotating Fuel Flowmeters
When fuel flowmeters are rotated among different units to facilitate the removal of meters for
accuracy testing (e.g., three fuel flowmeters rotated between two units), submit a new
MONITORING SYSTEM COMPONENT DATA record each time that a fuel flowmeter is being placed
into service, and update the end date and hour of the MONITORING SYSTEM COMPONENT DATA
record for the fuel flowmeter that is being removed. Use the reinstallation date and hour in the
FUEL FLOWMETER ACCURACY DATA record as the begin date and hour in the new MONITORING
SYSTEM COMPONENT DATA record, and use the hour prior to the reinstallation date and hour as the
end date and hour in the MONITORING SYSTEM COMPONENT DATA record for the fuel flowmeter
that is being removed. If the fuel flowmeter that is being placed into service had previously been
installed, you may report its previously assigned component ID in the MONITORING SYSTEM
COMPONENT DATA record or you may assign a new component ID.
The rotation of dilution probes should be reported in the same manner as fuel flowmeters.

1

While these components do not have to be identified in the monitoring plan, identify them in the data flow
diagram under § 75.53(c)(5)(iii) and/or the quality assurance plan under Appendix B to Part 75.

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7.0 Component Data

Manufacturer and Serial Number Data for DAHS Components
● Use an abbreviation that clearly identifies the utility or operating company responsible
for the software development if software has been developed in-house. Use the same
abbreviation or name in the Manufacturer field for all units and sources using the
software.
● Serial numbers are optional for DAHS software components and billing fuel flowmeters.
If choosing to assign one, it must be unique to the software installation.
Time-Share CEMS on Single Unit
When using a "time-share" CEMS configuration to monitor emissions from both the main stack
and bypass stack for a combined cycle combustion unit using a single monitoring location,
define separate systems with unique Monitoring System IDs for each effluent point, and define
separate component records with unique Component IDs for each system. Defining separate
components for each system will allow for the tracking of component specific tests (e.g.,
linearity, seven day cal, online offline cal, and cycle time) where the test cannot be otherwise
uniquely identified. (This is a distinct change from the previous EDR format, where it was
acceptable to include the same component in both systems, since the Monitoring System ID used
to be included in the test record.) If the same component was previously reported in both
systems, EPA recommends that affected units define new component records only for the system
that represents the monitoring of the bypass stack, so as to minimize the amount of data that
would need to be resubmitted. The most recent component specific QA test data (previously
submitted under the old format) will need to be resubmitted under the new Component IDs.

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7.1 Analyzer Range Data

June 17, 2009

7.1 ANALYZER RANGE DATA
Figure 14
ANALYZER RANGE DATA XML Elements

Description of Data
Submit an ANALYZER RANGE DATA record for each gas analyzer component (NOx, SO2, CO2,
and O2) identified in a COMPONENT DATA record of the monitoring plan. This record specifies
for each component whether that component is a high scale, low scale, or autoranging
component, and whether it is a dual range analyzer.
Dependencies for ANALYZER RANGE DATA
The ANALYZER RANGE DATA record is dependent on the COMPONENT DATA record.
No other records are dependent upon the ANALYZER RANGE DATA record.
ANALYZER RANGE DATA Elements
Instructions for completing each element of the ANALYZER RANGE DATA section are provided
below:
Analyzer Range Code
Element Name: AnalyzerRangeCode
Report the code specifying the range by using the appropriate uppercase code as shown in Table
17. If using a default high range value for SO2 or NOx, the correct range code for the analyzer is
L.

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7.1 Analyzer Range Data

Table 17
Analyzer Range Codes and Descriptions
Code

Description

H

High Range

L

Low Range

A

Auto Ranging

Dual Range Indicator
Element Name: DualRangeIndicator
Report a Dual Range Indicator code equal to "1" whenever a single analyzer is used to satisfy a
dual range monitoring requirement. There are two possible ways to represent this in the
component data:
● As two separate components in the monitoring plan (i.e., when the Analyzer Range Code
is reported as "H" for the analyzer under one component ID and as "L" for the same
analyzer under another unique component ID); or
● As a single auto-ranging component in the monitoring plan (i.e., Analyzer Range Code
equal to "A").
Note that reporting dual range analyzers as a single auto-ranging component is recommended.
If more than one analyzer is used to satisfy a dual range monitoring requirement (i.e., when two
separate analyzers are used, one for the low-range and another for the high-range), report each
analyzer component separately in the monitoring plan and report "0" as the Dual Range
Indicator.
Also report "0" if the component represents a single range analyzer that is not part of a dual
range monitoring configuration.
Begin Date
Element Name: BeginDate
Report the date on which the range information reported in this record became effective. In most
cases, this date will be the same as the earliest begin date in the MONITOR SYSTEM COMPONENT
DATA record. However, if the analyzer range changes (e.g., from a single scale to dual range), be
sure to put the proper End Date and End Hour in the existing ANALYZER RANGE DATA record and
enter another ANALYZER RANGE DATA record for the new range code using the appropriate Begin
Date and Hour.
Begin Hour
Element Name: BeginHour
Report the hour during which the range information reported in this record became effective.
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7.1 Analyzer Range Data

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End Date
Element Name: EndDate
Report the last date on which the range information reported in this record was effective. This
value should be left blank for active records.
End Hour
Element Name: EndHour
Report the last hour in which the range information reported in this record was effective. This
value should be left blank for active records.

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7.2 Calibration Standard Data

June 17, 2009

7.2 CALIBRATION STANDARD DATA
Figure 15
Calibration Standard Data XML Elements

Description of Data
Submit a CALIBRATION STANDARD DATA record for components that use a calibration gas
standard for daily calibration. This includes gas analyzers for NOx, SO2, CO2, and O2. All gas
calibration standard records should indicate the standard used for the upscale check, not the zerolevel check. For dual range analyzers that report under a single Component ID, indicate the
standard used for the upscale check on the normal range of the component.
This record is optional and EPA recommends not submitting this record at this time.
Dependencies for CALIBRATION STANDARD DATA
The CALIBRATION STANDARD DATA record is dependent on the COMPONENT DATA record.
No other records are dependent upon the CALIBRATION STANDARD DATA record.
CALIBRATION STANDARD DATA Elements
Instructions for completing each element of the CALIBRATION STANDARD DATA record are
provided below:

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7.2 Calibration Standard Data

Calibration Standard Code
Element Name: CalibrationStandardCode
Report the appropriate code from Table 18 describing the type of calibration standard used to
conduct daily calibration error tests:

Table 18
Calibration Standard Codes and Descriptions

Code

Component
Type

Description

SBP

Single Blend Protocol (consisting of a single certified
constituent per the EPA Protocol such as SO2 in N2)

SO2, NOx, CO2,
and O2

SIA

Scrubbed Instrument Air (see Zero Air Material definition
§72.2)

O2

BBP

Basic Blend Protocol (an EPA Protocol gas standard
consisting of multiple certified constituents, none of which
is CO2)

SO2, and NOx

MBP

Multi-Blend Protocol (consisting of multiple certified
constituents, one of which is CO2)

SO2, NOx, and
CO2

SRM

Standard Reference Material (see §72.2)

All

PRM

SRM-Equivalent Compressed Gas Primary Reference
Material (see §72.2)

All

NTRM

NIST Traceable Reference Material (see §72.2)

All

RGM

Research Gas Mixture (see §72.2)

All

GMIS

Gas Manufacturer's Intermediate Standard (see §72.2)

All

ZAM

Zero Air Material (see §72.2)

O2

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7.2 Calibration Standard Data

June 17, 2009

Calibration Source Code
Element Name: CalibrationSourceCode
Report the appropriate code from Table 19 describing the source of the calibration standard used
to conduct daily calibration error tests:

Table 19
Calibration Source Codes and Descriptions
Code

Description

Calibration Standard Code

CYL

Certified Cylinder Gas Standard

All

SIA

Scrubbed Instrument Air. This code is
only appropriate for the Calibration
Standard Codes of "ZAM" and "SIA"

O2

Begin Date
Element Name: BeginDate
Report the date on which the calibration standard information reported in this record became
effective (i.e., became the standard used for daily calibrations of this component). If the
calibration standard changes, be sure to put the proper End Date and End Hour in the existing
CALIBRATION STANDARD DATA record and enter another CALIBRATION STANDARD DATA record
for the new standard using the appropriate Begin Date and Hour.
Begin Hour
Element Name: BeginHour
Report the hour during which the calibration standard information reported in this record became
effective.
End Date
Element Name: EndDate
Report the last date on which the calibration standard information reported in this record was
effective. This value should be left blank for active records.
End Hour
Element Name: EndHour
Report the last hour in which the calibration standard information reported in this record was
effective. This value should be left blank for active records.

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8.0 Monitoring System Data

June 17, 2009

8.0 MONITORING SYSTEM DATA
Figure 16
MONITORING SYSTEM DATA XML Elements

Description of Data
Submit a MONITORING SYSTEM DATA record to define each monitoring system that is installed
(or will be installed) at each monitoring location in the monitoring plan. For CEMS
methodologies, a monitoring system is any combination of analytical components, sensors, and
data software components for which a relative accuracy test is required (e.g., SO2
concentration system, flow rate system, NOx diluent system, NOx concentration system, O2
concentration system, CO2 concentration system, or moisture system). For monitoring
methodologies based on fuel flowmetering, a monitoring system consists of the fuel flowmeter
component(s) and the software component(s) needed to calculate and report hourly fuel flow
for a unit or common pipe for a particular fuel. See the "Specific Considerations" section
below for more detailed information about system types.
Information describing the monitoring system's individual components is not needed for this
record. The relationship between COMPONENT DATA and MONITORING SYSTEM DATA is
defined in the MONITORING SYSTEM COMPONENT DATA record.

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8.0 Monitoring System Data

Dependencies for MONITORING SYSTEM DATA
The MONITORING SYSTEM DATA record is dependent on the UNIT DATA record or the STACK
PIPE DATA record.
The following records are dependent upon the MONITORING SYSTEM DATA record:
● MONITORING SYSTEM COMPONENT DATA
● MONITORING SYSTEM FUEL FLOW DATA
MONITORING SYSTEM DATA Elements
Instructions for completing each element of the MONITORING SYSTEM DATA section are
provided below:
Monitoring System ID
Element Name: MonitoringSystemID
Assign unique three-character alphanumeric IDs to each monitoring system at a stack, pipe, or
unit. Do not repeat a system ID for a given stack, pipe, or unit, and do not re-use the ID
number of a system that has been permanently removed from service. However, the same
system numbering scheme may be used for different units, stacks, or pipes at the same facility.
System Type Code
Element Name: SystemTypeCode
Report the code that indicates the type of system by using the appropriate uppercase codes as
shown in Table 20:

Table 20
System Type Codes and Descriptions
Code

Description

CO2

CO2 Concentration System

FLOW

Stack Flow System

GAS

Gas Fuel Flow System

H2O

Moisture System that uses wet and dry
O2 analyzers

H2OM

Moisture System that uses a
continuous moisture sensor

H2OT

Moisture System that uses a
temperature sensor and a table of
lookup values
(cont.)

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8.0 Monitoring System Data

June 17, 2009

Table 20
System Type Codes and Descriptions
(cont.)
Code

Description

LTGS

Long Term Gas Fuel Flow System
(LME)

LTOL

Long Term Oil Fuel Flow System
(LME)

NOX

NOx Emission Rate System

NOXE

Appendix E NOx System

NOXC

NOx Concentration System

NOXP

NOx Emission Rate PEMS System

O2

O2 Concentration System

OILV

Volumetric Oil Fuel Flow System

OILM

Mass of Oil Fuel Flow System

OP

Opacity (ARP only)

PM

Particulate Matter Monitoring System

SO2

SO2 Concentration System

System Designation Code
Element Name: SystemDesignationCode
Report one of the following uppercase codes indicating the designation of the monitoring
system.

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8.0 Monitoring System Data

Table 21
System Designation Code and Descriptions
Code

Description

P

Primary.

PB

Primary Bypass. A primary bypass
(PB) describes a monitoring system
located on a bypass stack before a heat
recovery steam generator (HRSG).1

RB

Redundant Backup. A redundant
backup (RB) monitoring system is
operated and maintained by meeting
all of the same program QA/QC
requirements as a primary system.

B

Non-Redundant Backup. A nonredundant backup system (B) is a
"cold" backup or portable monitoring
system, having its own probe, sample
interface, and analytical components.

DB

Data Backup. A data backup system is
comprised of the analytical
components contained in the primary
monitoring system (or in a redundant
backup system), but includes a backup
DAHS component.

RM

Reference Method Backup. A
reference method (RM) monitoring
system is a monitoring system that is
operated as a reference method
pursuant to the requirements of
Appendix A to Part 60.

CI2

Certified Monitoring System at the
Inlet to an Emission Control Device.

1

Use code "P" for the monitoring system located on the main HRSG stack.

2

Use code "CI" only for units with add-on SO2 or NOx emission controls. Specifically, the use of a "CI"
monitoring system is limited to the following circumstances:
● If the unit has an exhaust configuration consisting of a monitored main stack and an unmonitored
bypass stack, and you elect to report SO2 data from a certified monitoring system located at the
control device inlet (in lieu of reporting maximum potential concentration) during hours in which
the flue gases are routed through the bypass stack; or
● If the outlet SO2 or NOx monitor is unavailable and proper operation of the add-on emission
controls is not verified, and you elect to report data from a certified SO2 or NOx monitor at the
control device inlet in lieu of reporting MPC or MER values. However, note that for the purposes
of reporting NOx emission rate, this option may only be used if the inlet NOx monitor is paired with
a diluent monitor and represented as a NOx-diluent monitoring system in the Component record.

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8.0 Monitoring System Data

June 17, 2009

Fuel Code
Element Name: FuelCode
For Appendix D fuel flowmeter systems and Appendix E NOx systems, report the type of fuel
measured by the system by using the appropriate uppercase codes as shown in Table 22. For
all other systems, report the Fuel Code as "NFS" (Non Fuel-Specific).

Table 22
Fuel Codes and Descriptions
Code

Description

BFG

Blast Furnace Gas

BUT

Butane Gas

CDG

Coal Derived Gas

COG

Coke Oven Gas

DGG

Digester Gas

DSL

Diesel Oil

LFG

Landfill Gas

LPG

Liquefied Petroleum Gas (if measured
as a gas)

MIX

Mixture of oil/gas fuel types (for
NOXE system for co-fired curve
only)

NFS

Non-Fuel-Specific for CEM
(including H2O) and Opacity Systems

NNG

Natural Gas

OGS

Other Gas

OIL

Residual Oil

OOL

Other Oil

PDG

Producer Gas

PNG

Pipeline Natural Gas (as defined in
§72.2)

PRG

Process Gas

PRP

Propane Gas

RFG

Refinery Gas

SRG

Unrefined Sour Gas

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8.0 Monitoring System Data

Begin Date
Element Name: BeginDate
Report the date on which the system became responsible for reporting emissions data. Under
most circumstances, this date should be the actual date when the system first reported
emissions data. However, if this is a primary monitoring system associated with the use of a
new methodology, this date should be the same as the BeginDate of the associated Monitor
Method record.
This date may be later than the dates of any initial certification tests performed on the system
or related components.
Begin Hour
Element Name: BeginHour
Report the hour on which the system became responsible for reporting emissions data.
End Date
Element Name: EndDate
Report the date the system was last used if a system is retired or permanently deactivated. Do
not submit emissions data using this monitoring system ID after this date. This value should be
left blank for active records.
End Hour
Element Name: EndHour
If the system is retired or permanently deactivated, report the hour during which the system
was last used. Do not submit emissions data using this monitoring system ID after this time.
This value should be left blank for active records.
Specific Considerations
Characteristics of Monitoring Systems
● Monitoring systems are generally comprised of the actual, physical components that are
installed or will be installed for a unit, pipe, or stack where the measurement equipment
is installed. Each monitoring system either directly measures a specific emissions
parameter (for example, NOx emission rate) or provides a parameter necessary for
calculating emissions (for example, pollutant concentration, stack flow, moisture, or
mass oil flow). A monitoring system can include both hardware and software
components.
● CEM Systems must include the probe component in addition to the analyzer(s) and
DAHS software.

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8.0 Monitoring System Data

June 17, 2009

Types of Systems Which May Be Defined and Used
● CO2 or O2 System. A CO2 monitoring system may be used to: (1) measure percent
CO2 to determine CO2 mass emissions; or (2) determine hourly heat input rate (in
conjunction with a flow monitoring system). O2 monitoring systems are only used for
determining hourly heat input rate. A CO2 or O2 system is comprised of a CO2 or O2
analyzer and a DAHS software component. When using Equation F-14A or F-14B to
convert a measured O2 value to CO2 for purposes of determining hourly CO2 mass
emissions, define a CO2 monitoring system containing an O2 component and DAHS
software. A probe component must be added to the system when the sample
acquisition method of the CO2 or O2 System is either dilution (DIL), dilution in-stack
(DIN), dilution out-of-stack (DOU), dry extractive (EXT), or wet extractive (WXT).
● Flow Monitoring System. This monitoring system is used to measure stack flow rate in
standard cubic feet per hour (scfh). The flow rate is used to calculate heat input rate
and/or SO2, CO2, and/or NOx mass emissions. At a minimum, the system is comprised
of a flow monitor and DAHS software. For flow monitors, identify a single component
as representative of the control unit of the monitor. If the average of two or more flow
monitors will be used to determine the hourly flow value, identify each separate flow
monitor as a component in the flow monitoring system.
● Gas Fuel Flow System. This monitoring system measures gas flow rate in 100 standard
cubic feet per hour. Gas flow rate is used to calculate SO2 and CO2 mass emissions
and/or heat input rate. At a minimum, this system is comprised of a gas fuel flowmeter
and DAHS software.
● Moisture System. This system is used to measure hourly percent moisture for the
calculation of hourly heat input rate, NOx emission rate, NOx mass emissions, CO2
mass emissions, or SO2 mass emissions, if an hourly moisture adjustment is required
because component monitors use different moisture bases. A moisture system may be
comprised of a moisture sensor and DAHS software or one or more dry and wet basis
oxygen analyzers and DAHS software. One of these oxygen analyzers may also be a
component of the NOx-diluent system described below. For units with saturated gas
streams (e.g., following a wet scrubber, it is also possible to use a moisture system
comprised of a temperature sensor and a moisture look-up table. This type of system is
represented by a single DAHS software component (note that this is the same DAHS
component that is listed as a component of the other monitoring systems at the unit or
stack).
● Long Term Gas or Oil Fuel Flow System. These monitoring systems are for low mass
emissions (LME) units only. They measure fuel flow on a long term (non-hourly)
basis, for the purpose of quantifying unit heat input. The systems are comprised of
DAHS software components and, depending on the methodology selected, may also
include Appendix D or billing fuel flowmeters or other relevant components. These
systems are used in conjunction with default or unit-specific, fuel-specific emission
rates to determine SO2, NOx, and CO2 mass emissions for LME units (see
§75.19(c)(3)(ii)).

