ECMPS Reporting
Monitoring
Instructions
Plan
United States Environmental Protection Agency
Office of Air and Radiation
Clean Air Markets Division
1201 Constitution Ave, NW
Washington, DC 20004
September 11, 2019
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Monitoring Plan Reporting Instructions
Table of Contents
Table of Contents
Page
I.0 Introduction: The Monitoring Plan 1
2.0 Monitoring Plan (Root Element) 4
2.1 Monitoring Plan Comment Data 5
2.2 Unit Stack Configuration Data 6
2.3 Monitoring Location Data 8
3.0 Stack Pipe Data 9
4.0 Unit Data 12
4.1 Unit Capacity Data 15
4.2 Unit Control Data 17
4.3 Unit Fuel Data 21
5.0 Monitoring Location Attribute Data 24
6.0 Monitoring Method Data 27
6.1 Supplemental MATS Monitoring Method Data 36
7.0 Component Data 40
7.1 Analyzer Range Data 47
8.0 Monitoring System Data 49
8.1 Monitoring System Fuel Flow Data 58
8.2 Monitoring System Component Data 60
9.0 Monitoring Formula Data 62
10.0 Monitoring Default Data 90
II.0 Monitoring Span Data 105
12.0 Rectangular Duct WAF Data 114
13.0 Monitoring Load Data 118
14.0 Monitoring Qualification Data 125
14.1 Monitoring Qual LME Data 128
14.2 Monitoring Qual Percent Data 133
14.3 Monitoring Qual LEE Data 138
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Table of Contents
List of Tables
Page
Table 1: Stack Pipe ID Prefixes 9
Table 2: Parameter Codes and Descriptions 18
Table 3: Control Codes and Descriptions 18
Table 4: Unit Fuel Codes and Descriptions 21
Table 5: Unit Fuel Indicator Codes and Descriptions 22
Table 6: Demonstration Method to Qualify for Monthly Fuel Sampling for GCV Codes and
Descriptions 23
Table 7: Demonstration Method to Qualify for Daily or Annual Fuel Sampling for %S (ARP)
Codes and Descriptions 23
Table 8: Duct/Stack Material Codes and Descriptions 25
Table 9: Duct/Stack Shape Codes and Descriptions 25
Table 10: Parameter Codes and Descriptions for Monitoring Methods 28
Table 11: Measured Parameters and Applicable Monitoring Methods 29
Table 12: Substitute Data Codes and Descriptions 32
Table 13: Bypass Approach Codes and Descriptions 32
Table 14: Supplemental MATS Parameter Codes 37
Table 15: Supplemental MATS Measured Parameters and Applicable Monitoring Methods 37
Table 16: Component Type Codes and Descriptions 41
Table 17: Sample Acquisition Method Codes for Components 43
Table 18: Moisture Basis Codes and Descriptions for CEM Analyzer and Sorbent Trap Sampling
Train Components 44
Table 19: Analyzer Range Codes and Descriptions 47
Table 20: System Type Codes and Descriptions 50
Table 21: System Designation Codes and Descriptions 51
Table 22: Monitoring System Fuel Codes and Descriptions 52
Table 23: Units of Measure for Maximum Fuel Flow Rate Codes and Descriptions 59
Table 24: Parameter Codes and Descriptions for Monitoring Formula 63
Table 25: F-Factor* Reference Table 66
Table 26: SO2 Formula References 68
Table 27: SO2 Emissions Formulas 68
Table 28: SO2 Emission Rate Formula Reference Table for the MATS Rule 70
Table 29: SO2 Emission Formulas for the MATS Rule 70
Table 30: NOx Emission Rate Formula Reference Table 71
Table 31: NOx Emission Rate Formulas (lb/mmBtu) 72
Table 32: Hg Emission Formula Reference Table for the MATS Rule 73
Table 33: Hg Emissions Formulas for the MATS Rule 73
Table 34: HC1 Emission Rate Formula Reference Table for the MATS Rule 75
Table 35: HC1 Emission Formulas for the MATS Rule 75
Table 36: HF Emission Rate Formula Reference Table for the MATS Rule 76
Table 37: HF Emission Formulas for the MATS Rule 77
Table 38: Moisture Formulas* 78
Table 39: CO2 Formula Reference Table 78
Table 40: CO2 Concentration and Mass Emission Rate Formulas 79
Table 41: Heat Input Formula Reference Table 82
Table 42: Heat Input Formulas 82
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Table of Contents
Table 43: Apportionment and Summation Formulas 84
Table 44: NOx Mass Emissions Formulas (lbs/hr) 85
Table 45: Miscellaneous Formula Codes 85
Table 46: Representations for Electronic Reporting of Formulas 87
Table 47: Parameter Codes and Descriptions for Monitoring Default 93
Table 48: Rounding Rules for Default Values 94
Table 49: Fuel-Specific Minimum Default Moisture Values for SO2, NOx, CO2, and Heat Input
Rate Calculations 96
Table 50: Fuel-Specific Maximum Default Moisture Values for NOx Emission Rate Calculations
96
Table 51: NOx Emission Factors (lb/mmBtufor Low Mass Emissions Units) 97
Table 52: SO2 Emission Factors (lb/mmBtu) for Low Mass Emissions Units 97
Table 53: CO2 Emission Factors (ton/mmBtu) for Low Mass Emissions Units 97
Table 54: Units of Measure Codes by Parameter 98
Table 55: Default Purpose Codes and Descriptions 98
Table 56: Monitoring Default Fuel Codes and Descriptions 99
Table 57: Monitoring Default Operating Condition Codes and Descriptions 102
Table 58: Default Source Codes and Descriptions 103
Table 59: Component Type Codes and Descriptions for Monitor Span 106
Table 60: Provision for Calculating MPC/MEC/MPF Codes and Descriptions 106
Table 61: Criteria for MPC/MEC/MPF Determinations 108
Table 62: Flow Span Calibration Units of Measure Ill
Table 63: WAF Method Code and Descriptions 116
Table 64: Maximum Load Value Codes and Descriptions 119
Table 65: Qualification Type Codes and Descriptions 126
Table 66: Data Requirements for Monitoring Qual LME 129
Table 67: Qualification Data Type Codes and Descriptions 134
Table 68: Example Data for Qualification Based on Historical and Projected Data 135
Table 69: Example of Gas-Fired Qualification Based on Unit Operating Data 136
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Table of Contents
List of Figures
Page
Figure 1: Monitoring Plan XML Schema Complex Elements 3
Figure 2: Monitoring Plan XML Elements 4
Figure 3: Monitoring Plan Comment Data XML Elements 5
Figure 4: Unit Stack Configuration Data XML Elements 6
Figure 5: Monitoring Location Data Elements 8
Figure 6: Stack Pipe Data Elements 10
Figure 7: Unit Data XML Elements 13
Figure 8: Unit Capacity Data XML Elements 15
Figure 9: Unit Control Data XML Elements 17
Figure 10: Unit Fuel Data XML Elements 21
Figure 11: Monitoring Location Attribute Data XML Elements 24
Figure 12: Monitoring Method Data XML Elements 28
Figure 13: Supplemental MATS Monitoring Method Data XML Elements 36
Figure 14: Component Data XML Elements 40
Figure 15: Analyzer Range Data XML Elements 47
Figure 16: Monitoring System Data XML Elements 49
Figure 17: Monitoring System Fuel Flow Data XML Elements 58
Figure 18: Monitoring System Component Data XML Elements 60
Figure 19: Monitoring Formula Data XML Elements 62
Figure 20: Monitoring Default Data XML Elements 92
Figure 21: Monitoring Span Data XML Elements 105
Figure 22: Rectangular Duct WAF Data XML Elements 115
Figure 23: Monitoring Load Data XML Elements 118
Figure 24: Monitoring Qualification Data XML Elements 125
Figure 25: Monitoring Qual LME Data XML Elements 129
Figure 26: Monitoring Qual Percent Data XML Elements 133
Figure 27: Monitoring Qual LEE Data XML Elements 139
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Monitoring Plan Reporting Instructions
1.0 Introduction: The Monitoring Plan
ECMPS Reporting Instructions
Monitoring Plan
1.0 Intrnitu ii »i I k \h 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 Cross-State Air Pollution Rule (CASPR);
3) The Mercury and Toxics Standards (MATS) Rule; and
4) 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. For each complex element, this document includes a separate section which includes:
• Element Overview: An overview of the kinds of data submitted under the element,
including general guidance not specific to any associated child complex elements or
simple elements
• Element XML Model: A model diagram of the element and any associated child
complex elements or simple elements
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Monitoring Plan Reporting Instructions
1.0 Introduction: The Monitoring Plan
• Element Dependencies: Description of dependent relationships for the element
• Element XML Elements: Instructions for submitting data for each associated simple
element
• Specific Considerations: Additional considerations, including information that applies
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
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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Monitoring Plan Reporting Instructions
1.0 Introduction: The Monitoring Plan
Figure 1: Monitoring Plan XML Schema Complex Elements
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Monitoring Plan Reporting Instructions
2.0 Monitoring Plan
2.0 Monitoring Plan
Monitoring Plan Overview
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.
Monitoring Plan X odd
Figure 2: Monitoring Plan XML Elements
Dependencies for Monitoring Plan
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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.
Monitoring Plan X ements
ORIS Code (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 (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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Monitoring Plan Reporting Instructions
2.1 Monitoring Plan Comment Data
2.1 Monitoring Plan Comment Data
Monitoring Plan Comment Data Overview
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.
Monitoring Plan Comment Data XML Model
Figure 3: Monitoring Plan Comment Data XML Elements
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 XML Elements
Monitoring Plan Comment (MonitoringPlanComment)
Report any comments concerning the monitoring plan.
Begin Date (BeginDate)
Report the date on which the comment became effective.
End Date (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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Monitoring Plan Reporting Instructions
2.2 Unit Stack Configuration Data
2.2 Unit Stack Configuration 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.
Unit Stack Configuration Data XML Model
Figure 4: Unit Stack Configuration Data XML Elements
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 XML Elements
Stack Pipe ID (StackPipelD)
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 (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.
Begin Date (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.
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Monitoring Plan Reporting Instructions 2.2 Unit Stack Configuration Data
End Date (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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Monitoring Plan Reporting Instructions
2.3 Monitoring Location Data
2.3 Monitoring Location Data
Monitoring Location, Data Overview
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.
Monitoring Location, Data XML Model
Figure 5: Monitoring Location Data Elements
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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 XML Elements
Stack Pipe ID (StackPipelD)
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.
Unit ID (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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Monitoring Plan Reporting Instructions
3.0 Stack Pipe Data
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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).
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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Monitoring Plan Reporting Instructions
3.0 Stack Pipe Data
Stack Pipe Data. XI Kiel
Figure 6: Stack Pipe Data Elements
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Dependencies for Stack Pine 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:
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3.0 Stack Pipe Data
• Monitoring Location Attribute 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 Pine Data XML Elements
Active Date (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 (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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Monitoring Plan Reporting Instructions
4.0 Unit Data
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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.
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4.0 Unit Data
Unit Data XML Model
Figure 7: Unit Data XML Elements
Unit Data
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4.0 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 XML Elements
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Non Load Based Indicator (NonLoadBasedlndicator)
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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Monitoring Plan Reporting Instructions
4.1 Unit Capacity Data
it Capacity Data
Unit Capacity Data Overview
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.
Unit Capacity Data XML Model
Figure 8: Unit Capacity Data XML Elements
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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 XML Elements
Maximum Hourly Heat Input Capacity (MaximumHourlyHeatlnputCapacity)
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 (BeginDate)
Report the date on which the reported maximum hourly heat input capacity for a unit became
effective.
End Date (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.
Derated Units
If a unit has been derated, report the derated maximum heat input capacity.
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4.1 Unit Capacity Data
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.
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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Monitoring Plan Reporting Instructions
4.2 Unit Control Data
4.2 Unit C ontrol Data
Unit Control Data Overview
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.
If emission controls that are specific to Hg, HC1 or HF removal are also in place or planned for a
unit, EPA recommends that you submit additional Unit Control Data records to represent
these controls. 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, S02, HG, HC1, HF, 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.
Unit Control Data XML Model
Figure 9: Unit Control Data XML Elements
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.