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8.0 Monitoring System Data

● NOx-Diluent System. This monitoring system is used to determine NOx emission rate in
lb/mmBtu. It is comprised of a NOx concentration monitor, a CO2 or O2 diluent
monitor, and DAHS software. A probe component must be added to the system when
the sample acquisition method of the NOx-Diluent System is either dilution (DIL),
dilution in-stack (DIN), dilution out-of-stack (DOU), dry extractive (EXT), or wet
extractive (WXT).
● Appendix E NOx System (NOXE). This monitoring system is used to determine NOx
emission rate in lb/mmBtu based on a NOx/heat input rate correlation curve derived
from emission testing. Each NOXE system represents a single correlation curve (either
for a single fuel or for a consistent mixture of fuels) and is comprised of the DAHS
software component. Appendix E systems are associated with a unit, not with multiple
or common stacks.
● NOx Concentration System. This monitoring system is used to determine NOx
concentration, and is used in conjunction with a separately certified flow monitoring
system to calculate NOx mass emission rate (lb/hr). It is comprised of a NOx
concentration monitor and DAHS software.
● NOx Predictive Emissions Monitoring System. This type of monitoring system must be
approved by petition under §75.66 and Subpart E of Part 75. It is used to determine
NOx emission rate for a gas or oil-fired turbine or boiler and is comprised only of a
DAHS software component (or components).
● Volumetric Oil Fuel Flow System. This monitoring system measures hourly volumetric
oil flow rate. Oil flow rate is used to calculate SO2 and CO2 mass emissions and/or
heat input rate. At a minimum, it is comprised of an oil fuel flowmeter and DAHS
software.
● Mass Oil Fuel Flow System. This monitoring system measures hourly mass of oil
combusted in pounds per hour. Oil flow rate is used to calculate SO2 or CO2 mass
emissions and/or heat input rate. At a minimum, it is comprised of an oil fuel
flowmeter and DAHS software.
● Opacity System. This monitoring system is used to determine the opacity of emissions.
It is comprised of a continuous opacity monitor (COM) and DAHS software.
● Particulate Matter Monitoring System. This monitoring system is used to continuously
monitor particulate emissions. Affected units with a particulate monitoring system are
exempt from opacity monitoring under Part 75.
● SO2 Concentration System. This monitoring system is used to measure SO2
concentration. It is used in conjunction with a flow monitoring system to determine
hourly SO2 mass emission rates in lb/hr. The system consists of an SO2 concentration
monitor and a DAHS software component. A probe component must be added to the
system when the sample acquisition method of the SO2 Concentration System is either
dilution (DIL), dilution in-stack (DIN), dilution out-of-stack (DOU), dry extractive
(EXT), or wet extractive (WXT).
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8.0 Monitoring System Data

June 17, 2009

OILM, OILV, and GAS Systems
● If different types of oil or gas are burned in one unit, define a separate oil or gas system
for each type of fuel combusted in the unit.
● Each oil or gas system must include at least one fuel flowmeter hardware component.
Each oil and gas system must also include a DAHS component to record and calculate
fuel flow and heat input and to perform missing data substitutions.
● The oil or gas system for the unit or common pipe must include all fuel flowmeters that
are necessary to determine net fuel flow for one type of fuel. For example, if net oil
flow is measured by using one flowmeter for the main fuel line to the unit and
subtracting the value measured by the flowmeter on the return fuel line, the system
must include both the main and return flowmeters as separate components of the same
system. If more than one pipe supplies the same type of fuel to a unit and separate fuel
flowmeters are installed on each of the pipes (e.g., for a combined cycle turbine with a
duct burner), all the flowmeters measuring that one fuel are considered separate
components of the same system.
Low Mass Emissions Units (LMEs)
● For low mass emissions units reporting under §75.19, do not define monitoring
systems, and do not report this record unless long term fuel flow monitoring systems
are used to measure fuel flow and heat input.
● For a group of oil or gas-fired LME units served by a common pipe (or supply tank),
define a LTOL or LTGS monitoring system for the pipe or tank. In both cases (i.e., for
common pipe or tank), the pipe or tank ID number must begin with a "CP" prefix (e.g.,
CP001). If two or more common pipes or tanks of different fuel types supply the same
group of LME units, define a separate LTOL or LTGS system for each pipe or tank. If
two or more pipes or tanks supply the same type of fuel to a group of LME units, define
a single LTOL or LTGS system.
MONITORING SYSTEM DATA UPDATES
If changes must be made to key data fields and/or a system must be redefined after that system
has been certified and used to report emissions, recertification testing may be required. If it is
necessary to make such changes and it is unclear what testing or other requirements may be
associated with that change, consult with EPA or the applicable state agency.

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8.1 Monitoring System Fuel Flow Data

June 17, 2009

8.1 MONITORING SYSTEM FUEL FLOW DATA
Figure 17
MONITORING SYSTEM FUEL FLOW DATA XML Elements

Description of Data
The MONITORING SYSTEM FUEL FLOW DATA record provides the maximum fuel flow rate for the
system for use in missing data substitution routines. Report one MONITORING SYSTEM FUEL
FLOW DATA record for each GAS, OILV, OILM, LTOL, or LTGS system defined in
MONITORING SYSTEM DATA.
Dependencies for MONITORING SYSTEM FUEL FLOW DATA
The MONITORING SYSTEM FUEL FLOW DATA record is dependent on the SYSTEM DATA record.
No other records are dependent upon the MONITORING SYSTEM FUEL FLOW DATA record.
MONITORING SYSTEM FUEL FLOW DATA Elements
Instructions for completing each element of the MONITORING SYSTEM FUEL FLOW DATA section
are provided below:
Maximum Fuel Flow Rate
Element Name: MaximumFuelFlowRate
Report the maximum fuel flow rate for the system. This maximum fuel flow rate is needed for
missing data purposes. If the system is comprised of main supply and return components,
calculate the net system maximum fuel flow rate assuming that the main supply is operating at
the maximum potential fuel flow rate, as defined in Section 2.4.2.1 of Appendix D, and that the
return flow rate is zero. For a combined cycle turbine with a duct burner, if the fuel flowmeter
system includes both the turbine and duct burner flowmeter components, report the sum of the
maximum potential fuel flow rates of the component flowmeters.
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8.1 Monitoring System Fuel Flow Data

System Fuel Flow UOM Code
Element Name: SystemFuelFlowUOMCode
Report the units of measure for fuel flow rate provided by the system using the appropriate
uppercase codes as shown in Table 23:

Table 23
Units of Measure for Maximum Fuel Flow Rate Codes and Descriptions
Parameter
Volumetric Flow of Oil

Code

Description

SCFH

Standard cubic feet per hour

GALHR

Gallons per hour

BBLHR

Barrels per hour

M3HR

Cubic meters per hour

Mass of Oil

LBHR

Pounds per hour

Gas Flow

HSCF

100 standard cubic feet per hour

Maximum Fuel Flow Rate Source Code
Element Name: MaximumFuelFlowRateSourceCode
Report either "URV" to indicate that the maximum rate is based on the upper range value, or
"UMX" to indicate that the maximum rate is determined by the rate at which the unit can
combust fuel.
Begin Date
Element Name: BeginDate
Report the date on which the monitoring system fuel flow data became effective. This will
usually be the same as the begin date for the monitoring system. If there was a change to the
maximum fuel flow rate, in the record for the new information report the date that the change
took place.
Begin Hour
Element Name: BeginHour
Report the hour in which the monitoring system fuel flow data became effective.
End Date
Element Name: EndDate
If applicable, report the last date on which the fuel flow record was in effect. This value should
be left blank for active records.

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End Hour
Element Name: EndHour
If applicable, report the last hour in which the fuel flow record was in effect. This value should
be left blank for active records.

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8.2 Monitoring System Component Data

June 17, 2009

8.2 MONITORING SYSTEM COMPONENT DATA
Figure 18
MONITORING SYSTEM COMPONENT DATA XML Elements

Description of Data
This record links individual monitoring components to each monitoring system in which they
serve and defines the time frame for that relationship. Report a MONITORING SYSTEM
COMPONENT DATA record for each system-component relationship. See the descriptions for each
type of monitoring system in the instructions for the MONITORING SYSTEM DATA record for
general information about what components to include in each system.
Except for primary monitoring systems containing like-kind replacement ("LK") components, a
system should not contain any active components that are not in service when the system is being
used to monitor and report data. For example, do not include backup DAHS software as an
additional DAHS component of a primary system. If you have defined primary SO2 system 101,
consisting of a SO2 concentration monitor (component ID S01) and a DAHS software
installation (component ID D01), and you also have a second installation of that DAHS software,
you should define a separate Data Backup (DB) SO2 monitoring system.
Dependencies for MONITORING SYSTEM COMPONENT DATA
The MONITORING SYSTEM COMPONENT DATA record is dependent on the MONITORING SYSTEM
DATA record.
No other records are dependent upon the MONITORING SYSTEM COMPONENT DATA record.

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8.2 Monitoring System Component Data

MONITORING SYSTEM COMPONENT DATA Elements
Instructions for completing each element of the MONITORING SYSTEM COMPONENT DATA section
are provided below:
Component ID
Element Name: ComponentID
Report the three-character alphanumeric ID for the component.
Begin Date
Element Name: BeginDate
Report the date on which the component became an active part of the system. If this component
is an original part of the system, this date will be the same as the System Begin Date.
Begin Hour
Element Name: BeginHour
Report the hour in which the component became an active part of the system.
End Date
Element Name: EndDate
Report the last date that the component was an active part of the system. This value should be
left blank for active system-component relationships.
End Hour
Element Name: EndHour
Report the last hour that the component was an active part of the system. This value should be
left blank for active system-component relationships.

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9.0 Monitoring Formula Data

June 17, 2009

9.0 MONITORING FORMULA DATA
Figure 19
MONITORING FORMULA DATA XML Elements

Description of Data
The MONITORING FORMULA DATA record is used to identify the formulas that will be used to
calculate required data from the monitoring systems defined in the MONITORING SYSTEM DATA
record. It is not necessary to define formulas referencing backup monitoring systems unless the
backup monitoring systems use different formulas than the primary system.
MONITORING FORMULA DATA are used for three primary purposes:
● To verify that the formulas selected are appropriate to the monitoring approach and
reflect a thorough understanding of emissions calculations and the use of appropriate
variables;
● To provide the basis for formula verification to ensure that the DAHS software calculates
emissions and selected values accurately; and
● To verify hourly calculations in quarterly reports.
Dependencies for MONITORING FORMULA DATA
The MONITORING FORMULA DATA record is dependent on the UNIT DATA record or the STACK
PIPE DATA record.
No other records are dependent upon the MONITORING FORMULA DATA record.

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9.0 Monitoring Formula Data

MONITORING FORMULA DATA Elements
Instructions for completing each element of the MONITORING FORMULA DATA section are
provided below:
Formula ID
Element Name: FormulaID
Assign a unique three-character Formula ID for each formula defined at a unit, stack, or pipe.
Assign unique formula IDs across all related units and stacks, if a facility includes a common
stack, pipe header, or multiple stack. Do not reuse formula IDs if changing component types
(e.g., from dry extractive to wet dilution systems) and therefore changing the type of formula in
use.
Parameter Code
Element Name: ParameterCode
Report the parameter representing the pollutant or parameter calculated by the formula by using
the appropriate uppercase codes as shown in Table 24.

Table 24
Parameter Codes and Descriptions
for Monitoring Formula
Code

Description

CO2

CO2 Hourly Mass Emission Rate
(tons/hr)

CO2C

CO2 Concentration (%CO2)

CO2M

CO2 Daily Mass (tons)

FC

F-Factor Carbon-Based

FD

F-Factor Dry-Basis

FGAS

Gas Hourly Flow Rate (hscf)

FLOW

Net Stack Gas Volumetric Flow Rate

FOIL

Net Oil Flow Rate to Unit/Pipe

FW

F-Factor Wet-Basis

H2O

Moisture (%H2O)

HI

Heat Input Rate (mmBtu/hr)

HIT

Heat Input Total (mmBtu)

NOX

NOx Hourly Mass Emission Rate
(lb/hr)
(cont.)

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9.0 Monitoring Formula Data

June 17, 2009

Table 24
Parameter Codes and Descriptions
for Monitoring Formula (cont.)
Code

Description

NOXR

NOx Emission Rate (lb/mmBtu)

OILM

Oil Mass Flow Rate (lb/hr)

SO2

SO2 Hourly Mass Emission Rate (lb/hr)

SO2R

SO2 Emission Rate (lb/mmBtu) When
Equation D-1h Is Used

Formula Code
Element Name: FormulaCode
Report the formula code of the formula that appears in the tables below and in 40 CFR Part 75,
Appendices D through G (or, if appropriate, in 40 CFR Part 60, Appendix A, Method 19) that is
applicable to the parameter and the types of monitoring components. EPA relies on the accuracy
of the formula code to verify hourly emissions calculations. Tables 25 through 36 provide
summaries of the primary formulas used to calculate SO2, NOx emissions, and CO2; moisture and
heat input rate using CEMS; and fuel flowmeter methodologies. For moisture monitoring
systems comprised of wet and dry oxygen analyzers, see Table 30, Equations F-31 and M-1K.
For net fuel flow and average stack flow formulas, see Table 37. All formula codes must be
entered exactly as they are presented in Tables 25 through 36. This includes the use of dashes
and capital letters.
For example, report "F-1" (from Table 27) if using the equation for converting measurements of
SO2 concentration and flow rate on a wet basis to SO2 in lb/hr. Report "F-5" (from Table 29) if
using the equation from Method 19, Appendix A, 40 CFR Part 60 for converting measurements
of NOx concentration and O2 diluent on a dry basis to NOx emission rate in lb/mmBtu. In the
second example, formula code "19-1" could have been used instead of "F-5," since Equation
19-1 in Method 19 is identical to Equation F-5 in Appendix F to Part 75.
For custom or non-standard intermediate equations that are not listed in Tables 25 – 36 below,
leave the Formula Code blank.

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9.0 Monitoring Formula Data

Table 25
F-Factor* Reference Table
Option 1: Fuel-Based Constants

Fuel
Coal

F-Factor
(dscf/
mmBtu)

Fc-Factor
(scf CO2/
mmBtu)

Fw-Factor
(wscf/mmBtu)

Anthracite

10,100

1,970

10,540

Bituminous

9,780

1,800

10,640

Sub-bituminous

9,820

1,840

------

Lignite

9,860

1,910

11,950

Petroleum Coke

9,830

1,850

------

Tire-Derived Fuel

10,260

1,800

------

Natural Gas

8,710

1,040

10,610

Propane

8,710

1,190

10,200

Butane

8,710

1,250

10,390

Oil

Oil

9,190

1,420

10,320

Waste

Municipal Solid Waste

9,570

1,820

------

Wood

Bark

9,600

1,920

------

Wood Residue

9,240

1,830

------

Gas

(cont.)

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9.0 Monitoring Formula Data

June 17, 2009

Table 25
F-Factor* Reference Table (cont.)
Option 2: Calculated F-Factors
Code

Parameter

F-7A

FD

F-7B

FC

19-14

FW

Formula
F=

3.64(%H) + 1.53(%C) + 0.57(%S) + 0.14(%N) - 0.46(%O)
x 10 6
GCV

321 x 103 x (%C)
Fc=
GCV

Fw=

F-8**

Where:

5.57(%H) + 1.53(%C) + 0.57(%S) + 0.14(%N) - 0.46(%O) + 0.21(% H 2 O)

FD,
FC, or
FW

GCV w

n

F = ∑ X i Fi
i=1

n

F c = ∑ X i ( F c )i
i=1

n

F w = ∑ X i ( F w )i

x 106

F

= Dry-basis F-factor
(dscf/mmBtu)
= Carbon-based F-factor (scf
Fc
CO2/mmBtu)
= Wet-basis F-factor
Fw
(wscf/mmBtu)
%H,%N, = Content of element, percent
%S, %C, by weight, as determined
%O,%H2O on the same basis as the
gross calorific value by
ultimate analysis of the fuel
combusted using ASTM
D3176-89 for solid fuels,
ASTM D1945-91 or ASTM
D1946-90 for gaseous
fuels, as applicable
GCV
= Gross calorific value
(Btu/lb) of fuel combusted
determined by ASTM
D2015-91 for solid and
liquid fuels or ASTM
D1826-88 for gaseous
fuels, as applicable
GCVw = Calorific value (Btu/lb) of
fuel combusted, wet basis
F

= Dry-basis F-factor
(dscf/mmBtu)
= Carbon-based F-factor (scf
Fc
CO2/mmBtu)
n
= Number of fuels being
combusted
Fi,(Fc)i, = Applicable F, Fc, or Fw
factor for each fuel type
(Fw)i
= Fraction of total heat input
Xi
derived from each type of
fossil fuel

i=1

* F-factor is the ratio of the gas volume of all the products of combustion (less water) to the heat content of the
fuel. Fc-factor is the ratio of the gas volume of the CO2 generated to the heat content of the fuel (see Part 75,
Appendix F, Section 3.3). Fw-factor is the ratio of the quantity of wet effluent gas generated by the combustion
to the heat content of the fuel including free water in the fuel.
** This formula should be used for affected units that combust combinations of fossil fuels or fossil fuels and wood
residue. For affected units that combust a combination of fossil and non-fossil fuels, the selected F-factor must
receive state or EPA approval.