Unit Control Data, XML Elements
Parameter Code (ParameterCode)
Report the parameter being controlled by using one of the following uppercase codes as shown
in Table 2:
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4.2 Unit Control Data
Table 2: Parameter Codes and Descriptions
Code
Description
NOX
Nitrogen Oxides
S02
Sulfur Dioxide
PART
Particulates (opacity)
HG
Mercury
HCL
Hydrogen chloride
HF
Hydrogen fluoride
Control Code (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
Control
Code
Description
NOX
CM
Combustion Modification/Fuel Reburning
DLNB
Dry Low NOx Premixed Technology (turbines only)
H20
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 wall-
fired boilers, dry bottom turbo-fired boilers, or process heaters only)
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
0
Other
OFA
Overfire Air
SCR
Selective Catalytic Reduction
SNCR
Selective Non-Catalytic Reduction
STM
Steam Injection
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Monitoring Plan Reporting Instructions
4.2 Unit Control Data
Parameter
Control
Code
Description
S02
DA
Dual Alkali
DL
Dry Lime FGD
FBL
Fluidized Bed Limestone Injection
MO
Magnesium Oxide
0
Other
SB
Sodium Based
WL
Wet Lime FGD
WLS
Wet Limestone
PART
B
Baghouse(s)
ESP
Electrostatic Precipitator
HESP
Hybrid Electrostatic Precipitator
WESP
Wet Electrostatic Precipitator
WS
Wet Scrubber
0
Other
c
Cyclone
HG
UPAC
Injection of untreated powdered activated carbon (PAC) sorbents
HP AC
Injection of halogenated powdered activated carbon (PAC) sorbents
SB
Sodium Based
SORB
Injection of other (non-PAC) sorbents
APAC
Additives to enhance PAC and existing equipment performance
CAT
A catalyst (gold, palladium, or other) used to oxidize mercury
REAC
Regenerative Activated Coke Technology
HCL, HF
DSI
Dry Sorbent Injection
SB
Sodium Based
Original Code (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 (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.
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4.2 Unit Control Data
Optimization Date (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 (SeasonalControlsIndicator)
Report a "1" in the Seasonal Control Indicator field if the NOx control equipment is used only
during the ozone season. If not, report "0" (zero).
Retire Date (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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Monitoring Plan Reporting Instructions
4.3 Unit Fuel Data
4.3 Unit Fuel Data
Unit Fuel Data Overview
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.
Unit Fuel Data XML Model
Figure 10: Unit Fuel Data XML Elements
The Unit Fuel Data record is dependent on the Unit Data record.
No other records are dependent upon the Unit Fuel Data record.
Unit Fuel Data XML Elements
Fuel Code (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: Unit Fuel Codes and Descriptions
Code
Description
C
Coal
CRF
Coal Refuse (culm or gob)
DSL
Diesel Oil*
LPG
Liquefied Petroleum Gas
nng
Natural Gas
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4.3 Unit Fuel Data
Code
Description
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 D3 96-90) 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.
Indicator Code (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: Unit Fuel Indicator Codes and Descriptions
Code
Description
E
Emergency
I
Ignition (startup)
P
Primary
S
Backup (secondary)
Ozone Season Indicator (OzoneSeasonlndicator)
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 (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:
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4.3 Unit Fuel Data
Table 6: Demonstration Method to Qualify for Monthly Fuel Sampling for GCV Codes and
Descriptions
Code
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
Demonstration Method to Qualify for Daily or Annual Fuel Sampling for %S (ARP)
(DemS02)
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 (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 (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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Monitoring Plan Reporting Instructions
5.0 Monitoring Location Attribute Data
5 J Monitor! i cation Attribute Data
Monitoring Location Attribute Data Overview
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.
Monitoring Location Attribute Data XML Model
Figure 11: Monitoring Location Attribute Data XML Elements
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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 XML Elements
Duct Indicator (Ductlndicator)
Report a "1" or a "0" indicating whether the monitoring location is a duct, with "1" meaning yes
and "0" meaning no.
Bypass Indicator (Bypasslndicator)
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 (GroundElevation)
Report the elevation of the ground level, in feet above sea level, at the base of a stack or unit.
Stack Height (StackHeight)
Report the height of the stack exit, in feet above ground level.
Material Code (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: Duct/Stack Material Codes and Descriptions
Code
Description
BRICK
Brick and mortar
OTHER
Any material other than brick and mortar
Shape Code (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: Duct/Stack Shape Codes and Descriptions
Code
Description
RECT
Rectangular
ROUND
Round
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5.0 Monitoring Location Attribute Data
Cross Area Flow (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 (CrossAreaStackExit)
Report the inside cross-sectional area, in square feet, of the stack at the flue exit.
Begin Date (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 (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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Monitoring Plan Reporting Instructions
6.0 Monitoring Method Data
6.0 Monitoring Method Data
Monitoring Method Data Overview
wjwwtwiii', nyn wwii',
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, S02, C02, etc.) monitored or
calculated at each identified monitoring location. For EGUs subject to the MATS rule, report the
Monitoring Method Data record only if compliance with an applicable Hg, HC1, HF, or SO2
standard is demonstrated by continuously monitoring the pollutant emission rate. If MATS
compliance for acid gases or HAP metals is determined by any other method (e.g., periodic stack
testing, parameter monitoring, etc.), report the optional SUPPLEMENTAL MATS MONITORING
Method Data record instead (see section 6.1, below). 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, NOx program
units, Hg monitoring, 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.
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6.0 Monitoring Method Data
Monitoring Method Data XML Model
Figure 12: Monitoring Method Data XML Elements
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 XML Elements
Parameter Code (ParameterCode)
Report the appropriate Parameter Code as shown in Table 10:
Table 10: Parameter Codes and Descriptions for Monitoring Methods
Code
Description (Units)
C02
CO2 Mass Emissions Rate (tons/hr)
C02M
CO2 Mass Emissions (tons)
H20
Moisture (%H20)
HCLRE
Electrical Output-Based HC1 Emission Rate (lb/MWh)
hclrh
Heat Input-Based HC1 Emission Rate (lb/mmBtu)
hfre
Electrical Output-Based HF Emission Rate (lb/MWh)
hfrh
Heat Input-Based HF Emission Rate (lb/mmBtu)
hgre
Electrical Output-Based Hg Emission Rate (lb/GWh)
hgrh
Heat Input-Based Hg Emission Rate (lb/TBtu)
hi
Heat Input Rate (mmBtu/hr)
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Monitoring Plan Reporting Instructions
6.0 Monitoring Method Data
Code
Description (Units)
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)
S02
SO2 Mass Emissions Rate (lb/hr)
S02M
SO2 Mass Emissions (lb) (LME only)
S02RE
Electrical Output-Based SO2 Emission Rate (lb/MWh)
S02RH
Heat Input-Based SO2 Emission Rate (lb/mmBtu)
Monitoring Method Code (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
Method Code
Description
C02
AD
Appendix D Gas and/or Oil Flow System(s) (Formula G-4)
AMS
Alternative Monitoring System*
CEM
CO2 Continuous Emission Monitor
C02M
FSA
Fuel Sampling and Analysis (Formula G-l)
LME
Low Mass Emissions (§75.19)
H20
MMS
Continuous Moisture Sensor
MDF
Moisture Default
MTB
Moisture Lookup Table
MWD
H20 System with Wet and Dry O2 Analyzers
HCLRE or
HCLRH
CEM
HC1 Continuous Emission Monitoring System
CALC
Calculated from values measured at other locations. Used only for
Multistack Configurations where the HC1 hourly emission rate is
determined at multiple stacks and then summed to the unit.
HFRE or HFRH
CEM
HF Continuous Emission Monitoring System
CALC
Calculated from values measured at other locations. Used only for
Multistack Configurations where the HF hourly emission rate is
determined at multiple stacks and then summed to the unit.
HGRE
ST
Sorbent Trap Monitoring System
CEM
Hg Continuous Emission Monitoring System (Hg CEMS)
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Monitoring Plan Reporting Instructions
6.0 Monitoring Method Data
Parameter
Method Code
Description
CEMST
Hg CEMS and Sorbent Trap Monitoring System
CALC
Calculated from values measured at other locations. Used only for
Multistack Configurations where the HG electrical output-based
hourly emission rate is determined at multiple stacks and then
summed to the unit.
HGRH
ST
Sorbent Trap Monitoring System
CEM
Hg Continuous Emission Monitoring System (Hg CEMS)
CEMST
Hg CEMS and Sorbent Trap Monitoring System
CALC
Calculated from values measured at other locations. Used only for
Multistack Configurations where the HG heat input-based hourly
emission rate is determined at multiple stacks and then summed to
the unit.
HI
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
HIT
LTFF
Long-Term Fuel Flow (Low Mass Emissions - §75.19)
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)
NOX
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
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6.0 Monitoring Method Data
Parameter
Method Code
Description
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)
OP
COM
Continuous Opacity or Particulate Matter Monitor
EXP
Exempted
S02
AD
Appendix D Gas and/or Oil Flow System(s)
AMS
Alternative Monitoring System*
CEM
SO2 Continuous Emission Monitoring System
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)
S02M
LME
Low Mass Emissions (§75.19)
S02RE
CEM
SO2 Continuous Emission Monitoring System
CALC
Calculated from values measured at other locations. Used only for
Multistack Configurations where the SO2 electrical output-based
hourly emission rate is determined at multiple stacks and then
summed to the unit.
S02RH
CEM
SO2 Continuous Emission Monitoring System
CALC
Calculated from values measured at other locations. Used only for
Multistack Configurations where the SO2 heat input-based hourly
emission rate is determined at multiple stacks and then summed to
the unit.
* Use of this method requires EPA approval
Substitute Data Code (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 codes OP, HGRE, HGRH, HCLRE, HCLRH, HFRE, HFRH, S02RE, S02RH,
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:
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6.0 Monitoring Method Data
Table 12: Substitute Data Codes and Descriptions
Code
Description
Appropriate for Parameter Codes
FSP75
Fuel-Specific Part 75
NOXR, NOX, S02, C02, H20, and HI
FSP75C
Fuel-Specific Part 75 with separate co-
fired database
NOXR, NOX, S02, C02, H20, and HI
MHHI
Maximum Rated Hourly Heat Input Rate
for LME Units using Long Term Fuel
Flow methodology
HIT
NLB
Non-Load Based
NOXR, NOX, and HI
NLBOP
Non-Load Based with Operational Bins
NOXR, NOX, and HI
OZN75
Ozone vs. Non-Ozone Season
NOX, NOXR
REV75
Reverse of Standard Part 75
H20
SPTS
Standard Part 75
NOXR, NOX, S02, C02, H20, and HI
Bypass Approach Code (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
S02, 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 (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 (BeginHour)
Report the hour in which the methodology was first used to determine emissions or heat input
rate for the monitoring location.
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6.0 Monitoring Method Data
End Date (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.
End Hour (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 H20 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 S02 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.
NOx 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.
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Monitoring Plan Reporting Instructions
6.0 Monitoring Method Data
Hg Program Units (MATS Rule):
• Report a monitoring methodology record for parameter HGRE or HGRH at each
applicable location where the Hg emission rate is continuously monitored.
• If you plan to install, certify and operate a backup Hg monitoring system using a different
monitoring methodology other than the primary system, (e.g., where Hg CEMS is used as
the primary monitoring system and a sorbent trap system is used as a redundant backup),
report the combination method code (CEMST). The backup system may only be used for
reporting Hg concentration during operating hours in which the primary Hg system is not
available.
SO2, HC1 and HF Program Units (MATS Rule):
Report a monitoring methodology record for parameter S02RE, S02RH, HCLRE, HCLRH,
HFRE, or HFRH (as applicable) at each location where the SO2, HC1, or HF emission rate is
continuously monitored.
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 S02M, NOXM, C02M, HIT, and, if applicable OP.
• For Non-Acid Rain 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 C02, HI,
NOX, NOXR, or S02 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.
(Note: For EGUs subject to the MATS rule, if CEM, ST, or CEMST is the old methodology for
Hg emission rate, or if CEM is the old methodology for HC1, HF, or SO2 emission rate and you
switch to another monitoring methodology for acid gases or HAP metals (e.g., periodic stack
testing), close out the existing Monitoring Method Data record by entering the date and hour
that the methodology was discontinued (EndDate, EndHour). Then, EPA strongly encourages
you to create a new, optional Supplemental MATS Monitoring Method Data record, as
described in section 6.1.
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
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Monitoring Plan Reporting Instructions 6.0 Monitoring Method Data
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.
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Monitoring Plan Reporting Instructions
6.1 Supplemental MATS Monitoring Method Data
6.1 Supplemental MATS Monitoring Method Data
Supplemental MATS Monitoring Method Data Overview
When Hg, HC1, HF, or SO2 emission rates are not continuously monitored at a particular
monitoring location, EPA strongly encourages you to report the optional SUPPLEMENTAL MATS
Monitoring Method Data record, which describes the methods that you have chosen to
comply with the acid gas and HAP metals reduction requirements of the MATS rule. The
purpose of this optional record is to provide EPA with a clear picture of the overall MATS
monitoring strategy for the affected EGUs and to track any changes to the monitoring strategy
that occur over time. Although this is not required, it must be filled out correctly and completely
if reported.
A separate Supplemental MATS Monitoring Method Data record must be reported for each
applicable parameter.
Supplemental MATS Monitoring Method Data XML Model
Figure 13: Supplemental MATS Monitoring Method Data XML Elements
Dependencies for Supplemental MATS Monitoring Method Data
The Supplemental MATS Monitoring Method Data record is dependent on the Unit Data
record or the Stack Pipe Data record.
No other records are dependent upon the Supplemental MATS Monitoring Method Data
record.
Supplemental MATS Monitoring Method Data XML Elements
Supplemental MATS Parameter Code (SupplementalMATSParameterCode)
Report the appropriate Parameter Code as shown in Table 14:
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Monitoring Plan Reporting Instructions
6.1 Supplemental MATS Monitoring Method Data
Table 14: Supplemental MATS Parameter Codes
Parameter
Code
Description (Units)
HG
Mercury
HF
Hydrogen Fluoride
HCL
Hydrogen Chloride
TM
Total HAP Metals (Including Hg)
TNHGM
Total non-Hg HAP Metals
IM
Individual HAP Metals
(Including Hg)
INHGM
Individual non-Hg HAP Metals
LU
Limited-Use Oil-Fired Unit
Supplemental MATS Monitoring Method Code (SupplementalMATSMonitoringMethodCode)
Report the uppercase Method Code in Table 15 that identifies the monitoring method employed
for each applicable parameter at the monitoring location.
Table 15: Supplemental MATS Measured Parameters and Applicable Monitoring Methods
Parameters
Method Code
Description
HG
(Coal and pet coke-
fired EGUs and
IGCCs, only)
LEE
Low Emitting EGU
HF or HCL
LEE
Low Emitting EGU
QST
Quarterly Stack Testing
PMO
Percent Moisture in the Oil (Oil-fired EGUs, only)
TM
(Oil-fired EGUs
only)
LEE
Low Emitting EGU for Total HAP metals, including Hg
QST
Quarterly Stack Testing for Total HAP metals, including Hg
PMQST
Quarterly Stack Testing for Particulate Matter
PMCEMS
Particulate Matter Continuous Monitoring System
PMCPMS
Particulate Matter Continuous Parametric Monitoring System
CEMS
Continuous Emission Monitoring System (Requires Administrative
Approval under 40 CFR 63.7(f))
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Monitoring Plan Reporting Instructions 6.1 Supplemental MATS Monitoring Method Data
Parameters
Method Code
Description
TNHGM
LEE
Low Emitting EGU for Total non-Hg HAP metals
(Coal & pet coke-
QST
Quarterly Stack Testing for Total non-Hg HAP metals
fired EGUs and
IGCCs, only)
PMQST
Quarterly Stack Testing for Particulate Matter
PMCEMS
Particulate Matter Continuous Monitoring System
PMCPMS
Particulate Matter Continuous Parametric Monitoring System
CEMS
Continuous Emission Monitoring System (Requires Administrative
Approval under 40 CFR 63.7(f))
IM
LEE
Low Emitting EGU for each of the individual HAP metals,
including Hg
(Oil-fired EGUs,
only)
QST
Quarterly Stack Testing for each of the HAP metals, including Hg
LEST
Low Emitting EGU for some of the HAP metals and Quarterly
Stack Testing for the rest
CEMS
Continuous Emission Monitoring System for the individual HAP
metals (Requires Administrative Approval under 40 CFR 63.7(f))
INHGM
LEE
Low Emitting EGU (for each of the non-Hg HAP metals)
(Coal-fired and
QST
Quarterly Stack Testing (for each of the non-Hg HAP metals)
IGCC EGUs, only)
LEST
Low Emitting EGU for some of the non-Hg HAP metals and
Quarterly Stack Testing for the rest
CEMS
Continuous Emission Monitoring System for the individual non-Hg
HAP metals (Requires Administrative Approval under 40 CFR
63.7(f))
LU
NA
No Applicable Method
(Oil-fired units,
only)
Begin Date (BeginDate)
Report the date on which the monitoring method is first used at the monitoring location.
For new units, report the first date on which the monitoring method is expected to be used.
Correct as needed when the actual begin date is known.
Begin Hour (BeginHour)
Report the hour in which the monitoring method is first used at the monitoring location.
End Date (EndDate)
Report the date on which the monitoring method is last used at the monitoring location. Leave
this field blank for active records.
End Hour (EndHour)
Report the hour in which the monitoring method is last used at the monitoring location. Leave
this field blank for active records.
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Monitoring Plan Reporting Instructions
6.1 Supplemental MATS Monitoring Method Data
SlMcjlcCoBMieiMioBS
• For Hg, LEE status is available only for existing EGUs. For all other parameters, LEE
status is available for both new and existing EGUs.
• For all parameters except Hg, you must obtain 3 years of performance test data showing
that the emissions are < 50% of the standard to qualify for LEE status.
Updating the Supplemental MATS Monitoring Method Data Record
When you change the monitoring method for a parameter, report both the old and new
Supplemental MATS Monitoring Method Data records, except as described in the Note,
below. First, close out the existing record by entering the date and hour that the monitoring
method was discontinued (EndDate, EndHour). Second, create a new record, indicating the date
and hour at which use of the replacement monitoring method began (BeginDate, BeginHour). In
the new Supplemental MATS Monitoring Method Data record, leave the values for End
Date and End Hour blank.
In order to correct a previously submitted Supplemental MATS Monitoring Method Data
record that contains erroneous information, resubmit that record with the corrected information.
Note: If the new monitoring method involves continuous monitoring of the Hg, HC1, HF, or SO2
emission rate, deactivate the Supplemental MATS Monitoring Method Data record and
create a new Monitoring Method Data record to represent the change (see section 6.0,
above).
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Monitoring Plan Reporting Instructions
7.0 Component Data
7.0 Component Data
i''knmmmlJMaOmmm
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.
Component Data XML Model
Figure 14: Component Data XML Elements
¦---^AnalyzerRangeData |^]
0..OD
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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
Component Data XML Elements
Component ID (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.
Component Type Code (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 16. (Note: For sorbent trap monitoring systems, do not include a probe (PRB)
component).
Table 16: Component Type Codes and Descriptions
Code
Description
BGFF
Billing Gas Fuel Flowmeter
BOFF
Billing Oil Fuel Flowmeter
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Monitoring Plan Reporting Instructions
7.0 Component Data
Code
Description
CALR
Calorimeter
C02
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
H20
Percent Moisture (Continuous Moisture System only)
HCL
HC1 Concentration Analyzer
HF
HF Concentration Analyzer
HG
Mercury Concentration Analyzer (Hg CEMS)
MS
Mass Spectrograph
NOX
Nitrogen Oxide Concentration Analyzer
02
Oxygen Concentration Analyzer
OFFM
Oil Fuel Flowmeter
OP
Opacity Measurement
PLC
Programmable Logic Controller
PRB
Probe
PRES
Pressure Transmitter/Transducer
S02
Sulfur Dioxide Concentration Analyzer
STRAIN
Sorbent Trap Sampling Train Component, consisting of
a sample gas flow meter and the associated sorbent trap
TANK
Oil Supply Tank
TEMP
Temperature Transmitter/Transducer
Sample Acquisition Method Code (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 Tablel7:
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Monitoring Plan Reporting Instructions
7.0 Component Data
Table 17: Sample Acquisition Method Codes for Components
Component
Code
Description
For CEMS
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
0
Other
WXT
Wet Extractive
For Sorbent Traps
ADSP
Hg Adsorption on Sorbent Medium
For Volumetric Stack Flow Monitor
DP
Differential Pressure
0
Other
T
Thermal
U
Ultrasonic
For Fuel Flowmeter Types
COR
Coriolis
DP
Differential Pressure (e.g., Annubar)
NOZ
Nozzle
0
Other
ORF
Orifice
PDP
Positive Displacement
T
Thermal Mass Flowmeter
TUR
Turbine
U
Ultrasonic
VCON
V-Cone
VEN
Venturi
VTX
Vortex
Basis Code (BasisCode)
For CEM analyzer components and STRAIN 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 Tablel8:
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7.0 Component Data
Table 18: Moisture Basis Codes and Descriptions for CEM Analyzer and Sorbent Trap Sampling
Train Components
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 basis. For
SAM code EXT—dry basis. For all stack flow monitors—wet basis. For sampling train (STRAIN)
components in sorbent trap systems—dry basis. For others—check with vendor if uncertain.
Manufacturer (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 (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 (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.
Hg Converter Indicator (HgConverterlndicator)
For Hg CEM components, report "1" if the Hg analyzer has a converter. Report "0" if it does not.
Leave this field blank for all other component types.
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.
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7.0 Component Data
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 definitions1:
• 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.
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 calibration, online offline calibration, 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
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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Monitoring Plan Reporting Instructions
7.0 Component Data
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.
Manufacturer, Model, and Serial Number for STRAIN components
When reporting the Manufacturer, Model Number, or Serial Number for STRAIN components,
report the Sample Gas Flow Meter manufacturer, model number, and serial number. Do not
report the numbers, etc. associated with the sorbent traps or other associated hardware.
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Monitoring Plan Reporting Instructions
7.1 Analyzer Range Data
alvzer Range Data
Analyzer Ranee Data Overv iew
Submit an Analyzer Range Data record for each gas analyzer component (NOx, Hg, HC1, HF,
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.
Analyzer Manse Data XML Model
Figure 15: Analyzer Range Data XML Elements
Dependencies for Analyzer Ranee 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 Ranee Data XML Elements
Analyzer Range Code (AnalyzerRangeCode)
Report the code specifying the range by using the appropriate uppercase code as shown in Table
19. If using a default high range value for SO2 or NOx, the correct range code for the analyzer is
L. For Hg analyzers, report an analyzer code of H in all cases. There are no dual-range
requirements for Hg CEMS.
Table 19: Analyzer Range Codes and Descriptions
Code
Description
H
High Range
L
Low Range
A
Auto Ranging
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7.1 Analyzer Range Data
Dual Range Indicator (DualRangelndicator)
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 (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 (BeginHour)
Report the hour during which the range information reported in this record became effective.
End Date (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 (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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Monitoring Plan Reporting Instructions
8.0 Monitoring System Data
8 J Monitoring v stem Data
Monitoring System Data Overview
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 continuous
emission monitoring methodologies, a monitoring system is any combination of analytical
components, sensors, and data software components for which a relative accuracy test is
required (i.e., SO2 concentration system, Hg CEMS, HC1 CEMS, HF CEMS, sorbent trap
monitoring system, flow rate system, NOx diluent system, NOx concentration system, O2
concentration system, CO2 concentration system, or moisture system, as applicable). For
monitoring methodologies based on fuel flow metering, 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.
Monitoring System Data XML Model
Figure 16: Monitoring System Data XML Elements
"-if;
0,.oc
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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 XML Elements
Monitoring System ID (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 (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
C02
CO2 Concentration System
FLOW
Stack Flow System
GAS
Gas Fuel Flow System
H20
Moisture System that uses wet and dry O2 analyzers
H20M
Moisture System that uses a continuous moisture
sensor
H20T
Moisture System that uses a temperature sensor and a
table of lookup values
HCL
HC1 Concentration CEMS
HF
HF Concentration CEMS
HG
Hg Concentration CEMS
LTGS
Long Term Gas Fuel Flow System (LME)
LTOL
Long Term Oil Fuel Flow System (LME)
NOX
NOx Emission Rate System
NOXC
NOx Concentration System
NOXE
Appendix E NOx System
NOXP
NOx Emission Rate PEMS System
02
O2 Concentration System
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8.0 Monitoring System Data
Code
Description
OILM
Mass of Oil Fuel Flow System
OILV
Volumetric Oil Fuel Flow System
OP
Opacity (ARP only)
PM
Particulate Matter Monitoring System
S02
SO2 Concentration System
ST
Sorbent Trap Monitoring System
System Designation Code (SystemDesignationCode)
Report one of the following uppercase codes indicating the designation of the monitoring
system.