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9.0 Monitoring Formula Data

Table 26
SO2 Formula References

Usage

Moisture Basis*

SO2 CEMS

Appropriate Hourly Formulas (Part
75, Appendices D&F)

WET

F-1

DRY

F-2

Default SO2 emission rate when low
sulfur fuels are burned (e.g., natural
gas)

F-23 (and D-1H)

Oil Fuel Flowmeter

D-2

Gas Fuel Flowmeter

D-4 or D-5 (and D-1H)

Overall values for multiple fuel
flowmeter systems

D-12

* For sample acquisition method (SAM) codes IS, ISP, ISC, DIN, DOU, DIL, and WXT = wet extractive;
for EXT = dry extractive, located under component. Exceptions are possible. Check with vendor if
uncertain.

Table 27
SO2 Emission Formulas
Code Parameters
F-1

SO2

F-2

SO2

Formula

E h = K x C h x Qh

100 - % H 2 O
E h = K x C hp x Q hs x
100

D-1H

SO2R

ER =

2.0
S
x 106 x total
7000
GCV

Where:
Eh
K
Chp

=
=
=

Ch

=

Qh and =
Qhs
%H2O =
ER

=

Stotal

=

GCV

=

2.0
7000

=
=

106

=

Hourly SO2 mass emission rate (lb/hr)
1.660 x 10-7 for SO2 ((lb/scf)/ppm)
Hourly average SO2 concentration (ppm
(dry))
Hourly average SO2 concentration (ppm
(stack moisture basis))
Hourly average volumetric flow rate
(scfh (stack moisture basis))
Hourly average stack moisture content
(percent by volume)
Default SO2 emission rate for natural
gas (or "other" gaseous fuel)
combustion (lb/mmBtu)
Total sulfur content of gaseous fuel
(grains/100 scf)
Gross calorific value of the gas
(Btu/100 scf)
Ratio of lb SO2/lb S
Conversion of grains/100 scf to lb/
100 scf
Conversion of Btu to mmBtu
(cont.)

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9.0 Monitoring Formula Data

June 17, 2009

Table 27
SO2 Emission Formulas (cont.)
Code Parameters
D-2

Formula

SO2

SO2rate-oil =

SO 2rate-oil = 2.0 x OILrate x

D-4

Where:

% S oil
100.0

SO2

OILrate

=

%Soil

=

2.0

=

SO2rate

=

GASrate =

SO 2rate = (2.0 / 7000) x GAS rate x S gas

D-5

SO2

SO 2rate = ER x HI rate

F-23

SO2

E h = ER x HI

D-12*

SO2

∑

SO 2rate =

SO 2 rate-i t i

Sgas

=

2.0
7000

=
=

SO2rate

=

ER

=

HIrate

=

Eh
ER

=
=

HI

=

SO2rate

=

SO2rate-i =

all - fuels

tu

ti

=

tu

=

Hourly mass emission rate of SO2
emitted from combustion of oil (lb/hr)
Mass rate of oil consumed per hour
during combustion (lb/hr)
Percent sulfur by weight measured in
oil sample
Ratio of lb SO2 to lb S
Hourly mass rate of SO2 from
combustion of gaseous fuel (lb/hr)
Hourly metered flow rate of gaseous
fuel combusted (100 scf/hr)
Sulfur content of gaseous fuel
(grains/100 scf)
Ratio of lb SO2/lb S
Conversion of grains/100 scf to lb/
100 scf
Hourly mass emission rate of SO2 from
combustion of gaseous fuel (lb/hr)
SO2 emission rate from Appendix D,
Section 2.3.1.1 or Appendix D, Section
2.3.2.1.1 to Part 75 (lb/mmBtu)
Hourly heat input rate of a gaseous fuel,
calculated using procedures in
Appendix D, Section 3.4.1 to Part 75
(mmBtu/hr)
Hourly SO2 mass emission rate (lb/hr)
Applicable SO2 default emission rate
from Appendix D, Section 2.3.1.1, or
Appendix D, Section 2.3.2.1.1 to Part
75 (lb/mmBtu)
Hourly heat input rate, determined
using a certified flow monitor and
diluent monitor, according to Appendix
F, Section 5.2 (mmBtu/hr)
Hourly mass emission rate of SO2 from
combustion of all fuels (lb/hr)
SO2 mass emission rate for each type of
gas or oil fuel combusted during the
hour (lb/hr)
Time each gas or oil fuel was
combusted for the hour (fraction of an
hour)
Operating time of the unit

* This equation is a modified form of Equation D-12 as described in Appendix D, Section 3.5.1, and must be used
when reporting in the XML format.

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9.0 Monitoring Formula Data

Table 28
NOx Emission Rate Formula Reference Table
Moisture Basis
Usage
NOx CEMS (CO2 Diluent)

NOx CEMS (O2 Diluent)

NOx

CO2

O2

Appropriate Hourly
Formulas

DRY

DRY

19-6

DRY

WET

19-9

WET

DRY

19-8

WET

WET

19-7 or F-6

DRY

DRY

19-1 or F-5

DRY

WET

19-5 or 19-5D

WET

DRY

19-4

WET

WET

19-2, 19-3, or 19-3D

Overall Value from Multiple
Appendix E Systems

Monitoring Plan Reporting Instructions -- Page 80

E-2

Environmental Protection Agency

9.0 Monitoring Formula Data

June 17, 2009

Table 29
NOx Emission Rate Formulas (lb/mmBtu)
Code

Parameter

19-1
(F-5)

NOXR

19-2

NOXR

19-3*

NOXR

19-3D*

NOXR

19-4*

NOXR

19-5*

NOXR

19-5D

NOXR

19-6

NOXR

19-7
(F-6)

NOXR

19-8*

NOXR

19-9*

NOXR

E-2

NOXR

Formula

E = K x Cd x F d x

Where:
Formulas should be multiplied by the
conversion factor "K" (if Cd or Cw is in ppm)

20.9
20.9 - % O 2d

20.9
E = K x Cw x F w x
20.9 (1 - B wa ) - % O 2w
E = K x Cw x F d x

E = K x Cw x F d x

E= K x

E=

20.9
 100 - % H 2 O 
20.9 x 
 - % O 2w
100


20.9
 100 - % H 2 O 
20.9 x 
 - % O 2def
100


 100 - % H 2 O 
x

100


( Cw x F d )
20.9
x
(100 - % H 2 O)÷100 (20.9 - % O 2d )

20.9 x K x C d x F d

 100 - % H 2 O 
20.9 - % O 2w ÷ 

100




E = K x Cd x F d x

20.9
20.9 - % O 2def

E = K x Cd x F c x

100
% CO 2d

E = K x Cw x Fc x

100
% CO 2w

E= K x

( Cw x Fc )
100
x
(100 - % H 2 O) ÷ 100 % CO 2d

100
 100 - % H 2 O 
E = K x Cd x 
x Fc x

100
% CO 2w


all fuels

∑(E

Eh =

f

x HI f t f )

f =1

HT

FROM
ppm NOx

TO MULTIPLY BY "K"
lb/scf
K = 1.194 X 10-7

E
Cd

= Emission rate (lb/mmBtu)
= Pollutant concentration (ppm, dry
basis)
= (Pollutant concentration ppm, wet
Cw
basis)
= Dry-basis F-factor (dscf/mmBtu)
Fd
= Carbon-based F-factor (scf
Fc
CO2/mmBtu)
= Wet-basis F-factor (wscf/mmBtu)
Fw
Bwa = Moisture fraction of ambient air
(default value 0.027)
%H2O = Moisture content of effluent gas
= Oxygen diluent concentration
O2d
(percent of effluent gas, dry basis)
O2w = Oxygen diluent concentration
(percent of effluent gas, wet basis)
O2def = Default diluent cap O2 value (14.0
percent for boilers, 19.0 percent
for combustion turbines)
CO2d = Carbon dioxide diluent
concentration (percent of effluent
gas, dry basis)
CO2w = Carbon dioxide diluent
concentration (percent of effluent
gas, wet basis)
= NOx emission rate for the unit for
Ef
a given fuel at heat input rate HIf,
lb/mmBtu
= Heat input rate for the hour for a
HIf
given fuel, during the fuel usage
time, as determined using
Equation F-19 or F-20 in Section
5.5 of Appendix F to this part,
mmBtu/hr
= Total heat input for all fuels for
HT
the hour from Equation E-1
= Fuel usage time for each fuel
tf
(rounded to the nearest fraction of
an hour (in equal increments that
can range from one hundredth to
one quarter of an hour, at the
option of the owner or operator))

* Note that [(100 - %H2O/100] may also represented as (1 - Bws), where Bws is the proportion by volume of water
vapor in the stack gas stream.
Environmental Protection Agency

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9.0 Monitoring Formula Data

Table 30
Moisture Formulas*
Code
F-31

Parameter

Formula

H2O

% H2O=
M-1K

H2O

% H2 O =

(O

2d

Where:

( O 2d - O 2 w )

%H2O =
O2d
=

x 100

O 2d

− O2 w )

O2 d

O2w

× 100

, as adjusted1

=

Percent moisture
Oxygen diluent concentration
(percent of effluent gas, dry
basis)
Oxygen diluent concentration
(percent of effluent gas, wet
basis)

* Please contact the EPA Clean Air Markets Division for the assigned code for other moisture formulas.
1

Using a K-factor or other mathematical algorithm, per Appendix A, Section 6.5.7(a).

Table 31
CO2 Formula Reference Table

Usage

Appropriate Formulas
(Part 75, Appendices F, G)

Moisture Basis

CO2 CEMS
(O2 Analyzer)

WET

F-14B and F-11

DRY

F-14A and F-2

CO2 CEM
(CO2 Analyzer)

WET

F-11

DRY

F-2

Fuel Sampling

G-1 (and possibly G-2, G-3, G-5, G-6 and
G-8)

Gas or Oil Flowmeter

G-4

Overall Value from Multiple
Flowmeter Systems

G-4A

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9.0 Monitoring Formula Data

June 17, 2009

Table 32
CO2 Concentration and Mass Emission Rate Formulas
Code Parameter
F-2

Formula

Where:

CO2

E h = K × Chp × Qhs ×

100 − % H 2 O
100

Eh
K

=
=

Chp

=

Qhs

=

%H2O =
F-11

CO2

E h = K × Ch × Qh

F-14A

CO2C

=

K

=

Ch

=

Qh

=

CO2d =

CO2 d

F-14B

Eh

F
Fc

Fc 20.9 − O2 d
= 100 ×
×
F
20.9

=
=

20.9 =
O2 d =

CO2C

CO2w =

CO2 w =


100 Fc 
 100 − % H 2 O 
×
×  20.9
 − O2W 


20.9 F 
100


F
Fc

=
=

20.9 =
O2W =
%H2O =

G-1

CO2M

WCO2 =

WCO2

( MW + MW ) × W
=
c

O2

2000 MWc

c

MWc =
MWO2 =
Wc =

Hourly CO2 mass emissions (tons/hr)
5.7 x 10-7 for CO2
((tons/scf)/percent CO2)
Hourly average, CO2 concentration
(percent CO2, dry basis)
Hourly average volumetric flow rate
(scfh, wet basis)
Hourly average stack moisture
content (percent by volume)
Hourly CO2 mass emission rate
(tons/hr)
5.7x10-7 for CO2
((tons/scf)/percent CO2)
Hourly average CO2 concentration
(percent CO2, wet basis)
Hourly average volumetric flow rate
(scfh, wet basis)
Hourly average CO2 concentration
(percent by volume, dry basis)
Dry-basis F-factor (dscf/mmBtu)
Carbon-based F-factor
(scf CO2/mmBtu)
Percentage of O2 in ambient air
Hourly average O2 concentration
(percent by volume, dry basis)
Hourly average CO2 concentration
(percent by volume, wet basis)
Dry-basis F-factor (dscf/mmBtu)
Carbon-based F-factor
(scf CO2/mmBtu)
Percentage of O2 in ambient air
Hourly average O2 concentration
(percent by volume, wet basis)
Moisture content of gas in the stack
(percent)
CO2 emitted from combustion
(tons/day)
Molecular weight of carbon (12.0)
Molecular weight of oxygen (32.0)
Carbon burned (lb/day) determined
using fuel sampling and analysis and
fuel feed rates*
(cont.

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Table 32
CO2 Concentration and Mass Emission Rate Formulas (cont.)
Code Parameter
G-2

Formula

CO2M

WNCO2 = WCO2 −

G-3

Where:

MWCO2  A%   C % 
×
 × WCOAL
 ×
 100   100 
MWc

CO2M

WNCO2 =.99 × WCO2

G-4

CO2

WNCO2 = Net CO2 mass emissions discharged
to the atmosphere (tons/day)
WCO2 = Daily CO2 mass emissions calculated
by Equation G-1 (tons/day)
MWCO2 = Molecular weight of carbon dioxide
(44.0)
MWc = Molecular weight of carbon (12.0)
A%
= Ash content of the coal sample
(percent by weight)
C%
= Carbon content of ash (percent by
weight)
WCOAL = Feed rate of coal from company
records (tons/day)
WNCO2 = Net CO2 mass emissions from the
combustion of coal discharged to the
atmosphere (tons/day)
.99
= Average fraction of coal converted
into CO2 upon combustion
WCO2 = Daily CO2 mass emissions from the
combustion of coal calculated by
Equation G-1 (tons/day)
WCO2
Fc

WCO2 =

Fc × H × U f × MWCO2
2000
H
Uf
MWCO2

G-4A

CO2

∑ CO2

CO2 unit =

all − fuels

t unit

fuel

t fuel

= CO2 emitted from combustion
(tons/hr)
= Carbon-based F-factor, 1,040
scf/mmBtu for natural gas; 1,420
scf/mmBtu for crude, residual, or
distillate oil and calculated according
to the procedures in Section 3.3.5 of
Appendix F to Part 75 for other
gaseous fuels
= Hourly heat input rate (mmBtu/hr)
= 1/385 scf CO2/lb-mole at 14.7 psi and
68F
= Molecular weight of carbon dioxide
(44.0)

CO2unit = Unit CO2 mass emission rate
(tons/hr)
CO2fuel = CO2 mass emission rate calculated
using Equation G-4 for a single fuel
(tons/hr)
= Fuel usage time
tfuel
tunit
= Unit operating time
(cont.)

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9.0 Monitoring Formula Data

June 17, 2009

Table 32
CO2 Concentration and Mass Emission Rate Formulas (cont.)
Code Parameter
G-5

Formula

CO2M

SE CO2 = WCaCO3 × Fu ×

G-6

MWCO2
MWCaCO3

CO2M

SE CO2 = Fu

G-8

Where:

WSO2 MWCO2
2000 MWSO2

CO2M

SECO2 = CO2 emitted from sorbent (tons/day)
WCaCO3 = Calcium carbonate used (tons/day)
= 1.00, the calcium to sulfur
Fu
stoichiometric ratio
MWCO2 = Molecular weight of carbon dioxide
(44.0)
MWCaCO3= Molecular weight of calcium
carbonate (100.0)
SECO2 = CO2 emitted from sorbent (tons/day)
MWCO2 = Molecular weight of carbon dioxide
(44.0)
MWSO2 = Molecular weight of sulfur dioxide
(64.0)
WSO2 = Sulfur dioxide removed (lb/day)
based on applicable procedures,
methods, and equations in § 75.15
= 1.00, the calcium to sulfur
Fu
stoichiometric ratio
Wt

Wt = WCO2 + SECO2

WCO2
SECO2

= Estimated total CO2 mass emissions
(tons/day)
= CO2 emitted from fuel combustion
(tons/day)
= CO2 emitted from sorbent (tons/day)

* See Appendix G, sections 2.1.1 through 2.1.3

Table 33
Heat Input Formula Reference Table

Usage
CEMS (O2 Analyzer)

CEMS (CO2 Analyzer)

Moisture Basis*

Appropriate Hourly Formulas (Part
75, Appendices D and F)

WET

F-17

DRY

F-18

WET

F-15

DRY

F-16

Gas Fuel Flowmeter System

D-6 (F-20)

Oil Fuel Flowmeter System
(Mass)

D-8 (F-19)
(cont.)

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Table 33
Heat Input Formula Reference Table (cont.)

Usage

Moisture Basis*

Appropriate Hourly Formulas (Part
75, Appendices D&F)

Oil Fuel Flowmeter System
(Volumetric)

D-3 and D-8 (F-19) or F-19V

Overall Value from Multiple Fuel
Flowmeter Systems

D-15A

Apportioned Value from Common
Stack or Common Pipe

F-21A, F-21B, or F-21

Summed Value from Multiple
Stacks

F-21C

Summed Value from Unit

F-25

* For sample acquisition method (SAM) codes IS, ISP, ISC, DIN, DOU, DIL, and WXT = wet extractive; for
EXT = dry extractive, locate under the component. Exceptions are possible. Check with vendor if
uncertain.

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9.0 Monitoring Formula Data

June 17, 2009

Table 34
Heat Input Formulas
Code

Parameter

D-15A

HI

Formula

∑

HI rate- hr =

F-15

HI

F-16

HI

F-17

HI

F-18

HI

Where:
HIrate-hr = Heat input rate from all fuels
combusted during the hour
(mmBtu/hr)
HIrate-i = Heat input rate for each type of
gas or oil combusted during the
hour (mmBtu/hr)
= Time each gas or oil fuel was
ti
combusted for the hour (fuel
usage time) (fraction of an
hour)
= Operating time of the unit
tu

HI rate-i t i

all - fuels

HI = Q w x

tu

1
Fc

x

HI

% CO 2w
100

 100 - % H 2 O   % CO 2d 
HI = Q h x 


 100 F c   100 
HI = QW x

1 [(20.9/100)(100 - % H 2 O) - % O 2w ]
x
F
20.9

 (100 - % H 2 O)   (20.9 - % O 2d ) 
HI = Q w x 
 

100F
20.9


D-3

OILM

OILrate = V oil - rate x Doil

D-8**
(F-19V)

HI

HI rate-oil = OILrate x

GCV oil
6
10

= Hourly heat input rate
(mmBtu/hr)
Qw, Qh = Hourly average volumetric
flow rate (scfh, wet basis)
= Carbon-based F-factor
Fc
(scf/mmBtu)
F
= Dry basis F-factor
(dscf/mmBtu)
%CO2w = Hourly concentration of CO2
(percent CO2, wet basis)
%CO2d = Hourly concentration of CO2
(percent CO2 , dry basis)
%O2w = Hourly concentration of O2
(percent O2, wet basis)
%O2d = Hourly concentration of O2
(percent O2, dry basis)
%H2O = Hourly average moisture of gas
in the stack (percent)
OILrate = Mass rate of oil consumed per hr
(lb/hr)
Voil-rate = Volume rate of oil consumed
per hr, measured (scf/hr, gal/hr,
barrels/hr, or m3/hr)
= Density of oil, measured
Doil
(lb/scf, lb/gal, lb/barrel, or
lb/m3)
HIrate-oil = Hourly heat input rate from
combustion of oil (mmBtu/hr)
OILrate = Rate of oil consumed (lb/hr for
Equation D-8 or gal/hr for
Equation F-19V)
GCVoil = Gross calorific value of oil
(Btu/lb for Equation D-8 or
Btu/gal for Equation F-19V)
106
= Conversion of Btu to mmBtu
(cont.)

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9.0 Monitoring Formula Data

Table 34
Heat Input Formulas (cont.)
Code

Parameter

F-19

HI

Formula

Where:
HIo

HI o = M o x

GCV o
6
10

Mo
GCVo
106

D-6

HI

HI rate- gas =
F-20

HI

HI g =

GAS rate x GCV gas
6
10
( Q g x GCV g )
10

6

= Hourly heat input rate from
combustion of oil (mmBtu/hr)
= Mass rate of oil consumed per
hour (lb/hr)
= Gross calorific value of oil
(Btu/lb)
= Conversion of Btu to mmBtu

HIrate-gas,= Hourly heat input rate from
HIg
combustion of gaseous fuel
(mmBtu/hr)
GASrate, = Average volumetric flow
rate of fuel (100 scfh)
Qg
GCVgas, = Gross calorific value of
gaseous fuel (Btu/100 scf)
GCVg
= Conversion of Btu to mmBtu
106

** For units required to monitor NOx mass emissions but not SO2 mass emissions, if there is a volumetric oil
flowmeter, it is possible to use Equation D-8 on a volumetric basis, rather than a mass basis. If using this option,
represent the Equation as F-19V in the monitoring plan.

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9.0 Monitoring Formula Data

June 17, 2009

Table 35
Apportionment and Summation Formulas
Code

Parameter

F-21A

HI

Formula

Where:




 t CS  MW i t i 

HI i = HI CS    n

 ti  
 ∑ MW i t i 

 i=1

F-21B

HI




 t CS  SF i t i 

HI i = HI CS    n


t
 i 
 ∑ SF i t i 

 i=1

F-21C

HI

HIi

=

HICS

=

MWi
ti

=
=

tCS

=

n

=

i

=

HIi

=

HICS

=

n
SFi
ti

=
=
=

tCS

=

n

=

i

=

HIUnit =
n

∑ HI
HI Unit =

s

s=1

tUnit

ts

HIs

=

tUnit
ts

=
=

s

=

n

=

Heat input rate for a unit
(mmBtu/hr)
Heat input rate at the common
stack or pipe (mmBtu/hr)
Gross electrical output (MWe)
Operating time at a particular
unit
Operating time at common
stack or pipe
Total number of units using the
common stack or pipe
Designation of a particular unit
Heat input rate for a unit
(mmBtu/hr)
Heat input rate at the common
stack or pipe (mmBtu/hr)
Number of stacks or pipes
Gross steam load (flow) (lb/hr)
Operating time at a particular
unit
Operating time at common
stack or pipe
Total number of units using the
common stack or pipe
Designation of a particular unit
Heat input rate for a unit
(mmBtu/hr)
Heat input rate for each stack
or duct (mmBtu/hr)
Operating time for the unit
Operating time for a particular
stack or duct
Designation of a particular
stack or duct
Total number stacks, ducts
(cont.)

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9.0 Monitoring Formula Data

Table 35
Apportionment and Summation Formulas (cont.)
Code

Parameter

F-21D

HI

Formula

Where:




 t CP  FF i t i 

HI i = HI CP    n


t
 i 
 ∑ FF i t i 

 i=1

F-25

HI

p

∑ HI
HI CS =

u

tu

u=1

t CS

HIi

=

HICP

=

FFi

=

ti

=

tCP

=

n

=

i

=

HICS

=

HIu

=

p
tu

=
=

tCS

=

u

=

Heat input rate for a unit
(mmBtu/hr)
Heat input rate at the common
pipe (mmBtu/hr)
Fuel flow rate to a particular
unit (appropriate units)
Operating time at a particular
unit (hr)
Operating time at common pipe
(hr)
Total number of units using the
common pipe
Designation of a particular unit
Hourly average heat input rate
at the common stack
(mmBtu/hr)
Hourly average heat input rate
for a unit (mmBtu/hr)
Number of units
Operating time at a particular
unit
Operating time at common
stack
Designation of a particular unit

Table 36
NOx Mass Emissions Formulas (lbs/hr)
Code

Parameter

F-24A

NOX

Formula

E ( NOx) h = ER(NOx)h x HI h

F-26A

NOX

E ( NOx ) h = K × C hw × Qh

F-26B

NOX

E ( NOx ) h = K x C h d x Q h x

Monitoring Plan Reporting Instructions -- Page 90

(100 - % H 2 O)
100

Where:
E(NOx)h = Hourly NOx mass emissions
rate in lb/hr
K
= 1.194 x 10-7 for NOx
((lb/scf)/ppm)
= Hourly average, NOx
Chd
concentration (ppm (dry))
Chw
= Hourly average, NOx
concentration, stack moisture
basis (ppm (wet))
= Hourly average volumetric
Qh
flow rate (scfh)
%H2O = Hourly average stack moisture
content (percent by volume)
= Hourly average heat input rate
HIh
(mmBtu/hr)
ER(NOx)h = Hourly average NOx emission
rate (lb/mmBtu)

Environmental Protection Agency

9.0 Monitoring Formula Data

June 17, 2009

Table 37
Miscellaneous Formula Codes
Code

Parameter

Description

N-GAS

FGAS

Net or total gas fuel flow rate (100 scfh)

N-OIL

FOIL

Net or total oil fuel flow rate (scf/hr, gal/hr, barrels/hr, m3/hr, or lb/hr)

X-FL

FLOW

Average hourly stack flow rate (scfh). (To calculate the average of two or
more primary flow monitors, for example, two ultrasonic monitors in an
X-pattern)

T-FL

FLOW

Total stack flow rate (scfh)

SS-1A

SO2

Total hourly SO2 mass emissions from the affected unit(s) in a subtractive
stack configuration (lb/hr)

SS-1B

SO2

Hourly SO2 mass emissions from a particular affected unit in a subtractive
stack configuration (lb/hr)

SS-2A

NOX

Total hourly NOx mass emissions from the affected unit(s) in a
subtractive stack configuration (lb/hr)

SS-2B

NOX

Hourly NOx mass emissions from a particular affected unit in a
subtractive stack configuration (lb/hr). (Apportioned by gross load)

SS-2C

NOX

Hourly NOx mass emissions from a particular affected unit in a
subtractive stack configuration (lb/hr). (Apportioned by steam load)

SS-3A

HIT

Total hourly heat input for the affected unit(s) in a subtractive stack
configuration (mmBtu)

SS-3B

HI

Hourly heat input rate for a particular affected unit in a subtractive stack
configuration (mmBtu/hr)

NS-1

NOXR

Hourly NOx apportionment for NOx affected units in a subtractive stack
configuration (lb/mmBtu)

NS-2

NOXR

Hourly NOx apportionment for NOx affected units using simple NOx
apportionment (lb/mmBtu)

Formula Text
Element Name: FormulaText
When using a standard formula from Tables 25 through 36, above, leave the Formula Text field
blank. The Formula Text element is required only when a non-standard or custom equation is
used, i.e., either: (1) one of the equations in Table 37; or (2) another site-specific equation not
listed in Table 39. Use the following guidelines to construct formula text:
● Variables. In non-standard and custom equations, use recognizable symbols in
conjunction with the operators and other representations shown in Table 40. To the
extent possible, use symbols and nomenclature consistent with Tables 25 – 36. Use
parentheses and square brackets as needed, for added clarity.
● Formula References. Wherever another formula in the monitoring plan is part of a nonstandard or custom equation, you may refer to the other formulas as "F#(XYZ)" where
Environmental Protection Agency

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9.0 Monitoring Formula Data

XYZ is the Formula ID, rather than rewriting the entire text of the formula in the nonstandard or custom equation.
● Constants. Appropriate constants must also be included in each non-standard or custom
equation, such as unit conversion factors, fuel factors, etc., that are required for the
calculation.

Table 38
Representations for Electronic Reporting
Recommended
Representation

Operation

Example

Addition

+

MW_1 + MW_2

Subtraction

-

(100 - %H2O)

Multiplication

*

Cd * Fd

Division

/

%CO2/100

Exponential Power

**

1.66 x 10-7 = 1.66 * 10 ** -7

Subscript

Underscore

MW1 = MW_1

Fraction of Heat Input from Fuel

X_

X_oil

Gross Electrical Output

MW_

MW_1

Gross Steam Load (Flow)

SF_

SF_1

Hourly Emissions

E_h

E_h

Operating Time

T_

T_CS1

Begin Date
Element Name: BeginDate
Report the date on which the formula was first applied to calculate the data. This date should
correspond to the earliest date of the Begin Dates for the systems used in the calculation.
Begin Hour
Element Name: BeginHour
Report the hour in which the formula was first applied to calculate the data.
End Date
Element Name: EndDate
For formulas that are discontinued due to a change in monitoring, report the last date on which
the formula was used to calculate the data. This value should be left blank for active records.

Monitoring Plan Reporting Instructions -- Page 92

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9.0 Monitoring Formula Data

June 17, 2009

End Hour
Element Name: EndHour
Report the last hour in which the formula was used to calculate the data. This value should be
left blank for active records.
Specific Considerations
Required Formulas
● Depending on the monitoring methodologies and component types in use, include in the
monitoring plan one or more of the following formulas:
● For CEMS Based Methodologies
-- SO2 mass emission rate
-- NOx emission rate
-- NOx mass emission rate
-- CO2 concentration
-- CO2 mass emission rate
-- Heat input rate
-- F-factor proration calculation for mixed fuels (if elected)
-- Flow-weighted or heat input-weighted NOx emission rate formulas for multiple stacks
using two primary NOx systems
-- Moisture formulas for moisture systems using O2 wet and dry readings
-- Flow formulas for all flow systems containing two flow monitors
● For Fuel Flow Based Methodologies
-- SO2 mass emission rate (ARP)
-- CO2 mass emission rate (ARP)
-- NOx emission rate for the unit where separate Appendix E single fuel curves were
used (Equation E-2)
-- Heat input rate
-- Mass of oil formulas for OILV measurements (ARP)
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9.0 Monitoring Formula Data

-- Net fuel flow formulas for systems with more than one flowmeter
-- F-factor proration calculation for mixed fuels (if elected)
F-Factors and F-Factor Formulas
● Heat input rate, NOx emission rate, and CO2 emission rate formulas based on CEMS
require the inclusion of a specific F-factor based on the fuel being combusted. If a
combination of fuels may be combusted within any given hourly period, two options for
calculating emissions are available: (1) use the highest F-factor, or (2) use a prorated Ffactor. Calculate prorated F-factors using Equation F-8 in 40 CFR Part 75, Appendix F.
If a pro-rated F-factor formula is used, include it in this data set.
Situations That Do Not Require Formulas
● Appendix E units do not need formulas for the NOx emission rate.
● Units using LME methodology in §75.19 do not need formulas.
● Do not include formulas for cumulative quarterly or annual emissions or heat input.
● Do not provide formulas representing the default heat input rate or default NOx emission
rate for the unit or stack.

Monitoring Plan Reporting Instructions -- Page 94

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10.0 Monitoring Default Data

June 17, 2009

10.0 MONITORING DEFAULT DATA
Figure 20
MONITORING DEFAULT DATA XML Elements

Description of Data
MONITORING DEFAULT DATA records define Maximum Values, Minimum Values, Defaults, and
Constants that are used in the Part 75 calculations or in the missing data routines. Report one
record for each fuel type and parameter combination to define the applicable emission factor,
moisture content, maximum potential value or diluent cap to be used at a monitoring location, as
described below.
MONITORING DEFAULT DATA records are required for the following situations:
Missing Data Defaults (DefaultPurposeCode "MD")
● Maximum NOx emission rate (MER) for any location using a NOx-diluent monitoring
CEM system.
● Maximum controlled NOx emission rate (MCR) for bypass stacks or missing data
substitution for hours in which the add-on controls are documented to be operating
properly (see §§75.17(d) and 75.34(a)(5)).
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10.0 Monitoring Default Data

● Fuel-specific maximum potential SO2 or NOx concentrations (MPCs), maximum
potential NOx emission rates (MERs), or maximum potential flow rates (MPFs), for units
using fuel-specific CEMS missing data option under §75.33.
● Fuel-specific maximum potential SO2 or NOx concentrations or maximum potential NOx
emission rates, for units with add-on emission controls and unmonitored bypass stacks, if
the fuel-specific MPC or MER is reported during hours when the flue gases are routed
through the bypass stack and the add-on controls are either bypassed or not documented
to be operating properly (see §§75.16 (c)(3) and 75.17 (d)).
● Fuel-specific maximum controlled NOx concentrations or maximum controlled NOx
emission rates (MCR), for units with add-on emission controls and unmonitored bypass
stacks, if the fuel-specific MEC or MCR is reported during hours when the flue gases are
routed through the bypass stack when the add-on emissions controls are not bypassed, are
in use, and are documented to be operating properly (see §75.17 (d)).
● Generic NOx emission rate defaults for low mass emissions units. Use this value when
NOx controls are not operating or when default has expired.
● Maximum potential NOx concentration and emission rate for Appendix E units. Use
maximum emissions rate when NOx controls are not operating, when burning emergency
fuels, or when Appendix E curve has been invalidated or has expired.
● Maximum or minimum potential moisture percentage (required only if monitoring
moisture continuously or using a moisture look-up table). Used for missing data
purposes.
● Minimum emission values for subtractive stack situations, if approved by petition.
● Minimum potential O2 used for missing data purposes.
● Maximum potential CO2 concentration for missing data purposes for unit/stacks using an
O2 monitor to determine CO2.
Low Mass Emissions Defaults (DefaultPurposeCode "LM")
● Defaults for NOx, SO2, and CO2 emission rates for low mass emissions (LME) units
under §75.19.
● Default maximum rated hourly heat input rate (mmBtu/hr) for low mass emissions units.
Use this value if the heat input monitoring method is MHHI or if the substitute data code
for a LTFF unit is MHHI.

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Primary Monitoring Methodology Default (DefaultPurposeCode "PM")
● Default moisture values from §75.11(b) or §75.12(b), used to estimate stack moisture
content for specific fuels.
● Site-specific default moisture percentages, approved by petition under §75.66.
● Moisture Fraction in Ambient Air for use with equation 19-2.
Diluent Cap Default (DefaultPurposeCode "DC")
● CO2 or O2 diluent cap for NOx emission rate calculations.
Default for Use with Equation F-23 (DefaultPurposeCode "F23")
● Default SO2 emission rates for units which use Equation F-23 to determine SO2 mass
emissions (see §75.11(e)(1)).
Minimum Fuel Flow Rate Default (DefaultPurposeCode "DM")
● Default minimum fuel flow rate (refer to the Part 75 Emissions Monitoring Policy
Manual).
See "Specific Considerations" section about when not to report this record.
Dependencies for MONITORING DEFAULT DATA
The MONITORING DEFAULT DATA record is dependent on the UNIT DATA record or the STACK
PIPE DATA record.
No other records are dependent upon the MONITORING DEFAULT DATA record.

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10.0 Monitoring Default Data

MONITORING DEFAULT DATA Elements
Instructions for completing each element of the MONITORING DEFAULT DATA section are
provided below:
Parameter Code
Element Name: ParameterCode
Report the parameter for which a default value is defined by using the appropriate uppercase
codes as shown in Table 39:

Table 39
Parameter Codes and Descriptions for Monitoring Default

Category
Diluent Cap

Parameter
Code

Description

CO2N

CO2 Diluent Cap.

O2X

O2 Diluent Cap.

Low Mass Emissions Parameters CO2R
(§§75.19 and 75.81(b))

CO2 Default Emission Factor, from Table 45 or Fuel
and Unit-Specific CO2 Default Emission Factor, for
Combustion of "Other" Gaseous Fuel (tons/mmBtu).

NOXR

NOx Default Emission Factor, from Table 42 or Fuel
and Unit-Specific NOx Emission Rate1 (lb/mmBtu).

SO2R

SO2 Default Emission Factor, from Table 43 or Fuel and
Unit-Specific SO2 Default Emission Factor Calculated
Using Equation D-1h, either (1) for combustion of
"other" gaseous fuel; or (2) for fuel oil combustion,
based on the maximum weight percent sulfur in the
operating permit (lb/mmBtu).

MHHI

Maximum Rated Hourly Heat Input Rate (mmBtu/hr).

(cont.)

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Table 39
Parameter Codes and Descriptions for Monitoring Default (cont.)

Category

Parameter
Code

Description

Missing Data Values

H2ON

Minimum Potential Percent Moisture.

or

H2OX

Maximum Potential Percent Moisture.