Table 21: System Designation Codes and Descriptions
Code
Description
P
Primary
PB
Primary Bypass- 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 "cold" backup or portable monitoring
system, having its own probe, sample interface, and analytical
components
DB
Data Backup- a system 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 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
Fuel Code (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: Monitoring System 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 all CEMS (including H20), Sorbent
Trap Monitoring Systems, 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
Begin Date (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.
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8.0 Monitoring System Data
This date may be later than the dates of any initial certification tests performed on the system
or related components.
Begin Hour (BeginHour)
Report the hour on which the system became responsible for reporting emissions data.
End Date (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 (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.
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.
Types of Systems Which May Be Defined and Used
• CO? or O? 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.
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8.0 Monitoring System Data
• 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)).
• NOv-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 NOv System (NOXEY 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.
• NOv 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 aNOx
concentration monitor and DAHS software. A probe component must be added to the
system when the sample acquisition method of the NOx Concentration System is either
dilution (DIL), dilution in-stack (DIN), dilution out-of-stack (DOU), dry extractive
(EXT), or wet extractive (WXT).
• NOv 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).
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8.0 Monitoring System Data
• 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.
• SO? 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).
• Hg Concentration System. This monitoring system is used to measure hourly Hg
concentration in units of ng/scm. It is used in conjunction with auxiliary measurements
(i.e., stack gas flow rate, diluent gas concentration, stack gas moisture content,
electrical output, as applicable) to determine hourly Hg mass emission rates in units of
lb/TBtu or lb/GWh. The monitoring system consists of a Hg pollutant concentration
monitor, and a DAHS software component. A probe component must be added to the
system when the sample acquisition method of the Hg Concentration System is either
dilution (DIL), dilution in-stack (DIN), dilution out-of-stack (DOU), dry extractive
(EXT), or wet extractive (WXT).
• Sorbent Trap Monitoring System. This monitoring system is used to determine Hg
concentration in units of ng/dscm. Paired sampling trains are used to collect vapor
phase Hg over a discrete period of time (up to 14 operating days), using sorbent traps
that contain a suitable adsorbing medium (e.g., halogenated carbon). The total volume
of dry gas sampled by each train during the collection period is measured. After the
traps are removed from service, they are analyzed to determine the mass of Hg
collected. The Hg mass collected by each train is used together with the dry gas sample
volume to determine an Hg concentration value. Generally speaking, the two Hg
concentrations are averaged, and the average value is assigned to each operating hour
of the sampling period. This average concentration is used in conjunction with auxiliary
measurements (i.e., stack gas flow rate, diluent gas concentration, stack gas moisture
content, electrical output, as applicable) to determine hourly Hg mass emission rates in
units of lb/TBtu or lb/GWh. The monitoring system consists of two sampling train
components (each one representing a sorbent trap and the associated sample gas flow
meter) and a DAHS component.
• HC1 Concentration System. This monitoring system is used to measure hourly HC1
concentration in units of ppm. It is used in conjunction with auxiliary measurements
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Monitoring Plan Reporting Instructions
8.0 Monitoring System Data
(i.e., stack gas flow rate, diluent gas concentration, stack gas moisture content,
electrical output, as applicable) to determine hourly HC1 mass emission rates in units of
lb/mmBtu or lb/MWh. The monitoring system consists of a HC1 pollutant concentration
monitor, and a DAHS software component. A probe component must be added to the
system when the sample acquisition method of the HC1 Concentration System is either
dilution (DIL), dilution in-stack (DIN), dilution out-of-stack (DOU), dry extractive
(EXT), or wet extractive (WXT).
• HF Concentration System. This monitoring system is used to measure hourly HF
concentration in units of ppm. It is used in conjunction with auxiliary measurements
(i.e., stack gas flow rate, diluent gas concentration, stack gas moisture content,
electrical output, as applicable) to determine hourly HF mass emission rates in units of
lb/mmBtu or lb/MWh. The monitoring system consists of a HF pollutant concentration
monitor, and a DAHS software component. A probe component must be added to the
system when the sample acquisition method of the HF Concentration System is either
dilution (DIL), dilution in-stack (DIN), dilution out-of-stack (DOU), dry extractive
(EXT), or wet extractive (WXT).
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.
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Monitoring Plan Reporting Instructions 8.0 Monitoring System Data
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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Monitoring Plan Reporting Instructions
8.1 Monitoring System Fuel Flow Data
8.1 Monitoring System Fuel Flow Data
Monitoring System Fuel Flow Data Overview
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.
Monitoring System Fuel Flow Data XML Model
Figure 17: Monitoring System Fuel Flow Data XML Elements
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 XML Elements
wirTT'Wsy.stww^-ws^^^gi.'1'ivi'' ffr -7-/.*»I:
Maximum Fuel Flow Rate (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.
System Fuel Flow UOM Code (SystemFuelFlowUOMCode)
Report the units of measure for fuel flow rate provided by the system using the appropriate
uppercase codes as shown in Table 23:
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8.1 Monitoring System Fuel Flow Data
Table 23: Units of Measure for Maximum Fuel Flow Rate Codes and Descriptions
Parameter
Code
Description
Volumetric Flow of Oil
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 (MaximumFuelFlowRateSourceCodej
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 (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 (BeginHour)
Report the hour in which the monitoring system fuel flow data became effective.
End Date (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.
End Hour (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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Monitoring Plan Reporting Instructions
8.2 Monitoring System Component Data
8.2 Monitoring System Component Data
Monitoring System Component Data Overview
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 SOI) 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.
Monitoring System Component Data XML Model
'Ii'iinirn-i-rfrr ill wriTr—yr iiWiiw-i-r-, -r' v..,
Figure 18: Monitoring System Component Data XML Elements
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.
Monitoring System Component Data XML Elements
if
Component ID (ComponentID)
Report the three-character alphanumeric ID for the component. For sorbent trap monitoring
systems, define two unique sampling train component ID numbers (each one representing a
sorbent trap and the associated sample gas flow meter). Report all sample gas flow rate data
under these two component ID numbers— do not change these ID numbers when the sorbent
traps are changed out.
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8.2 Monitoring System Component Data
Begin Date (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 (BeginHour)
Report the hour in which the component became an active part of the system.
End Date (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 (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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Monitoring Plan Reporting Instructions
9.0 Monitoring Formula Data
9.0 Monitoring Formula Data
Monitoring Formula Data Overview
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.
Monitoring Formula Data XML Elements
Figure 19: Monitoring Formula Data XML Elements
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 XML Elements
Formula ID (FormulalD)
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 (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
C02
CO2 Hourly Mass Emission Rate (tons/hr)
C02C
CO2 Concentration (%C02)
C02M
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
H20
Moisture (%H20)
HCLRE
Electrical Output-Based HC1 Emission Rate (lb/MWh)
HCLRH
Heat Input-Based HC1 Emission Rate (lb/mmBtu)
HFRE
Electrical Output-Based HF Emission Rate (lb/MWh)
HFRH
Heat Input-Based HF Emission Rate (lb/mmBtu)
HGRE
Electrical Output-Based Hg Emission Rate (lb/GWh)
HGRH
Heat Input-Based Hg Emission Rate (lb/TBtu)
HI
Heat Input Rate (mmBtu/hr)
HIT
Heat Input Total (mmBtu)
NOX
NOx Hourly Mass Emission Rate (lb/hr)
NOXR
NOx Emission Rate (lb/mmBtu)
OILM
Oil Mass Flow Rate (lb/hr)
S02
SO2 Hourly Mass Emission Rate (lb/hr)
S02R
SO2 Emission Rate (lb/mmBtu) when Equation D-lh is used
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9.0 Monitoring Formula Data
Code
Description
S02RE
Electrical Output-Based SChEmission Rate (lb/MWh)
S02RH
Heat Input-Based SO2 Emission Rate (lb/mmBtu)
Formula Code (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 or in the
MATS Rule) 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. The Tables
provide summaries of the primary formulas used to calculate SO2, NOx, CO2, Hg, HC1, and HF
emissions, moisture, and heat input rate. For moisture monitoring systems comprised of wet and
dry oxygen analyzers, see Table 38, Equations F-31 and M-1K. For net fuel flow and average
stack flow formulas, see Table 45. All formula codes must be entered exactly as they are
presented in Table 25 through Table 45. This includes the use of dashes and capital letters.
For example, report "F-l" (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 "19-1" (from Table 31) if
you are using Equation 19-1 from Method 19, Appendix A, 40 CFR Part 60 to convert
measurements of NOx concentration and O2 diluent on a dry basis to NOx emission rate in
lb/mmBtu. In the second example, formula code "F-5" could have been used instead of "19-1"
since Equation 19-1 in Method 19 is identical to Equation F-5 in Appendix F to Part 75.
For heat input-based Hg, HC1, HF, and SO2 emission rates (parameters HGRH, HCLRH, HFRH,
and S02RH), report the formula code for the Method 19 equation used to convert Hg, HC1, HF,
or SO2 concentration from units of lb/scf to lb/mmBtu.
For electrical output-based Hg, HC1, HF, and SO2 emission rates (parameters HGRE, HCLRE,
HFRE, and S02RE), report the formula code that is used to calculate the Hg, HC1, HF, or SO2
emission rate in lb/hr. That is:
• For Hg, report either Equation A-2 or A-3 (from Appendix A of 40 CFR Part 63, Subpart
UUUUU);
• For HC1, report either Equation HC-2 or HC-3;
• For HF, report either Equation HF-2 or HF-3; and
• For SO2, report either Equation S-2 or S-3.
For Hg, do not report the formula code HG-1 or the formula code (i.e., A-4) for the Appendix A
equation used to convert lb/hr to lb/GWh. For HC1, HF, and SO2, do not report the formula code
for the equation used to convert lb/hr to lb/MWh, i.e., formula code HC-4, HF-4, or S-4, as
applicable.
For MATS parameters (HGRE, HGRH, HCLRE, HCLRH, HFRE, HFRH, S02RE, and S02RH)
which are monitored at multiple stacks with the rate summed to the unit, report formula code
MS-1.
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9.0 Monitoring Formula Data
I(£R), (a),
E»=—„
Z(e),
2=1
(Equation MS-1)
Where:
Eh = Flow-weighted hourly average pollutant emission rate for the EGU
(lb/mmBtu, lb/TBtu, lb/MWh, or lb/GWh, as appropriate)
ER = Hourly average pollutant emission rate measured in the monitored stack
or duct (lb/mmBtu, lb/TBtu, lb/MWh, or lb/GWh, as appropriate)
Q = Hourly stack gas flow rate measured in the monitored stack or duct
(scfh, wet basis)
i = Designation for a particular stack or duct
n = Total number of monitored stacks or ducts
For MATS-affected units with a multiple-stack or duct configuration that are subject to an
electrical output-based standard, use equation MS-2 to apportion the unit load to each stack or
duct.
Li —
Qik
Z?=i Qik
(Equation MS-2)
Where:
L; = Hourly flow rate-apportioned load for the stack or duct (MW)
Lu = Hourly unit load (MW)
Qi = Hourly average stack gas flow rate through the stack or duct (scfh)
ti = Stack (or duct) operating time
i = Designation or a particular stack or duct
n = Total number of monitored stacks or ducts
For custom or non-standard intermediate equations that are not listed in Table 25 through Table
45 below, leave the Formula Code blank.
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9.0 Monitoring Formula Data
Table 25: F-Factor* Reference Table
Option 1: Fuel-liasi
luel
il Constants
F-Fact or
(ilscl/
in in litu)
F,-Facto r
(scI C ();/
in in lit u)
F„-Factor
(wsiT/m in IJlii)
Coal
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
Gas
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
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9.0 Monitoring Formula Data
I'iliil-
111 CUT
Option 2: (':ilcnhitccl I-"-l-'sictors
C oilo
1-01-11111 hi
Where:
F-7A
FD
_ 3.64(%oH) + 1.53(%C) + 0.57(%S) + 0.14(%N) - 0.46(%O) 6
GCV Xl°
F = Dry-basis F-factor
(dscf/mmBtu)
Fc = Carbon-based F-factor (scf
F-7B
FC
32 J x JO3 x(%C)
F c
GCV
CCh/mmBtu)
Fw = Wet-basis F-factor
(wscf/mmBtu)
%H,%N, - Content of element, percent
%S, %C, by weight, as determined
%0,%H20 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
19-14
FW
5.57(%H) + 1.53(%C) + 0.57(%S) + 0.14(%aN)-0.46(%O) + 0.21(%H2O) ..