CO2X

Maximum Percent CO2.

O2N

Minimum Potential Percent Oxygen.

SO2X

Fuel-Specific Maximum Potential SO2 Concentration
(ppm).

NOCX

Fuel-Specific Maximum Potential (MPC) or Maximum
Expected NOx Concentration (ppm) for all hours or
controlled hours. For Appendix E missing data
purposes, report the MPC used to calculate the
Maximum NOx Emission Rate for each fuel curve and,
if applicable, for Emergency fuel.

NORX

Maximum NOx Emission Rate (MER) and Fuel-Specific
Maximum Potential or Maximum Expected NOx
Emission Rate (lb/mmBtu) for all hours or controlled
hours. For Appendix E missing data purposes, an MER
must be determined for each fuel curve and, if
applicable, for Emergency fuel.

FLOX

Fuel-Specific Maximum Potential Flow Rate (scfh).

H2O

Hourly Percent Moisture Content (%H2O).

BWA

Moisture Fraction in Ambient Air.

SO2R

SO2 Generic Default Emission Factor for Pipeline
Natural Gas; or

Maximum Values for
Unmonitored Bypass Stack and
Emergency Fuels

Moisture Default Parameter

SO2 Emission Rate Parameter
for Use in Formula F-23

Fuel and Unit-Specific Default Emission Factor
Calculated Using Equation D-1h for combustion of
"other" gaseous fuel; or
Emission Factor approved by petition for a very low
sulfur solid or liquid fuel (or combination of fuels) per
§75.11 (e).

1

Other Parameters (subject to
EPA approval of petition)

MNHI

Minimum Heat Input Rate (mmBtu/hr).

MNNX

Minimum NOx Emission Rate (lb/mmBtu).

Other Parameters (not subject to
EPA approval of petition)

MNOF

Minimum Oil Flow Rate.

MNGF

Minimum Gas Flow Rate.

Report "NOXR" in the following cases: (1) for fuel-and-unit specific NOx emission rates obtained by testing;
and (2) for the maximum potential NOx emission rate, if that value is reported in the interval from the first
hour of use of the LME methodology until the hour of completion of fuel-and-unit specific NOx emission rate
testing (see §75.19 (a)(4)).

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10.0 Monitoring Default Data

Default Value
Element Name: DefaultValue
Report the Maximum, Minimum, Default, or Constant Value to be used to the number of decimal
places consistent with the corresponding hourly data record.

Table 40
Rounding Rules for Default Values
Round to 0
Decimal
Places

Round to 1
Decimal
Place

Round to 2
Decimal
Places

CO2N, CO2X,
H2O, H2ON,
H2OX, MHHI,
MNGF,
MNHI,
MNOF,
NOCX, O2X,
O2N, SO2X

Parameter
Codes

Round to 3
Decimal
Places
BWA, CO2R,
MNNX,
NORX, NOXR

Round to 4
Decimal
Places
SO2R

Round to
Nearest
1000
FLOX

NOx Maximum Emission Rate (MER)
For a NOx-diluent monitoring system (lb/mmBtu), calculate and report a maximum potential
NOx emission rate (MER), based on the MPC value (reported in the Monitoring Span record) for
use with missing data procedures.
Calculate NOx MER on a unit or stack basis by using one of the following formulas and values:
E = K x Cd x F d x

20.9
20.9 - % O 2d

(Equation F-5)
Where:
E
K
Cd
Fd (dscf/mmBtu)
%O2d

=
=
=
=
=

Pollutant emissions during unit operation, lb/mmBtu;
1.194 x 10-7 (lb/dscf)/ppm NOx;
NOx concentration (dry) (use MPC value);
Dry basis F-factor used for the unit in Monitoring Formula; and
Maximum oxygen concentration during normal operating conditions,
or use the diluent cap value of 14.0 percent O2 for boilers and 19.0
percent O2 for turbines or if MPC is derived from historical data, the
O2 reading recorded at the hour of the MPC may be used.

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10.0 Monitoring Default Data

June 17, 2009

E = K x Cw x Fc x

100
% CO 2w

(Equation F-6)
Where:
E
K
Cw
Fc (scf CO2/mmBtu)
%CO2w

=
=
=
=

Pollutant emissions during unit operation, lb/mmBtu;
1.194 x 10-7 (lb/dscf)/ppm NOx;
NOx concentration (wet) (use MPC value);
Carbon-based F-factor used for the unit in Monitoring Formula 20;
and
= Minimum CO2 concentration during normal operating conditions,
or use the diluent cap value of 5.0 percent CO2 for boilers and 1.0
percent CO2 for turbines or if MPC is derived from historical data,
the CO2 reading recorded at the hour of the MPC may be used.

Diluent Cap Values
For a CO2 diluent cap value, report 5.0 percent for a boiler or 1.0 percent for a combustion
turbine. For an O2 diluent cap value, report 14.0 percent for a boiler or 19.0 percent for a
turbine.
Moisture Defaults
If using a default value to determine moisture, report fuel-specific moisture default values.
Tables 41 and 42 provide the fuel-specific moisture default values for coal-fired and woodburning units and natural gas-fired boilers. Table 41 provides minimum default moisture values
that are used in all emission (SO2, NOx, CO2) and heat input rate calculations requiring moisture
corrections, except for calculation of NOx emission rates using Equation 19-3, 19-4, or 19-8 from
EPA Method 19 in Appendix A-7 to 40 CFR 60. If Equation 19-3, 19-4, or 19-8 is used to
calculate NOx emission rate, use the appropriate maximum default moisture value from Table 42.
If using a monitoring system to determine moisture, report either the maximum or minimum
potential moisture percentage, depending on whether you use the standard or inverse missing
data procedure from Part 75. For the minimum potential moisture percentage, report either a
default value of 3.0 percent H2O or a site-specific value obtained from 720 or more hours of
historical data. For the maximum potential moisture percentage, report either a default value of
15.0 percent H2O or a site-specific value derived from 720 or more hours of historical data.

Environmental Protection Agency

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10.0 Monitoring Default Data

Table 41
Fuel-Specific Minimum Default Moisture Values
for SO2, NOx, CO2, and Heat Input Rate Calculations

Fuel

Minimum Moisture
Default Value

Anthracite Coal

3.0%

Bituminous Coal

6.0%

Sub-bituminous Coal

8.0%

Lignite Coal

11.0%

Wood

13.0%

Natural Gas (boilers
only)

14.0%

Table 42
Fuel-Specific Maximum Default Moisture Values
for NOx Emission Rate Calculations

Fuel

Maximum Moisture
Default Value

Anthracite Coal

5.0%

Bituminous Coal

8.0%

Sub-bituminous Coal

12.0%

Lignite Coal

13.0%

Wood

15.0%

Natural Gas (boilers
only)

18.0%

LME Defaults
Table 43 contains the "generic" default NOx emission factors for qualifying oil and gas-fired low
mass emissions units under §75.19, which are based on the unit type and the type of fuel
combusted. Unit and fuel-specific NOx emission rates may be determined for low mass
emissions units by emission testing, in lieu of using the defaults in Table 43. For fuel oil
combustion, in lieu of using the default values in Table 44, fuel and unit-specific default SO2
emission rates may be determined based on the maximum allowable weight percentage of sulfur
in the fuel, as specified in the operating permit (see §75.19(c)(1)(i)). For gaseous fuels other
than natural gas, there are no generic default values available. Therefore, fuel and unit-specific
emission rates must be determined for all emission parameters.

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10.0 Monitoring Default Data

June 17, 2009

Table 43
NOx Emission Factors (lb/mmBtu) for Low Mass Emissions Units
Boiler Type

Fuel Type

Turbine

Boiler

NOx Emission Factors

Natural Gas

0.7

Oil

1.2

Natural Gas

1.5

Oil

2.0

Table 44 contains the Part 75 SO2 emission factors for low mass emissions units, which are
based on the type of fuel combusted.

Table 44
SO2 Emission Factors (lb/mmBtu) for Low Mass Emissions Units
Fuel Type
Pipeline Natural Gas
(as defined in §72.2)

SO2 Emission Factors
0.0006

Natural Gas

0.06

Residual Oil
or Other Oil

2.10

Diesel Fuel

0.50

Table 45 contains fuel-specific CO2 emission factors for low mass emissions units.

Table 45
CO2 Emission Factors (ton/mmBtu) for Low Mass Emissions Units
Fuel Type

Environmental Protection Agency

CO2 Emission Factors

Natural Gas

0.059

Oil

0.081

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10.0 Monitoring Default Data

Default Units of Measure Code
Element Name: DefaultUnitsOfMeasureCode
Report the appropriate measurement units using the appropriate uppercase codes as shown in
Table 46. For Parameter BWA, leave this field blank.

Table 46
Units of Measure Codes by Parameter
Units of
Measure Code

Description

Parameter Code

PCT

Percent

CO2N, CO2X, H2O, H2ON,
H2OX, O2N, O2X

LBMMBTU

Pounds per Million Btu

MNNX, NOXR, SO2R, NORX

MMBTUHR

Million Btu per Hour

MNHI, MHHI

TNMMBTU

Tons per Million Btu

CO2R

SCFH

Standard Cubic Feet per Hour

MNOF, FLOX,

PPM

Parts per million

SO2X, NOCX

GALHR

Gallons of Oil per Hour

MNOF

BBLHR

Barrels of Oil per Hour

MNOF

M3HR

Cubic Meters of Oil per Hour

MNOF

LBHR

Pounds of Oil per Hour

MNOF

HSCF

Hundred SCF of Gas per Hour

MNGF

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June 17, 2009

Default Purpose Code
Element Name: DefaultPurposeCode
Identify the purpose or intended use of the Default Value for reporting and emissions
measurement by using the appropriate uppercase codes as shown in Table 47:

Table 47
Default Purpose Codes and Descriptions
Code

Description

Parameter Code

DC

Diluent Cap

CO2N, O2X

DM

Default Minimum Fuel Flow Rate

MNGF, MNOF

F23

SO2 Emission Rate Default for Use in Equation F-23 SO2R

LM

Low Mass Emissions Unit Default (§§75.19 and
75.81(b))

CO2R, SO2R, NOXR, MHHI

MD

Missing Data, Unmonitored Bypass Stack, or
Emergency Fuel

CO2X, FLOX, H2ON, H2OX,
MNHI, MNNX, NOCX,
NORX, O2N, SO2X

PM

Primary Measurement Methodology

BWA, H2O

Fuel Code
Element Name: FuelCode
Report the type of fuel associated with the default by using the appropriate uppercase codes as
shown in Table 48. For maximum NOx emission rate that is not fuel-specific or for maximum or
minimum potential moisture or O2/CO2 values, report a Non-Fuel Specific code, or "NFS."

Table 48
Fuel Codes and Descriptions
Type
LME Defaults
(§75.19)

Code

Description

BFG

Blast Furnace Gas

BUT

Butane (if measured as a gas)

CDG

Coal Derived Gas

COG

Coke Oven Gas

DGG

Digester Gas

DSL

Diesel Oil

LFG

Landfill Gas
(cont.)

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Table 48
Fuel Codes and Descriptions (cont.)
Type
LME Defaults
(§75.19) (cont.)

Moisture

SO2 Emission Rate Default
for Use in Equation F-23

Fuel-Specific CEMS Missing
Data

Code

Description

LPG

Liquefied Petroleum Gas (if measured as a gas)

NNG

Natural Gas

OGS

Other Gas

OIL

Residual Oil

OOL

Other Oil

PDG

Producer Gas

PNG

Pipeline Natural Gas (as defined in §72.2)

PRG

Process Gas

PRP

Propane (if measured as a gas)

RFG

Refinery Gas

SRG

Unrefined Sour Gas

ANT

Anthracite Coal

BT

Bituminous Coal

CRF

Coal Refuse (culm or gob)

LIG

Lignite

NNG

Natural Gas (including Pipeline Natural Gas)

PNG

Pipeline Natural Gas

SUB

Sub-bituminous Coal

W

Wood

NNG

Natural Gas

PNG

Pipeline Natural Gas

OGS

Other Gas

* or MIX

*With an approved petition, any liquid or solid fuel type that
qualifies as very low sulfur fuel, or a mixture of such fuels.
See fuel code list in UNIT FUEL DATA

BFG

Blast Furnace Gas

BUT

Butane (if measured as a gas)

C

Coal

CDG

Coal-Derived Gas

COG

Coke Oven Gas
(cont.)

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Table 48
Fuel Codes and Descriptions (cont.)
Type
Fuel-Specific CEMS Missing
Data (cont.)

Code

Description

COF

Co-Fired Fuels

CRF

Coal Refuse (culm or gob)

DGG

Digester Gas

DSL

Diesel Oil

LFG

Landfill Gas

LPG

Liquefied Petroleum Gas (if measured as a gas)

NNG

Natural Gas

OGS

Other Gas

OIL

Residual Oil

OOL

Other Oil

OSF

Other Solid Fuel

PDG

Producer Gas

PNG

Pipeline Natural Gas (as defined in §72.2)

PRG

Process Gas

PRP

Propane (if measured as a gas)

PRS

Process Sludge

PTC

Petroleum Coke

R

Refuse

RFG

Refinery Gas

SRG

Unrefined Sour Gas

TDF

Tire-Derived Fuel

W

Wood

WL

Waste Liquid

Fuel-Specific MPC/MER or
BFG
MEC/MCR Reporting During
BUT
Bypass Stack Operating
Hours
C

Blast Furnace Gas

CDG

Coal-Derived Gas

COG

Coke Oven Gas

CRF

Coal Refuse (culm or gob)

DGG

Digester Gas

DSL

Diesel Oil

Butane (if measured as a gas)
Coal

(cont.)
Environmental Protection Agency

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10.0 Monitoring Default Data

Table 48
Fuel Codes and Descriptions (cont.)
Type

Code

Fuel-Specific MPC/MER or
LFG
MEC/MCR Reporting During
LPG
Bypass Stack Operating
Hours (cont.)
NNG

Description
Landfill Gas
Liquefied Petroleum Gas (if measured as a gas)
Natural Gas

OGS

Other Gas

OIL

Residual Oil

OOL

Other Oil

OSF

Other Solid Fuel

PDG

Producer Gas

PNG

Pipeline Natural Gas (as defined in §72.2)

PRG

Process Gas

PRP

Propane (if measured as a gas)

PRS

Process Sludge

PTC

Petroleum Coke

R

Refuse

RFG

Refinery Gas

SRG

Unrefined Sour Gas

TDF

Tire-Derived Fuel

W

Wood

WL

Waste Liquid

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June 17, 2009

Operating Condition Code
Element Name: OperatingConditionCode
If the value is used only for controlled or uncontrolled hours, indicate this using a "C" or "U," as
appropriate. If this is a unit-specific default NOx emission rate for an LME combustion turbine
that has base and peak rates, report "B" or "P" to indicate the operating condition to which this
rate applies. Report "A" if the use of the value is not related to the control status of the unit or
base versus peak operation, such as for diluent cap records. Table 49 summarizes operating
condition codes and descriptions.

Table 49
Operating Condition Codes and Descriptions
Operating Condition Code

Description

A

Any Hour

C

Controlled Hour

B

Base Load Hour (LME units)

P

Peak Load Hour (LME units)

U

Uncontrolled Hour

Default Source Code
Element Name: DefaultSourceCode
Report the means of selecting or determining the Maximum, Minimum, or Constant value by
using the appropriate uppercase codes for the parameters reported as shown in Table 50:

Table 50
Default Source Codes and Descriptions
Default
Source Code

Source of Value Description

Parameter

APP*

Approved (Petition)

MNNX, SO2R, MNHI, H2O,
MHHI

DATA**

Historical or Other Relevant Data

O2N, O2X, CO2X, H2ON,
H2OX, FLOX, SO2X, NOCX,
NORX, NOXR, MNOF, MNGF,
BWA

PERM

Maximum Weight Percent Sulfur in Fuel Oil, as
Specified by Operating Permit (for LME)

SO2R, NORX, NOCX

TEST

Unit/Stack Testing

NOXR, FLOX, SO2X, NOCX,
NORX
(cont.)

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10.0 Monitoring Default Data

Table 50
Default Source Codes and Descriptions (cont.)
Default
Source Code

Source of Value Description

Parameter

SAMP

Fuel Sampling

SO2R, CO2R, SO2X

CONT

Contract Maximum

SO2R

DEF

Default Value from Part 75

CO2R, NOXR, CO2N, O2X,
SO2R, H2ON, H2OX, SO2X,
NOCX, NORX, H2O

MAXD

Maximum Value Based on Design or Nameplate
Capacity

MHHI, NORX, NOCX

* Report "APP" if you have an approved petition to use a site-specific SO2 emission factor for very low
sulfur solid or liquid fuels.
** Report code "DATA" in this field if reporting the maximum potential NOx emission rate in the interval
from the first hour of use of the LME methodology until the hour of completion of fuel-and-unit specific
NOx emission rate testing (see §75.19 (a)(4)).

Group ID
Element Name: GroupID
Report data in this field only if the unit is included in a group of identical low mass emissions
(LME) units under §75.19. Otherwise, leave this field blank.
Report the Group ID that has been assigned by the Designated Representative, if the default
value reported in this MONITORING DATA DEFAULT record is a currently-applicable (i.e., active)
fuel-and-unit-specific default NOx emission rate for this unit and for the other units in a group of
identical LME units under §75.19.
The Group ID must begin with GP or G, followed by the six-digit ORIS Code of one of the
facilities in the group. Include leading zeros in the ORIS code, as appropriate (e.g., report the
Group ID for a group of identical units that includes ORIS Code 55 as either "GP000055" or
"G000055").
The default value for the group of identical units must be updated each time that a subset of the
group is tested to establish the new default NOx emission rate (for LME units). The minimum
retest frequency for LME units is once every five years (20 calendar quarters).
Begin Date
Element Name: BeginDate
Report the date on which the default became effective for purposes of reporting emissions data.