F w % 10
GCVW
F-8**
FD,
FC, or
FW
F = ±X>Ft
i=l
F = Dry-basis F-factor
(dscf/mmBtu)
Fc = Carbon-based F-factor (scf
n
Fc = YjXi(Fc),
i=l
CCh/mmBtu)
n = Number of fuels being
combusted
Fi,(FcX= Applicable F, Fc, or Fw
(Fw)i factor for each fuel type
X = Fraction of total heat input
derived from each type of
fossil fuel
n
Fw = YJXl(Fw)l
i=l
* 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
I sa»e
Moisture Basis1-
Appropriate Hourly Formulas
(I'arl 75, Appendices l)»SF)
S02 CEMS
WET
F-l
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 orD-5 (andD-lH)
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 Emissions Formulas
Code
Parameters
Formula
Where:
F-l
S02
Eh = K xChxQh
Eh = Hourly SO2 mass emission rate (lb/hr)
K = 1.660 x 10"7 for SO2 ((lb/scf)/ppm)
ChP = Hourly average SO2 concentration (ppm
(dry))
Ch = Hourly average SO2 concentration (ppm
(stack moisture basis))
Qh and = Hourly average volumetric flow rate
Qhs (scfh (stack moisture basis))
%H20 = Hourly average stack moisture content
(percent by volume)
F-2
S02
„ 100-%H2O
Eh~ K xChpXQfoX io()
D-1H
S02R
ER- 10 x JO6 x Stotal
7000 GCV
ER = Default SO2 emission rate for natural
gas (or "other" gaseous fuel)
combustion (lb/mmBtu)
Stotai = Total sulfur content of gaseous fuel
(grains/100 scf)
GCV = Gross calorific value of the gas
(Btu/100 scf)
2.0 = Ratio of lb S02/lb S
7000 = Conversion of grains/100 scf to lb/
100 scf
106 = Conversion of Btu to mmBtu
D-2
S02
SO 2rate-oil = 2.0 X QILrate *
SO2 , = Hourly mass emission rate of SO2 from
rate-oil
combustion of oil (lb/hr)
OILrate = Mass rate of oil consumed per hour
during combustion (lb/hr)
%Soii = Percent sulfur by weight measured in
oil sample
2.0 = Ratio of lb SO2 to lb S
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9.0 Monitoring Formula Data
Code
Parameters
Formula
Where:
D-4
S02
SO 2 rate = (2.0 / 7000) X GAS rate X S gas
SChrate = Hourly mass rate of SO2 from
combustion of gaseous fuel (lb/hr)
GASrate = Hourly metered flow rate of gaseous
fuel combusted (100 scf/hr)
Sgas = Sulfur content of gaseous fuel
(grains/100 scf)
2.0 = Ratio of lb S02/lb S
7000 = Conversion of grains/100 scf to lb/
100 scf
D-5
S02
SO 2 rate ER X HI rate
SChrate = Hourly mass emission rate of SO2 from
combustion of gaseous fuel (lb/hr)
ER = 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)
HIrate = Hourly heat input rate of a gaseous fuel,
calculated using procedures in
Appendix D, Section 3.4.1 to Part 75
(mmBtu/hr)
F-23
S02
En = ER x HI
Eh = Hourly SO2 mass emission rate (lb/hr)
ER = 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)
HI = Hourly heat input rate, determined
using a certified flow monitor and
diluent monitor, according to Appendix
F, Section 5.2 (mmBtu/hr)
D-12*
S02
SOlrate-i ti
ry\ all-fuels
2 rate
K
SChrate = Hourly mass emission rate of SO2 from
combustion of all fuels (lb/hr)
SChrate-i = SO2 mass emission rate for each type of
gas or oil fuel combusted during the
hour (lb/hr)
ti = Time each gas or oil fuel was
combusted for the hour (fraction of an
hour)
tu = 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.
September 11, 2019
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9.0 Monitoring Formula Data
Table 28: SO2 Emission Rate Formula Reference Table for the MATS Rule
Usage
Moisture Basis
Appropriate Hourly Formulas
S02 CEMS
WET
S-2 and S-4 for electrical output-based SO2 emission
limit (lb/MWh)
19-2, 19-3, 19-4, 19-7, or 19-8 (select one) for heat
input-based SO2 emission limit (lb/mmBtu)
DRY
S-3 and S-4 for electrical output-based SO2 emission
limit (lb/MWh)
19-1, 19-5, 19-6, or 19-9 (select one) for heat input-
based SO2 emission limit (lb/mmBtu)
Table 29: SO2 Emission Formulas for the MATS Rule
Code
Formula
Where:
19-1
r ^ 20-9
E=KXCr]XFr]X
d d 20.9-%02d
The conversion factor "K" is needed to
convert SO2 concentration (Cd or Cw) from
ppm to lb/scf.
E = Unadjusted heat input-based
SO2 emission rate (lb/mmBtu)
K = 1.660 x 10"7 (lb/scf-ppm)
Cd = Unadjusted SO2 concentration
(ppm, dry basis)
Cw = Unadjusted SO2 concentration
(ppm, wet basis)
Fd = Dry-basis F-factor
(dscf/mmBtu)
Fc - Carbon-based F-factor (scf
CCh/mmBtu)
Fw = Wet-basis F-factor
(wscf/mmBtu)
Bwa = Moisture fraction of ambient air
(default value 0.027)
%H20 = Moisture content of effluent gas
C>2d = Oxygen diluent concentration
(percent of effluent gas, dry
basis)
O2W = Oxygen diluent concentration
19-2
r ^ 20-9
h = K x rw x Fw x
20.9 (1 - Bwa)-%002w
19-3*
r ^ 20-9
E = KxCwx Fdx f =i
^nn \100-%H201 0/^
20.9 x
L 100 J
19-3D
^ ^ 20-9
li. XI A /' J X 1— —1 1— —1
20.9X\100-%^°l%02
L 100 J 2« L 100 \
19-4*
E-rx (C-XF^ x 209
(100-%H2O)^100 (20.9-0%O2d)
19-5*
E 20.9 x K x Cd x Fd
I 2w y 100 J]
19-5D
^ ^ 20-9
E-K xCdx Fdx
20.9 -%02def
19-6
E-KxCdxFcx
%co2d
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9.0 Monitoring Formula Data
Code
Formula
Where:
19-7
r ^ 100
E-KxCwxFcx
%C02w
(percent of effluent gas, wet
basis)
Chdef = Default diluent cap O2 value
(14.0 percent)
C02d = Carbon dioxide diluent
concentration (percent of
effluent gas, dry basis)
CO2W = Carbon dioxide diluent
concentration (percent of
effluent gas, wet basis)
19-8*
(CwxFc) 100
(100-%H2O) + 100 %C02d
19-9*
r r \100-%H2Ol 100
E=KxC*i joo \xf
CO:
.is
O:
Appropriate 1 lourlv
l-'oi'iniilas
NOx CEMS (C02 Diluent)
DRY
DRY
19-6
DRY
WET
19-9
WET
DRY
19-8
WET
WET
19-7 or F-6
NOx CEMS (02 Diluent)
DRY
DRY
19-1 orF-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
E-2
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9.0 Monitoring Formula Data
Table 31: NOx Emission Rate Formulas (lb/mmBtu)
Code
Parameter
Formula
Where:
19-1
(F-5)
NOXR
^ 20 ¦9
E= KXCdXF dX
d d 20.9-%02d
Formulas should be multiplied by the
conversion factor "K" (if Cd or Cw is in ppm)
FROM TO MULTIPLY BY "K"
ppm NOx lb/scf K = 1.194 X 10 7
E = Emission rate (lb/mmBtu)
Cd = Pollutant concentration (ppm, dry
basis)
Cw = (Pollutant concentration ppm, wet
basis)
Fd = Dry-basis F-factor (dscf/mmBtu)
Fc = Carbon-based F-factor (scf
C02/mmBtu)
Fw = Wet-basis F-factor (wscf/mmBtu)
Bwa = Moisture fraction of ambient air
(default value 0.027)
%H20 = Moisture content of effluent gas
02d = Oxygen diluent concentration
(percent of effluent gas, dry basis)
02w = Oxygen diluent concentration
(percent of effluent gas, wet basis)
02def = Default diluent cap O2 value (14.0
percent for boilers, 19.0 percent
for combustion turbines)
C02d = Carbon dioxide diluent
concentration (percent of effluent
gas, dry basis)
CO2,,. = Carbon dioxide diluent
concentration (percent of effluent
gas, wet basis)
Ef - NOx emission rate for the unit for
a given fuel at heat input rate Hlf,
lb/mmBtu
Hlf = Heat input rate for the hour for a
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
Ht = Total heat input for all fuels for
the hour from Equation E-l
tf = Fuel usage time for each fuel
(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))
19-2
NOXR
r zr 20.9
E = K x rw x Fw x
20.9 (1 - Bwa) -%002w
19-3*
NOXR
r ^ 20.9
E = K xCwx Fdx f =i
^nn \100-%H201 0/^
20.9 x
L ioo J
19-3D*
NOXR
^ ^ 20-9
li. XI ... X / ^ A - - - -
20.9* I0°-%H>° -%02 x I0°-%^°
L ioo J 2v I ioo J
19-4*
NOXR
E-rx (C-XF^ x 209
(100-%H2O)^100 (20.9-0%O2d)
19-5*
NOXR
E~
20.9-
20.9 x K x Cd x Fd
\%o2 4,00-%h'0^
2" ^ 100 J]
19-5D
NOXR
r v 20.9
E-K xCdx Fdx
20.9 -%02def
19-6
NOXR
E~KxCdxFcx
%co2d
19-7
(F-6)
NOXR
r „ 100
E~K xCwxFcx
%co2w
19-8*
NOXR
E-Y„ (CwxFc) „ 100
(100-%H2O) + 100 %C02d
19-9*
NOXR
E = K x Cd x
~100-%H2Ol ioo
— XFCX
100 J %co2w
E-2
NOXR
all fuels
2 (EfXHIftf)
^ _ f=>
Eh
Ht
* 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.
September 11, 2019
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9.0 Monitoring Formula Data
Table 32: Hg Emission Formula Reference Table for the MATS Rule
Monitoring Methodology
Moisture
Basis
Appropriate Hourly Formulas
Part 63, Subpart UUUUIJ, Appendix A
Hg CEMS
WET
A-2 and A-4 for electrical output-based Hg
emission limit (lb/GWh)
19-2, 19-3, 19-4, 19-7, or 19-8 (select one) for heat
input-based Hg emission limit (lb/TBtu)
DRY
A-3 and A-4 for electrical output-based Hg
emission limit (lb/GWh)
19-1, 19-5, 19-6, or 19-9 (select one) for heat input-
based Hg emission limit (lb/TBtu)
Sorbent Trap Hg Monitoring
Systems
DRY
A-3 and A-4 for electrical output-based Hg
emission limit (lb/GWh)
19-1, 19-5, 19-6, or 19-9 (select one) for heat input-
based Hg emission limit (lb/TBtu)
Table 33: Hg Emissions Formulas for the MATS Rule
Code
Formula
Where:
A-2
Mh=KCh Qh
Mh = Hourly Hg mass emissions rate (lb/hr)
K = 6.24 x 10"11 (lb-scm/|ag-scf)
Ch = Hourly average, Hg concentration, wet
basis (|-ig/scm)
Qh = Hourly unadjusted average volumetric
flow rate (scfh)
A-3
Mh=KCh Qh (1-5J
Mh = Hourly Hg mass emissions rate (lb/hr)
K = 6.24 x 10"11 (lb-scm/|ag-scf)
Ch = Hourly average, Hg concentration, dry
basis (|-ig/scm)
Qh = Hourly unadjusted average volumetric
flow rate (scfh)
Bws = Moisture fraction of the stack gas,
expressed as a decimal (equal to
%H2O/100)
19-1
r ^ 20-9
E=KXCr]XFr]X
d d 20.9-%02d
The conversion factor "K" is needed to convert Hg
concentration (Cd or Cw) from |ig/scm to lb/scf.
E = Hg emission rate (lb/mmBtu)
K = 6.24 x 10"11 (lb-scm/ ng/scf)
Cd = Hg concentration (|ig/scm. dry basis)
Cw = Hg concentration (|ig/scm. wet basis)
19-2
r zr 20.9
h = K x rw x Fw x
20.9 (1 - Bwa) -%002w
19-3*
r ^ 20-9
E = K xCwx Fdx f =i
^nn \100-%H201 0/^
20.9 x
L ioo J
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9.0 Monitoring Formula Data
Code
Formula
Where:
19-3D
^ ^ 20-9
Fd = Dry-basis F-factor (dscf/mmBtu)
Fc = Carbon-based F-factor (scf CCh/mmBtu)
Fw = Wet-basis F-factor (wscf/mmBtu)
Bwa = Moisture fraction of ambient air (default
value 0.027)
%H20 = Moisture content of effluent gas
02d = Oxygen diluent concentration (percent of
effluent gas, dry basis)
02w = Oxygen diluent concentration (percent of
effluent gas, wet basis)
02def = Default diluent cap 02 value (14.0 percent
for boilers, 19.0 percent for IGCC units)
C02d = Carbon dioxide diluent concentration
(percent of effluent gas, dry basis)
C02w ~ Carbon dioxide diluent concentration
(percent of effluent gas, wet basis)
li. Ji { ,t, A- n /i A- - - - -
20.9x I0°-%^° -%02 x I00-%H>°
I 100 J 2v I 100 J
19-4*
E-rx (c-xF^ x 209
(100-%oH2O)+100 (20.9-0%O2d)
19-5*
E~
20.9-
20.9 x K x Cd x Fd
\%o2 4,00-%h'0^
2" ^ 100 J]
19-5D
r ^ 20 ¦9
E-K xCdxFdx
20-9-%O2def
19-6
E-K xCdxFcx
%co2d
19-7
r v 100
E-K xCwxFcx 0/
%C02w
19-8*
E-Y„ (CwxFc) „ 100
(100-%H2O) + 100 %C02d
19-9*
E = K x Cd x
~100-%H2Ol 100
— xFcx
100 J %co2w
A-4
Eh = Mh x 103
(MW)h
Eho = Electrical output based emissions rate
(lb/GWh)
Mh = Hourly Hg mass emissions rate (lb/hr)
(MW)h = Hourly gross electrical load
(megawatts)
103 = Conversion factor from MW to GW
HG-1
Ef = E x 106
Ef = Hg emission rate (lb/TBtu)
E Hg emission rate (lb/mmBtu)
106 = Conversion factor (mmBtu/TBtu)
Note that [(100 - %H20/100] may also represented as (1 - Bws), where Bws is the proportion by volume of water
vapor in the stack gas stream.
September 11, 2019
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9.0 Monitoring Formula Data
Table 34: HC1 Emission Rate Formula Reference Table for the MATS Rule
I ssi«e
Moisture Basis
Appropriate Hourly Formulas
HC1 CEMS
WET
HC-2 and HC-4 for electrical output-based
HC1 emission limit (lb/MWh)
19-2, 19-3, 19-4, 19-7, or 19-8 (select one) for
heat input-based HC1 emission limit
(lb/mmBtu)
DRY
HC-3 and HC-4 for electrical output-based
HC1 emission limit (lb/MWh)
19-1, 19-5, 19-6, or 19-9 (select one) for heat
input-based HC1 emission limit (lb/mmBtu)
Table 35: HC1 Emission Formulas for the MATS Rule
Code
Formula
Where:
19-1
r ^ 20-9
E=KXCr]XFr]X
d d 20.9-%02d
The conversion factor "K" is needed to
convert HC1 concentration (Cd or Cw) from
ppm to lb/scf.
E = Unadjusted heat input-based
SO2 emission rate (lb/mmBtu)
K = 9.43 x 10"8 (lb/scf-ppm)
Cd = Unadjusted HC1 concentration
(ppm, dry basis)
Cw = Unadjusted HC1 concentration
(ppm, wet basis)
Fd = Dry-basis F-factor
(dscf/mmBtu)
Fc - Carbon-based F-factor (scf
CCh/mmBtu)
Fw = Wet-basis F-factor
(wscf/mmBtu)
Bwa = Moisture fraction of ambient air
(default value 0.027)
%H20 = Moisture content of effluent gas
C>2d - Oxygen diluent concentration
(percent of effluent gas, dry
basis)
02w = Oxygen diluent concentration
(percent of effluent gas, wet
basis)
19-2
r zr 20'9
E-KxCwxFwx
20.9 (1 - Bwa)-%02w
19-3*
r 20-9
E = K xCwx Fdx f =;
^nn \100-%H201 0/^
20.9 x
L ioo J
19-3D
^ ^ 20-9
li. XI A /' J X - - - -
20.9* I0°-%H>° -%02 x I0°-%^°
L ioo J 2i¥ L ioo \
19-4*
E-Fx (C-XF^ x 209
(100-%oH2O)+100 (20.9-0%O2d)
19-5*
E 20.9 x K x Cd x Fd
I 2w { 100 )\
19-5D
r TT 20¦9
E-K xCdxFdx
20-9-%O2def
19-6
E-KxCdxFcx
%co2d
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9.0 Monitoring Formula Data
Code
Formula
Where:
19-7
r ^ 100
E-K xCwxFcx
%C02w
Chdef = Default diluent cap O2 value
(14.0 percent)
C02d = Carbon dioxide diluent
concentration (percent of
effluent gas, dry basis)
CO2W = Carbon dioxide diluent
concentration (percent of
effluent gas, wet basis)
19-8*
(CwxFc) 100
(100-%H2O) + 100 %C02d
19-9*
r r \100-%H2Ol 100
E = K xCdx xFcx
L 100 J %co2w
HC-2
Mh=KCh Qh
Mh = Hourly HC1 mass emission rate
(lb/hr)
K = 9.43 x 10"8 (lb/scf-ppm)
Ch = Unadjusted hourly average
HC1 concentration, dry basis
(ppm)
Qh = Unadjusted hourly average
volumetric flow rate (scfh)
Bws = Moisture fraction of the stack
gas, expressed as a decimal
(equal to %H20/100)
HC-3
Mh=KCh Qh (1 -BJ
HC-4
T7
h° (MW\
Eho = Unadjusted electrical output-
based HC1 emission rate
(lb/MWh)
Mh = Hourly HC1 mass emission rate
(lb/hr)
(MW)h = Hourly gross electrical load
(megawatts)
Table 36: HF Emission Rate Formula Reference Table for the MATS Rule
Usage
Moisture Basis
Appropriate Hourly Formulas
HF CEMS
WET
HF-2 and HF-4 for electrical output-based HF emission
limit (lb/MWh)
19-2, 19-3, 19-4, 19-7, or 19-8 (select one) for heat input-
based HF emission limit (lb/mmBtu)
DRY
HF-3 and HF-4 for electrical output-based HF emission
limit (lb/MWh)
19-1, 19-5, 19-6, or 19-9 (select one) for heat input-based
HF emission limit (lb/mmBtu)
September 11, 2019
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9.0 Monitoring Formula Data
Table 37: HF Emission Formulas for the MATS Rule
Code
Formula
Where:
19-1
^ 20 ¦9
E=KXCr]XFr]X
d d 20.9-%02d
The conversion factor "K" is needed to
convert HF concentration (Cd or Cw) from
ppm to lb/scf.
E = Unadjusted heat input-based HF
emission rate (lb/mmBtu)
K = 5.18 x 10 s (lb/scf-ppm)
Cd = Unadjusted HF concentration
(ppm, dry basis)
Cw = Unadjusted HF concentration
(ppm, wet basis)
Fd = Dry-basis F-factor
(dscf/mmBtu)
Fc - Carbon-based F-factor (scf
CCh/mmBtu)
Fw = Wet-basis F-factor
(wscf/mmBtu)
Bwa = Moisture fraction of ambient air
(default value 0.027)
%H20 = Moisture content of effluent gas
C>2d = Oxygen diluent concentration
(percent of effluent gas, dry
basis)
C>2w = Oxygen diluent concentration
(percent of effluent gas, wet
basis)
02def = Default diluent cap O2 value
(14.0 percent)
C02d = Carbon dioxide diluent
concentration (percent of
effluent gas, dry basis)
CO2W - Carbon dioxide diluent
concentration (percent of
effluent gas, wet basis)
19-2
r zr 20.9
E = K x rw x Fw x
20.9 (1 - Bwa)-%002w
19-3*
r ^ 20-9
E = KxCwx Fdx f =i
^nn \100-%H201 0/^
20.9 x
L ioo J
19-3D
^ ^ 20-9
li. XI A /' J X (— —1 I— —1
20.9X\100-%^°l%02
L ioo J 2i¥ L ioo \
19-4*
E-rx (C-XF^ x 209
(100-%H2O)^100 (20.9-0%O2d)
19-5*
r_ 20.9 x K x Cd x Fd
20.9-
\*0,
2" ^ 100 J]
19-5D
r v 20.9
E-K xCdx Fdx
20-9-%O2def
19-6
E-KxCdxFcx
%co2d
19-7
r r 100
E-KxCwxFcx
%C02w
19-8*
E-Y„ (CwxFc) „ 100
(100-%H2O) + 100 %C02d
19-9*
E = K xcdx
~100-%H2Ol ioo
xFcx
100 \ %co2w
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9.0 Monitoring Formula Data
Code
Formula
Where:
HF-2
Mh=KCh Qh
Mh = Hourly HF mass emission rate
(lb/hr)
K = 5.18 x 10"8 (lb/scf-ppm)
Ch = Unadjusted hourly average HF
concentration, dry basis (ppm)
Qh = Unadjusted hourly average
volumetric flow rate (scfh)
Bws = Moisture fraction of the stack
gas, expressed as a decimal
(equal to %H20/100)
HF-3
Mh=KCh Qh (1-5 J
HF-4
*7 M»
h° (MW\
Eho = Unadjusted electrical output-
based HF emission rate
(lb/MWh)
Mh = Hourly HF mass emission rate
(lb/hr)
(MW)h = Hourly gross electrical load
(megawatts)
Table 38: Moisture Formulas*
C ode
Parameter
Formula
Where:
F-31
H20
%oH20-^02d'°2^ xlOO
02d
%H20 = Percent moisture
C>2d = Oxygen diluent concentration
(percent of effluent gas, dry
basis)
C>2W = Oxygen diluent concentration
(percent of effluent gas, wet
basis)
M-1K
H20
%H20=^°2d °2wK 100
°id
, as adjusted1
* 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 39: CO2 Formula Reference Table
Usage
Moisture Basis
Appropriate Formulas
(Part 75, Appendices F, G)
C02 CEMS
(O2 Analyzer)
WET
F-14B andF-11
DRY
F-14A and F-2
C02 CEM
(CO2 Analyzer)
WET
F-ll
DRY
F-2
Fuel Sampling
G-l (and possibly G-2, G-3, G-5, G-6 and
G-8)
September 11, 2019
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9.0 Monitoring Formula Data
Usage
Moisture Basis
Appropriate Formulas
(Part 75, Appendices F, G)
Gas or Oil Flowmeter
G-4
Overall Value from Multiple
Flowmeter Systems
G-4A
Table 40: CO2 Concentration and Mass Emission Rate Formulas
Code
Parameter
Formula
Where:
F-2
C02
100- %H?0
Eh- KxChpXQhs* 100
Eh = Hourly CO2 mass emissions (tons/hr)
K = 5.7 x 10"7 for C02
((tons/scf)/percent CO2)
ChP = Hourly average, CO2 concentration
(percent CO2, dry basis)
Qhs = Hourly average volumetric flow rate
(scfh, wet basis)
%H20= Hourly average stack moisture
content (percent by volume)
F-ll
C02
Eh=KxChxQh
Eh = Hourly CO2 mass emission rate
(tons/hr)
K = 5.7xl0 7 for C02
((tons/scf)/percent CO2)
Ch = Hourly average CO2 concentration
(percent CO2, wet basis)
Qh = Hourly average volumetric flow rate
(scfh, wet basis)
F-14A
C02C
Fc 20.9 - 02d
C02d = 100 x — x —
2d F 20.9
C02d = Hourly average CO2 concentration
(percent by volume, dry basis)
F = Dry-basis F-factor (dscf/mmBtu)
Fc = Carbon-based F-factor
(scf C02/mmBtu)
20.9 = Percentage of O2 in ambient air
02d = Hourly average O2 concentration
(percent by volume, dry basis)
F-14B
C02C
100 f r f 100- %h2o) i
co-=20.9*;* [2oH 100 J-°-J
CO2W = Hourly average CO2 concentration
(percent by volume, wet basis)
F = Dry-basis F-factor (dscf/mmBtu)
Fc = Carbon-based F-factor
(scf C02/mmBtu)
20.9 = Percentage of O2 in ambient air
O2W = Hourly average O2 concentration
(percent by volume, wet basis)
%H20 = Moisture content of gas in the stack
(percent)
G-l
C02M
(mwc + mw0)xwc
W -
c°2 2000MWC
Wco2 = CO2 emitted from combustion
(tons/day)
MWc = Molecular weight of carbon (12.0)
MWo2= Molecular weight of oxygen (32.0)
Wc = Carbon burned (lb/day) determined
using fuel sampling and analysis and
fuel feed rates*
September 11, 2019
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9.0 Monitoring Formula Data
Code
Parameter
Formula
Where:
G-2
C02M
MWcm (A%\ (C%\
WNC02 = Warn — * X X WCOAL
mwc v 100/ uooy
Wnco2 = Net CO2 mass emissions discharged
to the atmosphere (tons/day)
Wco2 = Daily CO2 mass emissions calculated
by Equation G-l (tons/day)
MWC02 = 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)
G-3
C02M
WnC02 =-99x^C02
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-l (tons/day)
G-4
C02
F' x H x U f x MWcn
wco= f 2
2 2000
Wco2 = CO2 emitted from combustion
(tons/hr)
Fc = 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
H = Hourly heat input rate (mmBtu/hr)
Uf = 1/385 scf CCVlb-mole at 14.7 psi and
68EF
MWco2 = Molecular weight of carbon dioxide
(44.0)
G-4A
C02
C02 fuelt fuel
/"VT") all-fuels
unit ~
unit
C02umt = Unit CO2 mass emission rate
(tons/hr)
C02fuei = CO2 mass emission rate calculated
using Equation G-4 for a single fuel
(tons/hr)
tfuei = Fuel usage time
tunit = Unit operating time
G-5
C02M
MWco
SEco = WCaCO xFux 2—
2 3 MWCaCOi
SECo2 = CO2 emitted from sorbent (tons/day)
Wcaco3 = Calcium carbonate used (tons/day)
Fu = 1.00, the calcium to sulfur
stoichiometric ratio
MWco2 = Molecular weight of carbon dioxide
(44.0)
MWcaco3= Molecular weight of calcium
carbonate (100.0)
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9.0 Monitoring Formula Data
Code
Parameter
Formula
Where:
G-6
C02M
„ WSo2 MWcol
co2 u 200Q
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
Fu = 1.00, the calcium to sulfur
stoichiometric ratio
G-8
C02M
W, = wC02 + SECOi
Wt = Estimated total CO2 mass emissions
(tons/day)
Wco2 = CO2 emitted from fuel combustion
(tons/day)
SECo2 = CO2 emitted from sorbent (tons/day)
* See Appendix G, sections 2.1.1 through 2.1.3
** For a unit linked to a common pipe with one additional fuel flowmeter system defined at the unit, report a G-4A
formula to calculate the unit hourly CO2 rate, even though there is only a single fuel flowmeter defined at the unit.