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10.0 Monitoring Default Data

June 17, 2009

Begin Hour
Element Name: BeginHour
Report the hour on which the default became effective for purposes of reporting emissions data.
End Date
Element Name: EndDate
Report the date after which the value will no longer be used. Submit a second Monitor Default
record with an effective date to report a new value. This value should be left blank for active
records.
End Hour
Element Name: EndHour
Report the hour after which the value will no longer be used. Submit a second Monitor Default
record with an effective hour to report a new value. This value should be left blank for active
records.
Specific Considerations
Situations Not Requiring Monitoring Default Data Submission
● Values for CO2 or O2 used to calculate the maximum potential velocity (MPV), which is
used to determine the flow rate span value. Submit the information to support flow span
calculations in hardcopy with the initial monitoring plan (and store on site). Do not
report this information electronically in the EDR.
● Maximum oil and gas fuel flow rate. These values are defined in SYSTEM FUEL FLOW
DATA.
● Maximum potential (or maximum expected) SO2, NOx, CO2, or flow rate values, for units
using the standard (non-fuel-specific (NSF)) CEMS missing data routines in §75.33.
(These maximum potential and expected values are defined in Monitor Span Data.)
● Default high range value for SO2 or NOx (already defined in monitor span).
● Default SO2 emission rates for Acid Rain Program units that use Appendix D to account
for SO2 mass emissions from the combustion of gaseous fuel. For these units, report the
default SO2 emission rates in the PARAMETER FUEL FLOW DATA record.
● Appendix D density and GCV values for oil and gas. These values are defined in the
FUEL FLOW DATA record.

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10.0 Monitoring Default Data

Specific Considerations for Units Using Equation F-23
● For pipeline natural gas combustion, report 0.0006 lb/mmBtu.
● For other natural gas combustion, report the default SO2 emission rate (lb/mmBtu)
calculated using Equation D-1h.
● For gaseous fuels other than natural gas that qualify under Section 2.3.6 of Appendix D
to use a default SO2 emission rate, report the emission rate (lb/mmBtu), calculated using
Equation D-1h.
● For very low sulfur solid or liquid fuels or mixtures of these fuels with gaseous fuel,
report the custom default SO2 emission rate(s) approved by petition.

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11.0 Monitoring Span Data

June 17, 2009

11.0 MONITORING SPAN DATA
Figure 21
MONITORING SPAN DATA XML Elements

Description of Data
MONITORING SPAN DATA contains information concerning the span and range values associated
with the continuous emission monitors installed at unit or stack and the time period in which
these values are effective. It also contains information regarding the Maximum Potential and
Maximum controlled values for each parameter monitored.

Environmental Protection Agency

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11.0 Monitoring Span Data

Dependencies for MONITORING SPAN DATA
The MONITORING SPAN DATA record is dependent on the UNIT DATA record or the STACK PIPE
DATA record.
No other records are dependent upon the MONITORING SPAN DATA record.
MONITORING SPAN DATA Elements
Instructions for completing each element of the MONITORING SPAN DATA section are provided
below:
Component Type Code
Element Name: ComponentTypeCode
Identify the component type (parameter) of the monitor using the following uppercase codes:

Table 51
Component Type Codes and Descriptions for Monitor Span
Code

Description

CO2

CO2 Concentration (percent)

FLOW

Stack Flow

NOX

NOx Concentration (ppm)

O2

O2 Concentration (percent)

SO2

SO2 Concentration (ppm)

Span Scale Code
Element Name: SpanScaleCode
Report either "H" to indicate high scale or "L" to indicate low scale for SO2, NOx, CO2, or O2.
For FLOW leave this field blank.

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11.0 Monitoring Span Data

June 17, 2009

Span Method Code
Element Name: SpanMethodCode
Report the method used to determine the maximum potential (or expected) concentration (MPC
or MEC) or flow rate (MPF) by using the appropriate uppercase codes as shown in Table 52:

Table 52
Provision for Calculating MPC/MEC/MPF Codes and Descriptions
Code

Description

F

Formula (low and high-scale SO2,
flow rate, and low-scale NOx only)

HD

Historical Data

TR

Test Results

TB

Table of Constants from Part 75 or
Default Values from Part 75 (e.g., 800
ppm NOx for coal-firing)

OL

Other Limit

GS

Low Scale Default for SO2 for Gas
Units

PL

NOx MEC Based on Permit Limit

ME

NOx MPC Based on Manufacturer's
Estimate of Uncontrolled Emissions

Table 53 summarizes the recommended methods for determining MPC/MEC/MPF.
● Submit documentation with the original hardcopy monitoring plan submission and retain
files of the supporting information concerning a unit for recordkeeping purposes if using
Equations A-1a or A-1b from Appendix A to Part 75 or historical data to determine
maximum potential flow (MPF).
● Leave this field blank for O2 records.
● For CO2, enter a default MPC value of 14.0 percent CO2 for boilers and 6.0 percent CO2
for turbines. For turbines, an alternative default MPC value below 6.0 percent CO2 may
be used if a technical justification is provided in the hard copy monitoring plan. Report a
Span Method Code of "TB" if the default value is reported. The MPC may also be
determined based on historical data. If historical data are used (720 hours, minimum),
report the highest %CO2 value observed in the historical look-back period as the MPC.

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11.0 Monitoring Span Data

Table 53
Criteria for MPC/MEC/MPF Determinations

Parameter
NOX

Scale
High

Low

FLOW

N/A

Method Used to Determine
MPC/MEC/MPF

Selection Criteria

Method
Code

800 or 1600 ppm, as applicable

For coal-fired units

TB

400 ppm

For oil- or gas-fired units

TB

2000 ppm

Cement kilns

TB

500 ppm

Process heaters burning oil

TB

200 ppm

Process heaters burning only gaseous
fuels

TB

Historical CEM data

For initial determination or for changes in HD
MPC as described in Section 2.1.2.5 of
Appendix A

Other constant values from
Appendix A, Tables 2-1 and 2-2

If historical data not available by boiler
type and fuel

TB

Test results

If historical data not available

TR

Other, including other
state/federal requirements

As justified

OL

Manufacturer=s estimate of
uncontrolled emissions

For initial MPC determination,
principally for new units

ME

Equation A-2

For units with emission controls

F

Historical CEM data

For initial determination or for changes in HD
MEC as described in Sections 2.1.2.2(c)
and 2.1.2.5 of Appendix A

Other, including other
state/federal requirements

As justified

OL

Test results

If available

TR

Permit limit

For initial MEC determination,
principally for new units

PL

Equation A-3a and Equation of
Continuity*

Based on %CO2

F

Equation A-3b and Equation of
Continuity*

Based on %O2

F

Historical data

For changes in MPF, as described in
Section 2.1.4.3 of Appendix A

HD

Test results

If available

TR
(cont.)

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11.0 Monitoring Span Data

June 17, 2009

Table 53
Criteria for MPC/MEC/MPF Determinations (cont.)

Parameter
SO2

Scale
High

Low

Method Used to Determine
MPC/MEC/MPF

Selection Criteria

Method
Code

Equation A-1a

Based on %CO2

F

Equation A-1b

Based on %O2

F

Historical CEM data

For initial determination or for changes in HD
MPC as described in Section 2.1.1.5 of
Appendix A

Test results

If available

TR

Other, including other
state/federal requirements

As justified

OL

Equation A-2

For units with emission controls

F

Historical CEM data

For initial determination or for changes in HD
MEC as described in Section 2.1.1.5 of
Appendix A

 200 ppm (span value)

For units burning only very low sulfur
fuel (as defined in §72.2)

GS

Other, including other
state/federal requirements

As justified

OL

* The maximum potential flow rate (MPF) is calculated using the Equation of Continuity: MPF = 60 x MPV x
As. In this equation, MPV is the maximum potential velocity (from Equation A-3a or A-3b or from test
results), in units of wet, standard feet per minute, and As is the cross-sectional area of the stack at the flow
monitor location.

MEC Value
Element Name: MECValue
If required to determine MEC per Part 75, Appendix A, report the Maximum Expected
Concentration (MEC) value for the location in the SO2 and NOx span records. Report MEC for
SO2 and NOx to one decimal place. Report this value in the high-scale record and, if a low scale
is defined, also in the low-scale record. Leave this field blank for other parameters.
MPC Value
Element Name: MPCValue
In the high scale record for NOx, SO2, or CO2, report the Maximum Potential Concentration
(MPC) value for the location. Report MPC for NOx or SO2 to one decimal place. For O2, leave
this field blank.

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MPF Value
Element Name: MPFValue
If the span record is for parameter FLOW, report the Maximum Potential Flow (MPF) value for
the monitoring location in standard cubic feet per hour (scfh) on a wet basis.
Span Value
Element Name: SpanValue
Report the Span Value determined according to the requirements of Part 75. If using a default
high range value for SO2 or NOx, leave this field blank in the high scale record.
For SO2 and NOx, high-scale span values must be between 100 percent and 125 percent of the
maximum potential concentration, rounded up to the next highest multiple of 100 ppm (or,
alternatively, rounded up to the next 10 ppm if 125 percent of MPC is less than 500 ppm). Lowscale span values must be between 100 percent and 125 percent of MEC, rounded upward to the
next highest multiple of 10 ppm.
For flow rate, the span value is the calibration span value and must be reported in the units used
for daily calibrations. To determine the calibration span value for monitors that are not
calibrated in units of inches of H2O, first convert the maximum potential velocity (MPV) from
units of wet standard feet per minute (wsfpm) to the units used for daily calibration. Multiply the
result by a factor no less than 1.00 and no more than 1.25 and round up, retaining at least two
significant figures. For flow monitors calibrated in inches of water, report the calibration span
value to two decimal places.
For CO2 and O2, report the appropriate percentage (see Part 75, Appendix A, §2.1.3), to the
nearest one percent CO2 or O2, not ppm.
Full Scale Range
Element Name: FullScaleRange
Report the full-scale range in the units used for daily calibrations for SO2, NOx, CO2, O2, and
flow rate. As a general guideline, select the range such that, to the extent practicable, the
majority of the readings obtained during normal operation of the monitor are between 20 and 80
percent of full-scale. See Section 2.1 of Appendix A to Part 75 for allowable exceptions to this
guideline. The full-scale range must be greater than or equal to the span value. Leave this field
blank in the high scale Monitoring Span record if using a default high range value for SO2 or
NOx.

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11.0 Monitoring Span Data

June 17, 2009

Span Units of Measure Code
Element Name: SpanUnitsOfMeasureCode
For SO2 and NOx, report PPM. For O2 and CO2, report PCT.
For a flow span record, report one of the following uppercase codes to indicate the units used to
report and perform daily calibrations based on span:

Table 54
Flow Span Calibration Units of Measure
Code

Description

ACFH

Actual Cubic Feet of Stack Flow per
Hour

ACFM

Actual Cubic Feet of Stack Flow per
Minute

AFPM

Actual Feet of Stack Flow per Minute

AMSEC

Actual Meters of Stack Flow per Second

INH2O

Inches of Water

KACFH

Thousand Actual Cubic Feet of Stack
Flow per Hour

KACFM Thousand Actual Cubic Feet of Stack
Flow per Minute
KAFPM

Thousand Actual Feet of Stack Flow per
Minute

KSCFH

Thousand Standard Cubic Feet of Stack
Flow per Hour

KSCFM

Thousand Standard Cubic Feet of Stack
Flow per Minute

KSFPM

Thousand Standard Feet of Stack Flow
per Minute

MACFH Million Actual Cubic Feet of Stack
Flow per Hour

Environmental Protection Agency

MSCFH

Million Standard Cubic Feet of Stack
Flow per Hour

SCFH

Standard Cubic Feet of Stack Flow per
Hour

SCFM

Standard Cubic Feet of Stack Flow per
Minute

SFPM

Standard Feet of Stack Flow per Minute

SMSEC

Standard Meters of Stack Flow per
Second

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11.0 Monitoring Span Data

Scale Transition Point
Element Name: ScaleTransitionPoint
If a dual range analyzer is installed for NOx, SO2 or CO2 (see Analyzer range data), report the
concentration value at which the DAHS switches from recording on the normal range to
recording on the secondary range (usually low to high). Report this value in both the low and
high scale records. Scale transition point is not reported for FLOW span.
Default High Range
Element Name: DefaultHighRange
For parameter SO2 or NOx, if using a default high range, report the actual default value in this
field in the high scale record. The default high range value must be 200 percent of the maximum
potential concentration. Report this value only in the high scale record for the parameter.
For the parameters CO2, O2, or FLOW, leave this field blank.
Flow Span Value
Element Name: FlowSpanValue
For the parameter FLOW, report the flow rate span value in scfh, which is the product of the
MPF and a factor no less than 1.00 and no greater than 1.25. This factor must be the same one
that was used to determine the calibration span value. Round the flow rate span value upward to
the next highest 1000 scfh.
Flow Full Scale Range
Element Name: FlowFullScaleRange
Report the actual full-scale range value expressed in units of scfh for the parameter FLOW. The
flow rate full-scale range value must be greater than or equal to the flow rate span value.
Begin Date
Element Name: BeginDate
Report the date that the current span value became effective for reporting emissions data.
If you have elected to use a default high range value for SO2 or NOx, report the date on which the
default high range was implemented in the DAHS.
Begin Hour
Element Name: BeginHour
Report the hour that the current span value became effective for reporting emissions data.
If you have elected to use a default high range value for SO2 or NOx, report the hour on which
the default high range was implemented in the DAHS.

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11.0 Monitoring Span Data

June 17, 2009

End Date
Element Name: EndDate
Report the last date on which the span record was in effect. Leave this field blank for active span
records. If a span change was made, report both the original span record with the appropriate
end date and the new span record with the appropriate begin date.
End Hour
Element Name: EndHour
Report the last hour in which the span record was in effect. Leave this field blank for active span
records.
Specific Considerations
CEMS Methodology
● If you are using a CEMS methodology, MONITORING SPAN DATA must be included for
each parameter (e.g., NOX, SO2, CO2, O2, or FLOW) that is measured with CEMS.
Note that for units that combust more than one type of fuel, the maximum potential
concentration (MPC) values reported in MONITORING SPAN DATA are based solely on the
fuel that produces the highest pollutant concentration or emission rate. Therefore, if you
elect to use one of the fuel-specific missing data options in §75.33, 75.16(c)(3), or
75.17(d)(2), in addition to reporting the "conventional" MPC or MER values in
MONITORING SPAN DATA, you must report a fuel-specific maximum potential value for
each of the other fuels, using MONITORING DEFAULT DATA.
Dual Ranges and Separate MONITORING SPAN DATA Records
● If SO2, NOx, CO2, or O2 emission concentrations vary such that dual ranges are required
(e.g., due to fuel switching or emission controls), provide separate Monitoring Span Data
records for the low scale and high scale values.
High Scale and Low Scale Span Records
● If you elect to use a default high range value (200 percent of MPC for SO2 or NOx)
instead of calibrating and maintaining a high monitor range for hours in which emissions
exceed the full-scale of the low range, submit both high scale and low scale span records,
but in the high scale record, only report values for the following elements: the MPC,
Begin Date and Begin Hour, the activation date and hour of the default high range value,
and Default High Range (the default high range value of 200 percent of MPC).

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11.0 Monitoring Span Data

DP-Type Flow Monitors Calibrated in Units of Inches of H2O
● For DP-type flow monitors that are calibrated in units of inches of H2O, select a value
between 100 percent and 125 percent of the MPV. Then convert that value from units of
wet, standard feet per minute (wsfpm) to units of wet actual feet per second (wafps).
Then use Equation 2-7 in EPA Reference Method 2 (40 CFR 60, Appendix A-1) to
convert the actual velocity to an equivalent delta-P value in inches of H2O. Retain at
least two decimal places in the delta-P value. In performing these calculations, the values
of stack temperature, stack pressure, stack gas molecular weight and the pitot tube
coefficient may be estimated based on the results of previous emission testing.
Updating the MONITORING SPAN DATA Record
When any value in a MONITORING SPAN DATA record changes, update the information by
reporting both the original span record with the appropriate end date and the new span record
with the appropriate begin date.
If you have discontinued the use of a default high range value for SO2 or NOx in favor of using a
span value, report in the old record the last date and hour on which the default high range was in
use. In the new record, report the date and hour on which the new span value became effective.
If changing from a span value to a default high range value for SO2 or NOx, report the date on
which the default high range was implemented in the DAHS.
In order to correct a previously submitted record that contains erroneous information, resubmit
the MONITORING SPAN DATA record with the corrected information.

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12.0 Rectangular Duct WAF Data

June 17, 2009

12.0 RECTANGULAR DUCT WAF DATA
Figure 22
RECTANGULAR DUCT WAF DATA XML Elements

Description of Data
Submit a RECTANGULAR DUCT WAF DATA record for rectangular ducts or stacks with installed
flow monitors, in which a wall effects adjustment factor (WAF) was determined using
Conditional Test Method CTM-041 and applied to the hourly flow rate data. Conditional Test
Method CTM-041 is used to either:
● Determine a site-specific default WAF; or
● Make wall effects measurements and calculate an average WAF, based on three or more
test runs.
If you elect to measure wall effects, the measurements may be made at any load level (low, mid
or high) and may either be coupled with the test runs of a flow RATA or may be made
separately. Once a default or measured WAF has been determined, it may be entered into the
programming of the flow monitor as a correction to the cross-sectional area of the rectangular
stack or duct, thereby adjusting the measured stack gas flow rates for wall effects. Then, when a
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12.0 Rectangular Duct WAF Data

subsequent RATA of the flow monitor is performed, the same WAF that is being used to correct
the flow monitor readings should be applied to the reference method test data.
All units/stacks currently applying a wall effects correction obtained using CTM-041 to flow rate
data must report a RECTANGULAR DUCT WAF DATA record in each quarterly submission. For
units not presently applying a wall effects correction, if you intend to begin using a WAF, report
this record after the WAF has been determined and prior to the next quarterly file that uses that
WAF.
If a new WAF test has been performed (because the stack or ductwork is altered such that the
flow profile is significantly changed), report two RECTANGULAR DUCT WAF DATA records: one
that ends the record that is no longer effective, and one that reports the new wall effects
adjustment factor data.
Dependencies for RECTANGULAR DUCT WAF DATA
The RECTANGULAR DUCT WAF DATA record is dependent on the UNIT DATA record or the
STACK PIPE DATA record.
No other records are dependent upon the RECTANGULAR DUCT WAF DATA record.
RECTANGULAR DUCT WAF DATA Elements
Instructions for completing each element of the MONITORING LOCATION ATTRIBUTE DATA
section are provided below:
WAF Determination Date
Element Name: WAFDeterminationDate
Report the date the WAF was determined. Unless you are a first time user of CTM-041, this date
must be on or prior to the WAF Begin Date. First time users of CTM-041 may retroactively
apply the rectangular duct WAF back to January 1 of the year in which the rectangular duct
WAF determination is made, unless the flow profile changed significantly during that period.
Therefore, for first-time users, the WAF Begin Date may be earlier than the WAF Determination
Date.
WAF Begin Date
Element Name: WAFBeginDate
Report the date on which the WAF was first applied to the flow rate data.
WAF Begin Hour
Element Name: WAFBeginHour
Report the hour in which the WAF was first applied to the flow rate data.