Because the fuel usage time may not be equal to the unit operating time, the hourly CO2 rate for the fuel may be
different from the hourly CO2 rate for the unit. Use formula G-4A to calculate the unit hourly CO2 rate.
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9.0 Monitoring Formula Data
Table 41: Heat Input Formula Reference Table
I sa»e
Moisture Basis1-
Appropriate Hourly Formulas (Part
75, Appendices 1) and F)
CEMS (O2 Analyzer)
WET
F-17
DRY
F-18
CEMS (CO2 Analyzer)
WET
F-15
DRY
F-16
Gas Fuel Flowmeter System
D-6 (F-20)
Oil Fuel Flowmeter System
(Mass)
D-8 (F-19)
Oil Fuel Flowmeter System
(Volumetric)
D-3 and D-8 (F-19) orF-19V
Overall Value from Multiple Fuel
Flowmeter Systems
D-15A
Apportioned Value from Common
Stack or Common Pipe
F-21A, F-21B, orF-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.
Table 42: Heat Input Formulas
Code
Parameter
Formula
Where:
D-15A
HI
HI rate-it i
all-fuels
ill rate-hr
tu
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)
t = Time each gas or oil fuel was
combusted for the hour (fuel
usage time) (fraction of an
hour)
tu = Operating time of the unit
F-15
HI
HI = 0 x ' X%C0"
F.- 100
HI = Hourly heat input rate
(mmBtu/hr)
Qw, Qh = Hourly average volumetric
flow rate (scfh, wet basis)
Fc = Carbon-based F-factor
(scf/mmBtu)
F-16
HI
hi = oJ,00-%h>0}\%coA
* L I°°Fc JL 100 J
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9.0 Monitoring Formula Data
Code
Parameter
Formula
Where:
F-17
HI
In-C - 1 ,.[(20.9/100)(100-%H20)-%02J
F 20.9
F = Dry basis F-factor
(dscf/mmBtu)
%C02w = Hourly concentration of CO2
(percent CO2, wet basis)
%C02d = Hourly concentration of CO2
(percent CO2, dry basis)
%02w = Hourly concentration of O2
(percent O2, wet basis)
%02d = Hourly concentration of O2
(percent O2, dry basis)
%H20 = Hourly average moisture of gas
in the stack (percent)
F-18
HI
[ (100-%H20)]\(20.9-%02d)]
^w [ 100F JL 20.9 \
D-3
OILM
OILrate Voil-rate ^ D oil
OILrate = Mass rate of oil consumed per hi
(lb/hr)
Voii-rate = Volume rate of oil consumed
per hr, measured (scf/hr, gal/hr,
barrels/hr, or m3/hr)
Don = Density of oil, measured
(lb/scf, lb/gal, lb/barrel, or
lb/m3)
D-8**
(F-19V)
HI
HI rate-el-OILmteXGCV6°'1
106
HIrate-oii = 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)
GCVoii = Gross calorific value of oil
(Btu/lb for Equation D-8 or
Btu/gal for Equation F-19V)
106 = Conversion of Btu to mmBtu
F-19
HI
HIo=MoX^r
106
HI0 = Hourly heat input rate from
combustion of oil (mmBtu/hr)
M0 = Mass rate of oil consumed per
hour (lb/hr)
GCV0 = Gross calorific value of oil
(Btu/lb)
106 = Conversion of Btu to mmBtu
D-6
HI
_ GAS rate X GCV gas
ill rate-gas *
106
HIrate-gas = Hourly heat input rate from
HIg combustion of gaseous fuel
(mmBtu/hr)
GASrate = Average volumetric flow
Qg rate of fuel (100 scfh)
GCVgas = Gross calorific value of
GCVg gaseous fuel (Btu/100 scf)
106 = Conversion of Btu to mmBtu
F-20
HI
(QgxGCVg)
HIg = — r-L-
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
Table 43: Apportionment and Summation Formulas
Code
Parameter
Formula
Where:
F-21A
HI
/
Hit = Hies
\
tcs^
. u J
MWiti
n
YjMWi ti
. i=l
HI = Heat input rate for a unit
(mmBtu/hr)
Hies = Heat input rate at the common
stack or pipe (mmBtu/hr)
MWi = Gross electrical output (MWe)
ti = Operating time at a particular
unit
tcs = Operating time at common
stack or pipe
n = Total number of units using the
common stack or pipe
i = Designation of a particular unit
F-21B
HI
Hh = Hies
'tcs]
V ti J
1 1
nC
& ^
1 1
HI = Heat input rate for a unit
(mmBtu/hr)
Hies = Heat input rate at the common
stack or pipe (mmBtu/hr)
n = Number of stacks or pipes
SF, = Gross steam load (flow) (lb/hr)
ti = Operating time at a particular
unit
tcs = Operating time at common
stack or pipe
n = Total number of units using the
common stack or pipe
i = Designation of a particular unit
F-21C
HI
n
YjHL u
HI umt = —
tlJnit
Hlunit = Heat input rate for a unit
(mmBtu/hr)
HIS = Heat input rate for each stack
or duct (mmBtu/hr)
tumt = Operating time for the unit
ts = Operating time for a particular
stack or duct
s = Designation of a particular
stack or duct
n = Total number stacks, ducts
F-21D
HI
HI , = HI cp
'tcA
V ti J
1 1
nC
^ £:
^ -W:
i i
HI = Heat input rate for a unit
(mmBtu/hr)
HIcp = Heat input rate at the common
pipe (mmBtu/hr)
FFi = Fuel flow rate to a particular
unit (appropriate units)
ti = Operating time at a particular
unit (hr)
tcp = Operating time at common pipe
(hr)
n = Total number of units using the
common pipe
i = Designation of a particular unit
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9.0 Monitoring Formula Data
Code
Parameter
Formula
Where:
F-25
HI
p
HI u tu
HIcs = —
tcs
Hies = Hourly average heat input rate
at the common stack
(mmBtu/hr)
HIU = Hourly average heat input rate
for a unit (mmBtu/hr)
p = Number of units
tu = Operating time at a particular
unit
tcs = Operating time at common
stack
u = Designation of a particular unit
Table 44: NOx Mass Emissions Formulas (lbs/hr)
Code
Parameter
Formula
Where:
F-24A
NOX
E(NOx)h ER(NOx)h HIh
E(NOx)h = Hourly NOx mass emissions
rate in lb/hr
K = 1.194 x 10"7 for NOx
((lb/scf)/ppm)
CiM = Hourly average, NOx
concentration (ppm (dry))
Chw = Hourly average, NOx
concentration, stack moisture
basis (ppm (wet))
Qh = Hourly average volumetric
flow rate (scfh)
%H20 = Hourly average stack moisture
content (percent by volume)
Hlh = Hourly average heat input rate
(mmBtu/hr)
ER,\: r, ,h = Hourly average NOx emission
rate (lb/mmBtu)
F-26A
NOX
E(yox)h = K x Chw x Qh
F-26B
NOX
„ (100-%H2O)
E(NOx)h-KxChdxQhx
Table 45: 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
S02
Total hourly SO2 mass emissions from the affected unit(s) in a
subtractive stack configuration (lb/hr)
SS-1B
S02
Hourly SO2 mass emissions from a particular affected unit in a
subtractive stack configuration (lb/hr)
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9.0 Monitoring Formula Data
Code
Parameter
Description
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)
MS-1
HGRE, HGRH,
HCLRE,
HCLRH, HFRE,
HFRH, S02RE,
S02RH
Hourly flow-weighted pollutant emission rate for a MATS unit with
monitored multiple stacks or ducts (lb/mmBru, lb/TBtu, lb/MWh, or
lb/GWh, as appropriate)
MS-2
HGRE, HCLRE,
HFRE, S02RE
Flow rate-apportioned load value for a MATS unit with monitored
multiple stacks or ducts subject to an electrical output-based standard
Formula Text (FormulaText)
When using a standard formula from Table 25 through Table 44 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 45; or (2) another site-specific equation not
listed in Table 25 through Table 45. 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 46. To the extent
possible, use symbols and nomenclature consistent with Table 25 through Table 44. Use
parentheses and square brackets as needed, for added clarity.
• Formula References. Wherever another formula in the monitoring plan is part of a non-
standard or custom equation, you may refer to the other formulas as "F#(XYZ)M where
XYZ is the Formula ID, rather than rewriting the entire text of the formula in the non-
standard 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.
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9.0 Monitoring Formula Data
Table 46: Representations for Electronic Reporting of Formulas
Operation
Recommended
Representation
Example
Addition
+
MW_1 + MW_2
Subtraction
-
(100 - %H20)
Multiplication
*
Cd*Fd
Division
/
%co2/ioo
Exponential Power
**
1.66 xl0"7= 1.66* 10 ** -7
Subscript
Underscore
MWi = MW_1
Fraction of Heat Input from Fuel
X_
Xoil
Gross Electrical Output
MW_
MW_1
Gross Steam Load (Flow)
SF_
SF_1
Hourly Emissions
Eh
Eh
Operating Time
T_
TCSl
Begin Date (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 (BeginHour)
Report the hour in which the formula was first applied to calculate the data.
End Date (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.