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12.0 Rectangular Duct WAF Data

June 17, 2009

WAF Method Code
Element Name: WAFMethodCode
Report the appropriate WAF Method Code displayed in Table 55 to indicate the WAF
calculation approach.

Table 55
WAF Method Code and Descriptions
Code

Description

FT

Full Test (CTM-041 §§8.1 and 8.2)

AT

Abbreviated Test (CTM-041 §8.4.1)

DF

Default Value (CTM-041 §8.4.2)

WAF Value
Element Name: WAFValue
Report the WAF applied to the flow rate data, to four decimal places, with a leading zero (e.g.,
0.9750).
Number of Test Runs
Element Name: NumberOfTestRuns
Report the number of runs in the WAF test (must be one for default WAF and at least three for a
measured WAF).
Number of Traverse Points WAF
Element Name: NumberOfTraversePointsWAF
Report the number of Method 1 traverse points in the WAF test runs.
Number of Test Ports
Element Name: NumberOfTestPorts
Report the number of test ports at which measurements were made during the WAF test runs.
Number of Traverse Points Reference
Element Name: NumberOfTraversePointsRef
Report the number of Method 1 traverse points in the "reference" flow RATA test runs. The
reference flow RATA is either the RATA that accompanied the CTM-041 determination, or if
the WAF was determined separately from a RATA, the RATA that most recently preceded the
WAF determination. Consistent with CTM-041, the number of this data element for the
"reference" flow RATA and for all subsequent flow RATAs must equal the Number of Traverse
Points WAF data element, for the WAF test run(s). If you wish to increase the number of
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12.0 Rectangular Duct WAF Data

Method 1 traverse points used in a subsequent flow RATA, you must re-determine the WAF
using an equal number of Method 1 traverse points.
Duct Width
Element Name: DuctWidth
Report the width of the rectangular duct at the test location (i.e., dimension Lx in Figure 1 of
CTM-041), to the nearest 0.1 ft.
Duct Depth
Element Name: DuctDepth
Report the depth of the rectangular duct at the test location (i.e., dimension Ly in Figure 1 of
CTM-041), to the nearest 0.1 ft.
WAF End Date
Element Name: WAFEndDate
Report the date on which the WAF was last applied to the flow rate data. Leave this field blank
if this WAF is still being applied.
WAF End Hour
Element Name: WAFEndHour
Report the hour in which the WAF was last applied to the flow rate data. Leave this field blank
if this WAF is still being applied.

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13.0 Monitoring Load Data

June 17, 2009

13.0 MONITORING LOAD DATA
Figure 23
MONITORING LOAD DATA XML Elements

Description of Data
The MONITORING LOAD DATA record identifies the maximum load, the lower and upper
boundaries of the range of operation and, if applicable, the normal load level(s) for a unit or
other monitoring location. Report this record for every unit, stack, and pipe in the monitoring
plan.
Dependencies for MONITORING LOAD DATA
The MONITORING LOAD DATA record is dependent on the UNIT DATA record or the STACK PIPE
DATA record.
No other records are dependent upon the MONITORING LOAD DATA record.

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MONITORING LOAD DATA Elements
Instructions for completing each element of the MONITORING LOAD DATA section are provided
below:
Maximum Load Value
Element Name: MaximumLoadValue
This value is required for all units and all additional monitoring locations with the exception of
non-load based units. Define the maximum hourly gross load associated with the unit, stack, or
pipe at full capacity:
● For boilers and simple cycle turbines (including units with multiple stack exhaust
configurations), this value is based on one of the following: (1) the nameplate capacity;
(2) the nameplate capacity as derated; or (3) a value higher than nameplate, if the unit or
stack historically operates at levels exceeding nameplate.
● For common stack (or common pipe) configurations, the maximum load will be the
highest sustainable combined operating load for the units serving the common stack (or
pipe).
● For multiple stacks, report the maximum hourly gross load for the associated unit.
● Determine the total maximum hourly gross load according to the guidelines in the Part 75
Emissions Monitoring Policy Manual for combined cycle (CC) combustion turbine units.
For combined cycle combustion turbines where the HRSG produces steam, the equivalent
load for the HRSG must be included in the maximum hourly gross load determination.
Express the total unit load on a consistent basis, i.e., either in terms of electrical or steam
load.
● Leave this field blank for units that do not produce electrical or steam load.

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13.0 Monitoring Load Data

June 17, 2009

Maximum Load Units of Measure Code
Element Name: MaximumLoadUnitsOfMeasureCode
Identify the type of load information reported in this record by using the appropriate uppercase
codes as shown in Table 56. Note that you must use the same units of measure as will be used to
report hourly load.

Table 56
Maximum Load Value Codes and Descriptions
Code

Description

MW

Electrical Capacity (in megawatts)

KLBHR

Steam (load) Mass Rate (in units of
1000 lbs/hr)

MMBTUHR

BTUs of Steam Produced (in
mmBtu/hr)

Note: Leave this field blank for units that do not produce electrical or steam load.

Lower Operation Boundary
Element Name: LowerOperationBoundary
This value is required for all units and all additional monitoring locations where load-based
missing data are used. Report the lower boundary of the range of operation for units that
produce electrical or steam load, in units of megawatts, 1000 lb/hr of steam or mmBtu/hr of
steam, as appropriate.
For single units (including units that have a multiple stack exhaust configuration), report the
minimum safe, sustainable load for the unit.
For a common stack (or pipe), report the lowest safe, sustainable load for any of the units using
the stack (or pipe) as the lower boundary of the range of operation. Alternatively, for frequently
operated units discharging to a common stack (or using a common pipe), the sum of the
minimum safe, stable loads of the units serving the common stack (or pipe) may be reported as
the lower boundary of the operating range.
For multiple stacks, report, the minimum safe, stable load for the associated unit.
For non load-based units, report the lower boundary of the range of operation in terms of stack
gas velocity (ft/sec), as described in Section 6.5.2.1(a) of Appendix A.

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Upper Operation Boundary
Element Name: UpperOperationBoundary
This value is required for all units and all additional monitoring locations where load-based
missing data are used. Report the upper boundary of the range of operation for units that
produce electrical or steam load, in units of megawatts, 1000 lb/hr of steam, or mmBtu/hr of
steam, as appropriate. The upper boundary of the range of operation must be equal to or less
than the maximum hourly gross load reported in the Maximum Load Value.
Report the maximum sustainable load for single units (including units that have a multiple stack
exhaust configuration), to either: (1) the nameplate capacity of the unit (less any physical or
regulatory deratings); or (2) the highest sustainable load, based on a minimum of four
representative quarters of historical operating data.
Report the sum of the maximum sustainable loads of all units using the stack (or pipe) for a
common stack (or pipe), as the upper boundary of the range of operation. If that combined load
is unattainable in practice, report the highest sustainable combined load, based on a minimum of
four representative quarters of historical operating data.
For multiple stacks, report the maximum sustainable load for the associated unit.
For non load-based units, report the upper boundary of the range of operation in terms of stack
gas velocity (ft/sec), as described in Section 6.5.2.1(a) of Appendix A.
Normal Level Code
Element Name: NormalLevelCode
This value is required for all units and all additional monitoring locations where load-based
missing data are used, except for peaking units or stacks linked to peaking units. Designate and
report the most frequently used load level ("L," "M," or "H") as the "normal" load level for units
that produce electrical or steam load, based upon the results of the historical load data analysis
described in Section 6.5.2.1(c) of Appendix A. For all SO2, NOx, and flow RATAs conducted at
the designated normal load, a bias test is required.
For non load-based units, designate the normal operating level based on knowledge of the unit
and operating experience with the industrial process.
Second Level Code
Element Name: SecondLevelCode
This value is required for all units and all additional monitoring locations where load-based
missing data are used, except for peaking units or stacks linked to peaking units. Report the
second most frequently used level based on the results of the historical load data analysis
described in Section 6.5.2.1(c) of Appendix A (for units that produce electrical or steam load),
or, based on knowledge of the unit and operating experience with the industrial process (for non
load-based units).

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13.0 Monitoring Load Data

June 17, 2009

Second Normal Indicator
Element Name: SecondNormalIndicator
This value is required for all units and all additional monitoring locations where load-based
missing data are used, except for peaking units or stacks linked to peaking units. For units that
produce electrical or steam load, based upon the results of the historical load data analysis, the
second most frequently used load level may be elected to be designated as an additional normal
load level. If you wish to designate the second most frequently used operating level as a second
normal level, report "1" for this element. Otherwise, report "0". Note that if you designate the
second level as a normal level, you must perform a bias test for all SO2, NOx, and flow RATAs
conducted at this load level.
For non load-based units, a second normal operating level may be designated, based on
knowledge of the unit and operating experience with the industrial process.
Load Analysis Date
Element Name: LoadAnalysisDate
Report the year, month and day of the historical load data analysis (see Sections 6.5.2.1 (c) and
(d) of Appendix A) that defines the two most frequently used load levels, and the normal load
level(s) for units that produce electrical or steam load.
Leave this field blank for new units since no load analysis has yet been completed.
Leave this field blank for non load-based units.
Begin Date
Element Name: BeginDate
Report the date on which the load information became effective. For the initial load analysis at a
particular unit or stack, report the Begin Date as the first day of the quarter in which the data
analysis was performed (i.e., 2005-01-01 or 2005-04-01, etc.), rather than the actual date of the
analysis unless the two dates are the same. For records created to indicate a change to the load
information, this date should equal the load analysis date if the change is based on a new load
analysis. But, if you are simply electing to add a second normal load or to make minor
adjustments to the boundaries of the operating range, or updating other information that is not
dependent on the load analysis, the Begin Date may be later than the load analysis date.
For peaking units, report the later of: (a) the date of program participation; or (b) the date on
which peaking status was first claimed for the unit.
For non load-based units, report the date on which the determination of the operating range, the
most frequent operating level(s), and the normal operating level(s) is made.
Begin Hour
Element Name: BeginHour
Report the hour in which the load information became effective.
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13.0 Monitoring Load Data

End Date
Element Name: EndDate
Report the last date on which the load information was in effect. Report an end date only when
another MONITORING LOAD DATA record will be reported to provide a change to one or more
data elements, either because a new historical load data analysis was performed which indicated
a change, or because you elect to change the second normal load designation or the range of
operation. When this occurs, submit one MONITORING LOAD DATA record with the results of the
previous load data analysis and report the end date in this field. Submit a second MONITORING
LOAD DATA record with the results of the new load data analysis or choice, leaving this field
blank (see "Specific Considerations" below).
For non load-based units, report an end date only when a change in the manner of unit or process
operation results in a change in the operating range and/or the most frequently-used operating
levels, and/or the designated normal operating level(s). Should this occur, submit two
MONITORING LOAD DATA records, one to deactivate the old information, and one to activate the
new information, as described immediately above for load-based units.
End Hour
Element Name: EndHour
Report the last date on which the load information was in effect. This value should be left blank
for active records.
Specific Considerations
Range of Operation for Electrical or Steam Load Units and Non Load-Based Units
● MONITORING LOAD DATA defines the upper and lower boundaries of the "range of
operation" for the unit (or units, for a common stack or pipe). For units that produce
electrical or steam load, the range of operation extends from the minimum safe, stable
operating load to the maximum sustainable load, and provides the basis for defining the
low, mid, and high operating load levels. For non load-based units (e.g., cement kilns,
refinery process heaters, etc.), the range of operation extends from the minimum potential
stack gas velocity, in ft/sec (or, alternatively, from 0.0 ft/sec) to the maximum potential
velocity.
Purpose of Historical Load Data Analysis
● MONITORING LOAD DATA is also used to report the results of an analysis of historical load
data for the unit or stack, as described in Part 75 (see Section 6.5.2.1(c) of Appendix A).
The results of the historical load data analysis provide the basis for: (1) defining the
normal operating load level (or levels) for the unit or stack; (2) determining the two
appropriate load levels at which to conduct annual two-load flow RATAs; (3)
determining, for multi-load flow RATAs, the two appropriate load levels at which to
calculate bias adjustment factors, when a normal load bias test is failed; and (4)
determining the appropriate load level at which to conduct the quarterly flow-to-load
ratio test. Note that for peaking units, the historical load data analysis is not required.
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13.0 Monitoring Load Data

June 17, 2009

Historical Load Data Analysis for Non Load-Based Units
● Non load-based units are exempted from the historical load data analysis in Section
6.5.2.1 (c) of Appendix A. For these units, the most frequently used operating levels and
the normal operating level(s) are determined by the owner or operator, using sound
engineering judgment, based on operating experience with the unit and knowledge of the
industrial process.
Upper and Lower Boundaries for New or Newly-Affected Units
● For new or newly-affected units, in the initial monitoring plan submittal, use the best
available estimates of the upper and lower boundaries of the range of operation and
determine the normal load (or operating level) and the two most frequently-used load (or
operating) levels based on the anticipated manner of operating the unit. Report the date
of submittal of the initial monitoring plan or the date on which commercial operation of
the unit begins (whichever is earlier) in the Begin Date field.
Updating the MONITORING LOAD DATA Record
When the manner of operating the unit(s) changes significantly, update the information in
MONITORING LOAD DATA by submitting two MONITORING LOAD DATA records. First, close out
the existing monitor load record by entering an end date and hour. Next, create a new monitor
load record indicating the Begin Date and Hour for the new record.
In order to correct a previously submitted record that contains erroneous information, resubmit
the MONITORING LOAD DATA record with the corrected information. For example, if the Normal
Level Code was previously submitted as "H" (for high-load) when the normal load level should
have be "M" (for mid-load), the record should be updated and resubmitted. Note that the
BeginDate and BeginHour elements should not be updated, unless the BeginDate and/or
BeginHour are the elements to be corrected.
Once the operating range and normal load level(s) have been established, Part 75 does not
require repeating the historical load analysis unless a significant change in the manner of unit
operation occurs, which may result in a re-designation of the operating range and/or the normal
load level(s) and/or the two most frequently used load levels. At least two quarters of
representative data are required to document that such a change in unit operation has occurred.
If such a change has been determined, establish the new load information by creating a new
MONITORING LOAD DATA record with the new information, and report the old record with the
appropriate End Date and End Hour (which must be just prior to the Begin Date and Begin Hour
of the new record).
If, however, you elect to repeat the load analysis periodically, e.g., prior to each annual RATA,
in order to confirm that nothing has changed (this is good practice, even though this is not
required by the regulation), do not change the Begin Date unless the new data analysis shows
that a re-designation of the operating range and/or the normal load and/or the two most
frequently-used load levels is necessary.

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13.0 Monitoring Load Data

For peaking units, if peaking status is lost at the end of a year or ozone season, the MONITORING
LOAD DATA record information must be deactivated as of December 31 (for a year-round
reporter) or September 30 (for an ozone season-only reporter) of that year. Then, you must
perform a historical load analysis and activate a new MONITORING LOAD DATA record, as
described in the Load Analysis data element instructions above.
When transitioning from non-peaking status to peaking unit status at the beginning of a new
calendar year or ozone season, deactivate the existing MONITORING LOAD DATA record, as of
December 31 of the previous year (for a year-round reporter) or September 30 of the previous
year (for an ozone season-only reporter). Then, activate a new MONITORING LOAD DATA record,
as of January 1 of the current year (for a year-round reporter) or October 1 of the previous year
(for an ozone season-only reporter). A new load analysis is not required, because the whole
operating range is considered normal for a peaking unit. Therefore, in the new MONITORING
LOAD DATA record, leave Normal Level Code through Second Level Indicator data elements
blank. A MONITORING QUALIFICATION PERCENT DATA record must also be submitted, to claim
peaking unit status.

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14.0 Monitoring Qualification Data

June 17, 2009

14.0 MONITORING QUALIFICATION DATA
Figure 24
MONITORING QUALIFICATION DATA XML Elements

Description of Data
Report a MONITORING QUALIFICATION DATA record for a unit for which qualification is sought
as a gas-fired unit or a peaking unit, or to use the low mass emissions (LME) monitoring and
reporting provisions in §75.19. A separate record must be submitted for each type of
qualification sought. For example, two separate record sets must be submitted for a single unit to
indicate both gas-fired and peaking unit status. Also include the appropriate Monitoring
Qualification records providing the historical or projected information to demonstrate peaking,
gas-fired, or LME status. See instructions for MONITORING QUAL LME DATA and MONITORING
QUAL PERCENT DATA for more information.
To indicate that a unit or stack has an approved petition to perform flow RATAs at only a single
load or two loads, report this record with applicable Qual Type Code (PRATA1 or PRATA2).
Dependencies for MONITORING QUALIFICATION DATA
The MONITORING QUALIFICATION DATA record is dependent on the UNIT DATA record or the
STACK PIPE DATA record.
The following complex elements specify additional qualification data and are dependent on the
MONITORING QUALIFICATION DATA record:
● MONITORING QUAL LME DATA
● MONITORING QUAL PERCENT DATA
The complex elements cannot be submitted for a monitoring plan unless an applicable
MONITORING QUALIFICATION DATA record is included.

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14.0 Monitoring Qualification Data

MONITORING QUALIFICATION DATA Elements
Instructions for completing each element of the MONITORING QUALIFICATION DATA section are
provided below:
Qualification Type Code
Element Name: QualificationTypeCode
Report a code from the Table 57 specifying the type of qualification being sought:

Table 57
Qualification Type Codes and Descriptions
Category

Code

Description

Gas-Fired

GF

Gas-Fired Qualification

Low Mass Emitter

LMEA

Low Mass Emitter Qualification (Annual) -- Required
when reporting on a year-round basis

LMES

Low Mass Emitter Qualification (Ozone Season) -Required when subject to an Ozone-Season NOx program

PK

Peaking Unit Qualification (Annual)

SK

Peaking Unit Qualification for Ozone Season (applies
exclusively to sources that report on an ozone season-only
basis)

PRATA1

Single Load RATA Qualification by petition approval

PRATA2

Two Load RATA Qualification by petition approval

COMPLEX

Exemption from Flow-to-Load Testing Due to Complex
Configuration

LOWSULF

SO2 RATA Exemption for a Source Combusting Only
Very Low Sulfur Fuel

Peaking

QA Test Exemption

Begin Date
Element Name: BeginDate
Report the date on which qualification will become effective.
For gas-fired and peaking unit qualifications and for LME qualifications, this should equal the
first date on which the qualification is needed for monitoring and reporting purposes. It must be
no later than the begin date of any MONITORING METHOD DATA record that depends on the
qualification.
For Flow RATA qualifications, this date should be equal to or earlier than the first RATA which
relies on the petition provisions.

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June 17, 2009

For Flow-to-Load exemptions, this date should be equal to the completion date of the first flow
RATA that qualifies for the exemption.
End Date
Element Name: EndDate
If applicable, report the date on which the qualification ended.
For gas-fired and peaking unit qualifications and for LME qualifications, this would be the last
day of the calendar year (or ozone season) in which the qualification was lost. This date triggers
the requirement to meet new monitoring and reporting requirements within the specified time
allowed by Part 75.

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June 17, 2009

14.1 MONITORING QUAL LME DATA
Figure 25
MONITORING QUAL LME DATA XML Elements

Description of Data
Report MONITORING QUALIFICATION DATA records to provide the initial evidence that a unit
qualifies for low mass emissions (LME) status. If the unit reports on a year-round basis, report a
MONITORING QUALIFICATION DATA record with a QualificationTypeCode of "LMEA" and three
supporting MONITORING QUAL LME DATA records (one for each required
QualificationDataYear). If the unit is subject to an ozone-season NOx program (e.g., CAIROS,
NBP, etc.), report a MONITORING QUALIFICATION DATA record with a QualificationTypeCode of
"LMEA" and three supporting MONITORING QUAL LME DATA records (one for each required
QualificationDataYear).
If the unit reports on a year-round basis, and is also subject to an ozone-season NOx program, the
unit must report both sets of records and meet both the annual and ozone-season emissions limits
to qualify for LME status.
See Table 58 for more information about which MONITORING QUALIFICATION DATA records to
report and which elements must be filled out in the associated MONITORING QUAL LME DATA
records.

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14.1 Monitoring Qual LME Data

Table 58
Data Requirements for Monitoring Qual LME
Linked to MONITORING QUALIFICATION DATA
Record with QualificationTypeCode:
LMEA
Reporting
Frequency
Annual

Ozone Season
Only

LMES

SO2
Tons

NOx
Tons

Subject to Acid Rain
Program (or CAIRSO2 plus
CAIRNOX), but not subject
to Ozone Season NOx
Program





Subject to Acid Rain
Program (or CAIRSO2 plus
CAIRNOX), and also subject
to Ozone Season NOx
Program





Subject to CAIRSO2, but not
subject to any NOx Program



--

Subject to Ozone Season
NOx program and reporting
year-round, but not subject to
CAIRSO2

--



Subject to CAIRNOX, but
not subject to CAIRSO2 or
Ozone Season NOx program

--



Program Applicability

Subject to Ozone Season
NOx program and reporting
during Ozone Season only

SO2
Tons

NOx
Tons

Do not report LMES
record

Do not report LMEA
record

--



Do not report LMES
record
--



Do not report LMES
record
--



Dependencies for MONITORING QUAL LME DATA
The MONITORING QUAL LME DATA record is dependent on the MONITORING QUALIFICATION
DATA record.
No other records are dependent upon the MONITORING QUAL LME DATA record.

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14.1 Monitoring Qual LME Data

June 17, 2009

MONITORING QUAL LME DATA Elements
Instructions for completing each element of the MONITORING QUAL LME DATA section are
provided below:
Qualification Data Year
Element Name: QualificationDataYear
Report the calendar year used for the measured, estimated, or projected SO2 and/or NOx mass
emissions.
Operating Hours
Element Name: OperatingHours
Report the number of unit operating hours (as defined in §72.2) for the Qualification Data Period
(i.e., full year or ozone season) in the Qualification Data Year.
SO2 Tons
Element Name: SO2Tons
If this record is linked to a MONITORING QUALIFICATION DATA record with a
QualificationTypeCode of "LMEA", and the unit is subject to an SO2 program, report the SO2
mass emissions for the Qualification Data Year based on either measured or estimated SO2 mass
emissions or projected SO2 mass emissions, as appropriate according to § 75.19. Round and
report this value to one decimal place.
Otherwise, leave this field blank.
NOx Tons
Element Name: NOxTons
If this record is linked to a MONITORING QUALIFICATION DATA record with a
QualificationTypeCode of "LMEA", and the unit is subject to a NOx program and is reporting
year-round, report the annual NOx mass emissions for the Qualification Data Year based on
either measured or estimated NOx mass emissions or projected NOx mass emissions, as
appropriate according to §75.19. Round and report this value to one decimal place.
If this record is linked to a MONITORING QUALIFICATION DATA record with a
QualificationTypeCode of "LMES", and the unit is subject to an ozone-season NOx program,
report the seasonal NOx mass emissions for the Qualification Data Year based on either
measured or estimated NOx mass emissions or projected NOx mass emissions, as appropriate
according to §75.19. Round and report this value to one decimal place.
Otherwise, leave this field blank.

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14.1 Monitoring Qual LME Data

Specific Considerations
SO2 Mass Emissions Reduction Program Units
● Use this record type to qualify as a low mass emissions unit by demonstrating that the
unit emits no more than 25 tons of SO2 per year.
NOx Mass Emissions Reduction Program Units
● For a unit subject to a program with a seasonal NOx emission cap, use this record type to
qualify as a low mass emissions unit by demonstrating that the unit emits no more than
50 tons of NOx per ozone season.
● For a unit that reports NOx mass emission data year-round, use this record to qualify as a
low mass emissions unit by demonstrating that the unit emits < 100 tons of NOx per year.
Data Projections
Projections may be used, as necessary, for Year 1, Year 2, or Year 3 (or for Ozone Season 1, 2,
or 3), when:
● Actual measured data (e.g., EDR reports) or reasonable estimates of actual emissions
derived from other sources (e.g., Part 60 monitoring data, process operating data, fuel
usage records, etc.) are not available (e.g., for a new unit);
● One or more of the past three years is not representative of current unit operation (e.g., if
controls were recently installed); or
● The owner or operator takes a federally enforceable permit restriction on unit operating
hours.
Historical Data
● If only historical data are being used to qualify, Year 1 would be three years before the
Qualification Data Year (i.e., the year of the LME application (see §75.19(a)(2)).
● If only projected data are being used, Year 1 would be the calendar year of the
Qualification Data Year (i.e., the year of the LME application).
● If only historical data are being used, Year 3 would be one year before the Qualification
Data Year or if only projected data were being used, Year 3 would be two years after the
Qualification Data Year (i.e., the year of the LME application).
● The appropriate calendar years for Ozone Seasons 1, 2, and 3 are determined in a similar
manner.

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14.1 Monitoring Qual LME Data

June 17, 2009

LME Attainment Failure
● If a qualifying LME unit emits more than the allowable number of tons of SO2 or NOx in
a particular year or ozone season, the unit loses its LME status. Should this occur, the
owner or operator must install and certify monitoring systems in a timely manner, as
described in §75.19(b)(2).
● If LME status is lost, update the MONITORING QUALIFICATION DATA record by
completing the end date. Also submit a MONITORING METHOD DATA record indicating
changes in monitoring methodologies with the appropriate effective dates.
LME Emission Testing
● For information on emission testing of a group of identical LME units, refer to the UNIT
DEFAULT TEST SUMMARY DATA record instructions in the QA Certification Data section
of the reporting instructions.
Updating the MONITORING QUAL LME DATA Record
This record is not designed to be updated from year to year. Rather, ongoing LME status is
demonstrated by the cumulative SO2 and NOx mass emissions reported in the hourly emissions
records. Changes to this data should only be necessary if the unit loses its LME status or needs
additional qualification records based on a change in program applicability or a change in
reporting frequency.

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June 17, 2009

14.2 MONITORING QUAL PERCENT DATA
Figure 26
MONITORING QUAL PERCENT DATA XML Elements

Description of Data
Report this record in conjunction with the MONITORING QUALIFICATION DATA record to support
the qualifications of a peaking unit or gas-fired unit. For any year or ozone season in which a
unit qualifies as a peaking or gas-fired unit, submit a MONITORING QUAL PERCENT DATA record
documenting the capacity or fuel usage of the unit during a three year period. "Peaking unit" is
defined in 40 CFR 72.2 for an annual basis and is described in 40 CFR 75.74(c)(11) for an ozone
season basis. "Gas-fired" is defined in 40 CFR 72.2. Do this for any regulatory purpose (i.e.,
either for the selection of monitoring methodology, exemption from multi-load testing, or
frequency of on-going QA/QC activities).
Dependencies for MONITORING QUAL PERCENT DATA
The MONITORING QUAL PERCENT DATA record is dependent on the MONITORING QUALIFICATION
DATA record.
No other records are dependent upon the MONITORING QUAL PERCENT DATA record.

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14.2 Monitoring Qual Percent Data

MONITORING QUAL PERCENT DATA Elements
Instructions for completing each element of the MONITORING QUAL PERCENT DATA section are
provided below:
Qualification Year
Element Name: QualificationYear
Report the year for which qualification is sought.
Average Percentage Value
Element Name: AveragePercentageValue
Report the average of the three years' Percentage Values.
Year 1 Qualification Data Year
Element Name: Yr1QualificationDataYear
Report the calendar year or season represented by Year 1.
Year 1 Qualification Data Type Code
Element Name: Yr1QualificationDataTypeCode
Report one of the following codes that describe the type of percent data for Year 1 supporting
qualification as a peaking unit or gas-fired unit:

Table 59
Qualification Data Type Code and Descriptions
Code

Description

A

Actual Percent Capacity Factor or Fuel
Usage

P

Projected Capacity Factor or Fuel
Usage

D

720 Hours of Unit Operating Data
(gas-fired only)

Year 1 Percentage Value
Element Name: Yr1PercentageValue
Report the percent capacity factor or the percent of heat input from gaseous fuel for Year 1.

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14.2 Monitoring Qual Percent Data

June 17, 2009

Year 2 Qualification Data Year
Element Name: Yr2QualificationDataYear
Report the calendar year or season represented by Year 2.
Year 2 Qualification Data Type Code
Element Name: Yr2QualificationDataTypeCode
Report one of the codes from Table 59, above, that describes the type of percent data for Year 2
supporting qualification as a peaking unit or gas-fired unit:
Year 2 Percentage Value
Element Name: Yr2PercentageValue
Report the percent capacity factor or the percent of heat input from gaseous fuel for Year 2.
Year 3 Qualification Data Year
Element Name: Yr3QualificationDataYear
Report the calendar year or season represented by Year 3.
Year 3 Qualification Data Type Code
Element Name: Yr3QualificationDataTypeCode
Report one of the codes from Table 59, above, that describes the type of percent data for Year 3
supporting qualification as a peaking unit or gas-fired unit:
Year 3 Percentage Value
Element Name: Yr3PercentageValue
Report the percent capacity factor or the percent of heat input from gaseous fuel for Year 3.

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14.2 Monitoring Qual Percent Data

Specific Considerations
Qualifying Using Historical and/or Projected Data
● Provide three years of historical percent capacity factor or fuel usage information using
projected data as provided for in the definitions of gas-fired and peaking unit in §72.2.
● For a unit in a NOx mass emissions reduction program reporting on an ozone season-only
basis, provide ozone season capacity factor information for the period from May 1
through September 30 of each year. Year 1 should be the earliest year for which data are
reported (for example, if all historical data are being used, Year 1 would be three years
before the current calendar year or, if all projected data were being used, Year 1 would be
the current calendar year). Similarly, Year 3 should be the last year for which data are
reported (for example, if all historical data are being used, Year 3 would be one year
before the current calendar year or if all projected data were being used, Year 3 would be
two years after the current calendar year).
● Calculate the three year average annual capacity factor or percentage of the annual heat
input (HI) from the combustion of gaseous fuel, by averaging the percent capacity factor
(or percent of HI from gaseous fuel) for the three years of data provided. For example, if
a unit has operated for three years at 6.0 percent, 10.0 percent, and 12.0 percent annual
capacity factor, report each of these values as a Percentage Value element.

Table 60
Example Data for Qualification Based on
Historical and Projected Data
Initial
Qualifying
Methodology
Actual Historical
Data

Data Reported in MONITORING QUAL PERCENT DATA Record
Current
Year

Type*

Year 1

Type*

Year 2

Type*

Year 3

2000

1997

A

1998

A

1999

A

2001

1998

A

1999

A

2000

A

2002

1999

A

2000

A

2001

A

2000

2000

P

2001

P

2002

P

2001

2000

A

2001

P

2002

P

2002

2000

A

2001

A

2002

P

2003

2000

A

2001

A

2002

A

Combination of
2001
Actual Historical
Data and Projected 2002
Data
2003

2000

A

2001

P

2002

P

2000

A

2001

A

2002

P

2000

A

2001

A

2002

A

Projected Data

* A = Actual historical data; P = Projected data

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14.2 Monitoring Qual Percent Data

June 17, 2009

Peaking and Gas-Fired Unit Qualification
● If reporting to qualify both as a peaking unit and as a gas-fired unit, submit two
MONITORING QUALIFICATION DATA records, one with QualificationTypeCode of GF
(gas-fired) and one with QualificationTypeCode of PK or SK. With each, report the
appropriate MONITORING QUAL PERCENT DATA record to demonstrate that the unit meets
the gas-fired or peaking unit criteria.
Qualifications for Gas-Fired Units
● In accordance with paragraph (3)(ii)(B) of the "gas-fired" definition in §72.2, 720 hours
of unit operating data may be provided to initially qualify as a gas-fired unit, if the
designated representative certifies that the pattern of fuel usage has permanently changed.
● A unit is classified as gas-fired as of the date on which the results of the 720 hour
demonstration are submitted to the Administrator (see paragraph (3)(iii) of "gas-fired"
definition). The 720 hour demonstration data qualifies a unit as gas-fired from the date
on which the results of the demonstration are submitted until the end of that same
calendar year.
● For the next year, actual, historical fuel usage data must be submitted from the previous
year (beginning with the date on which gas-fired qualification was first met) to verify that
fuel usage requirements were met for the first reporting year.
● For example, if qualified based on the 720 hour demonstration as of June 30, 2000, then,
in 2001, historical data must be submitted for the time interval from June 30, 2000
through December 31, 2000 (labeled as Year 1). In 2002, historical data would be
submitted for 2000 (labeled as Year 1) and 2001 (labeled as Year 2). In 2003, historical
data would be submitted for 2000, 2001, and 2002, labeled as Year 1, Year 2, and Year 3,
respectively (see Table 61, below).

Table 61
Example of Gas-Fired Qualification Based onUnit Operating Data
Initial
Qualifying
Methodology

Data Reported in MONITORING QUAL PERCENT DATA Record
Current
Year

Year 1

Type

Year 2

Type

Year 3

Type

Qualifying Based
on 720 Hours of
Unit Operating
Data

2000

2000

D**

2001

P

2002

P

2001

2000

A

2001

P

2002

P

2002

2000

A

2001

A

2002

P

After the first
year, available
historical data
must be provided.

2003

2000

A

2001

A

2002

A

** Initial qualification based on 720 hours of unit operating data
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14.2 Monitoring Qual Percent Data

Initial and Subsequent Qualification
● It is possible a unit may initially qualify as a gas-fired or peaking unit by using historical
data or projected data. A combination of historical and projected data may be used.
However, to maintain peaking unit or gas-fired unit status, actual capacity factor or fuel
usage data for each subsequent year must be reported. Thus, if the basis for qualifying in
the first reporting year is on three years of projections, it is not possible to re-qualify in
the second reporting year based solely on projections. The qualifying data for the second
reporting year must include the actual capacity factor or fuel usage data from the first
reporting year.
Loss of Status
● If, after evaluating the capacity factor or fuel usage data for a particular reporting year,
the unit no longer qualifies as a peaking or gas-fired unit, update the MONITORING QUAL
DATA record by reporting the appropriate End Date, to indicate that the peaking or gasfired unit status has been lost.
● If a unit has previously qualified as a peaking or gas-fired unit but has lost that status and
re-establishing peaking or gas-fired status is wished, the unit may only re-qualify based
on three years of actual historical data. The use of projections is disallowed in such cases
(see §72.2, paragraph (4) of "gas-fired" definition and paragraph (3) of the "peaking unit"
definition).
Updating the MONITORING QUAL PERCENT DATA Record
For each unit, as applicable, add another MONITORING QUAL PERCENT DATA record at the
beginning of each calendar year (for year-round reporters) or at the start of the ozone season (for
ozone season-only reporters) to demonstrate on-going qualification, based on the previous year
(or ozone season) of historical data.

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