End Hour (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
o SO2 mass emission rate
o NOx emission rate
o NOx mass emission rate
o CO2 concentration (if CO2 is calculated from O2 data)
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9.0 Monitoring Formula Data
o CO2 mass emission rate
o Hg emission rate
o HC1 emission rate
o HF emission rate
o SO2 emission rate (MATS)
o Heat input rate
o F-factor proration calculation for mixed fuels (if elected)
o Flow-weighted or heat input-weighted NOx emission rate formulas for multiple
stacks using two primary NOx systems
o Moisture formulas for moisture systems using O2 wet and dry readings
o Flow formulas for all flow systems containing two flow monitors
• For Fuel Flow Based Methodologies
o SO2 mass emission rate (ARP)
o CO2 mass emission rate (ARP)
o NOx emission rate for the unit where separate Appendix E single fuel curves were
used (Equation E-2)
o Heat input rate
o Mass of oil formulas for OILV measurements (ARP)
o Net fuel flow formulas for systems with more than one flowmeter
o 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 F-factor. 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.
Equations 19-3D and 19.5D
• For units that use Equation 19-3 or 19-5 to calculate NOx, SO2, Hg, HC1, or HF emission
rate (lb/mmBtu) during normal unit operation, if the O2 diluent cap value is applied
during startup and shutdown hours, you must use Equation 19-3D instead of Equation 19-
3 or Equation 19-5D instead of Equation 19-5 (as applicable) for each hour in which the
diluent cap is used, to avoid generating negative NOx, SO2, Hg, HC1, or HF emission
rates.
Situations That Do Not Require Formulas
• Appendix E units do not need formulas for the NOx emission rate.
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• 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.
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10.0 Monitoring Default Data
10.0 Monitoring Default Data
Monitoring Default Data Overview
wjwwtwiii',
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), 75.31(c)(3), and 75.34(a)(5)).
• 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.
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10.0 Monitoring Default Data
Low Mass Emissions Defaults (DefaultPurposeCode "LM")
• Fuel-specific 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. This parameter should be active beginning with the first
quarter the unit uses the LME methodology.
Primary Monitoring Methodology Default (DefaultPurposeCode "PM")
• Default moisture values from §75.11(b) or §75.12(b), used to estimate
content for specific fuels.
• Site-specific default moisture percentages, approved by petition under
• Moisture Fraction in Ambient Air for use with equation 19-2.
Diluent Cap Default (DefaultPurposeCode "DC")
CO2 or O2 diluent cap for heat input-based NOx, SO2, Hg, HC1, or HF emission rate calculations
(lb/mmBtu or lb/TBtu, as applicable).
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.
stack moisture
§75.66.
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10.0 Monitoring Default Data
Monitoring Default Data XML Model
Figure 20: Monitoring Default Data XML Elements
" OperatingConditionCode
3
' Group®
" Begin Date
"Begin Hour
" EndDate
"EndHour
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 XML Elements
Parameter Code (ParameterCode)
Report the parameter for which a default value is defined by using the appropriate uppercase
codes as shown in Table 47:
Table 47: Parameter Codes and Descriptions for Monitoring Default
Category
Parameter
Code
Description
Diluent Cap
C02N
CO2 Diluent Cap
02X
O2 Diluent Cap
Low Mass Emissions Parameters
(§§75.19 and 75.81(b))
C02R
CO2 Default Emission Factor, from Table 51 or Fuel
and Unit-Specific CO2 Default Emission Factor, for
Combustion of "Other" Gaseous Fuel (tons/mmBtu)
NOXR
NOx Default Emission Factor, from Table 49 or Fuel
and Unit-Specific NOx Emission Rate1 (lb/mmBtu)
S02R
SO2 Default Emission Factor, from Table 50 or Fuel and
Unit-Specific SO2 Default Emission Factor Calculated
Using Equation D-lh, 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)
Missing Data Values
or
Maximum Values for
Unmonitored Bypass Stack and
Emergency Fuels
H20N
Minimum Potential Percent Moisture
H20X
Maximum Potential Percent Moisture
C02X
Maximum Percent CO2
02N
Minimum Potential Percent Oxygen
S02X
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), MCR, or Fuel-
Specific Maximum Potential or Maximum Controlled
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)
Moisture Default Parameter
H20
Hourly Percent Moisture Content (%H20)
BWA
Moisture Fraction in Ambient Air
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10.0 Monitoring Default Data
Category
Parameter
Code
Description
SO2 Emission Rate Parameter
for Use in Formula F-23
S02R
SO2 Generic Default Emission Factor for Pipeline
Natural Gas; or
Fuel and Unit-Specific Default Emission Factor
Calculated Using Equation D-lh 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).
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
1 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)).
Default Value (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 48: Rounding Rules for Default Values
Round (0 0
Decimal
Places
Round (0 1
Decimal
Places
Round (0 2
Decimal
Places
Round (0 3
Decimal
Places
Round (0 4
Decimal
Places
Round (0
Nearest
1000
Parameter
C odes
C02N, C02X,
H20, H20N,
H20X,
MHHI,
MNGF,
MNHI,
MNOF,
NOCX, 02X,
02N, S02X
BWA, C02R,
MNNX,
NORX,
NOXR
S02R
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.
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Calculate NOx MER on a unit or stack basis by using one of the following formulas and values:
Where:
E = K xQdxFdx
20.9
20.9-%02d
(Equation F-5)
E
K
Cd
Fd (dscf/mmBtu)
%02h
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.
^ ^ 100
E = K xCwxFcx
%C02w
(Equation F-6)
Where:
E = Pollutant emissions during unit operation, lb/mmBtu;
K = 1.194 x 10"7 (lb/dscf)/ppm NOx;
Cw = NOx concentration (wet) (use MPC value);
Fc (scf C02/mmBtu) = Carbon-based F-factor used for the unit in Monitoring Formula 20;
and
%C02w = 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 combustion turbines
(including IGCC units). For an O2 diluent cap value, report 14.0 percent for a boiler or 19.0
percent for turbines (including IGCC units).
Moisture Defaults
If using a default value to determine moisture, report fuel-specific moisture default values. Table
49 and Table 50 provide the fuel-specific moisture default values for coal-fired and wood-
burning units and natural gas-fired boilers. Table 49 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
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calculate NOx emission rate, SO2 emission rate, HC1 emission rate, HF emission rate, or Hg
emission rate, use the appropriate maximum default moisture value from Table 50.
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.
Table 49: 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 50: 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 51 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 51. If testing is used to
derive default emission rates, use the default source code "TEST" (see Table 58) and conduct
LME Unit Default testing as described in Section 3.6 of the Quality Assurance and Certification
Reporting Instructions.
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10.0 Monitoring Default Data
For fuel oil combustion, in lieu of using the default values in Table 52, 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)(l)(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.
Table 51: NOx Emission Factors (lb/mmBtu for Low Mass Emissions Units)
Boiler Type
Fuel Type
NOx Emission Factors
Turbine
Natural Gas
0.7
Oil
1.2
Boiler
Natural Gas
1.5
Oil
2.0
Table 52 contains the Part 75 SO2 emission factors for low mass emissions units, which are
based on the type of fuel combusted.
Table 52: SO2 Emission Factors (lb/mmBtu) for Low Mass Emissions Units
Fuel Type
SO2 Emission Factors
Pipeline Natural Gas
(as defined in §72.2)
0.0006
Natural Gas
0.06
Residual Oil or
Other Oil
2.10
Diesel Fuel
0.50
Table 53 contains fuel-specific CO2 emission factors for low mass emissions units.
Table 53: CO2 Emission Factors (ton/mmBtu) for Low Mass Emissions Units
Fuel Type
CO2 Emission Factors
Natural Gas
0.059
Oil
0.081
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Default Units of Measure Code (DefaultlJnitsOjMeasureCode)
Report the appropriate measurement units using the appropriate uppercase codes as shown in
Table 54. For Parameter BWA, leave this field blank.
Table 54: Units of Measure Codes by Parameter
Units of
Measure Code
Description
Parameter Code
PCT
Percent
C02N, C02X, H20, H20N,
H20X, 02N, 02X
LBMMBTU
Pounds per Million Btu
MNNX, NOXR, S02R, NORX
MMBTUHR
Million Btu per Hour
MNHI, MHHI
TNMMBTU
Tons per Million Btu
C02R
SCFH
Standard Cubic Feet per Hour
MNOF, FLOX
PPM
Parts per million
S02X, 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
Default Purpose Code (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 55:
Table 55: Default Purpose Codes and Descriptions
Code
Description
Parameter Code
DC
Diluent Cap
C02N, 02X
DM
Default Minimum Fuel Flow Rate
MNGF, MNOF
F23
SO2 Emission Rate Default for Use in Equation F-23
S02R
LM
Low Mass Emissions Unit Default (§§75.19 and
75.81(b))
C02R, S02R, NOXR, MHHI
MD
Missing Data, Unmonitored Bypass Stack, or
Emergency Fuel
C02X, FLOX, H20N, H20X,
MNHI, MNNX, NOCX,
NORX, 02N, S02X
PM
Primary Measurement Methodology
BWA, H20
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Fuel Code (FuelCode)
Report the type of fuel associated with the default by using the appropriate uppercase codes as
shown in Table 56. 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 56: Monitoring Default Fuel Codes and Descriptions
Type
Code
Description
LME Defaults
(§75.19)
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
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
Moisture
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
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Type
Code
Description
SO2 Emission Rate Default
for Use in Equation F-23
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
Fuel-Specific CEMS Missing
Data
BFG
Blast Furnace Gas
BUT
Butane (if measured as a gas)
C
Coal
CDG
Coal-Derived Gas
COG
Coke Oven Gas
CRF
Coal Refuse (culm or gob)
DGG
Digester Gas
DSL
Diesel Oil
LFG
Landfill Gas
LPG
Liquefied Petroleum Gas (if measured as a gas)
MIX
Co-Fired Fuels
NNG
Natural Gas
OGS
Other Gas
OIL
Residual Oil
Fuel-Specific CEMS Missing
Data (cont.)
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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Type
Code
Description
Fuel-Specific MPC/MER or
MEC/MCR Reporting During
Bypass Stack Operating
Hours
BFG
Blast Furnace Gas
BUT
Butane (if measured as a gas)
C
Coal
CDG
Coal-Derived Gas
COG
Coke Oven Gas
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
Fuel-Specific MPC/MER or
MEC/MCR Reporting During
Bypass Stack Operating
Hours (cont.)
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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Operating Condition Code (OperatingConditionCode)
If the value is used only for controlled or uncontrolled hours, indicate this using a "C" or "U," as
appropriate (for example, if using separate NORX codes for controlled and uncontrolled
operating conditions, use the "C" code for the MCR rate value and "U" code for the MER rate
value). 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 57 summarizes operating condition
codes and descriptions.
Table 57: Monitoring Default 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 (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 58:
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Table 58: Default Source Codes and Descriptions
Default
Source Code
Source of Value Description
Parameter
APP*
Approved (Petition)
MNNX, S02R, MNHI, H20,
MHHI
DATA**
Historical or Other Relevant Data
02N, 02X, C02X, H20N,
H20X, FLOX, S02X, NOCX,
NORX, NOXR, MNOF, MNGF,
BWA
PERM
Maximum Weight Percent Sulfur in Fuel Oil, as
Specified by Operating Permit (for LME)
S02R, NORX, NOCX
TEST
Unit/Stack Testing
NOXR, FLOX, S02X, NOCX,
NORX
SAMP
Fuel Sampling
S02R, C02R, S02X,
CONT
Contract Maximum
S02R
DEF
Default Value from Part 75
C02R, NOXR, C02N, 02X,
S02R, H20N, H20X, S02X,
NOCX, NORX, H20
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 (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 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 (BeginDate)
Report the date on which the default became effective for purposes of reporting emissions data.
Begin Hour (BeginHour)
Report the hour on which the default became effective for purposes of reporting emissions data.
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End Date (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 (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.
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.
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-lh.
• 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-lh.
• 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
11.0 Monitoring Span Data
Monitoring Span Data Overview
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.
Monitoring Span Data XML Model
Figure 21: Monitoring Span Data XML Elements
Dependencies for Monitoring Span Data
The Monitoring Span Data record is dependent on the Unit Data record or the Stack Pipe
Data record.
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No other records are dependent upon the Monitoring Span Data record.
Monitoring Span Data XML Elements
Component Type Code (ComponentTypeCode)
Identify the component type (parameter) of the monitor using the following uppercase codes:
Table 59: Component Type Codes and Descriptions for Monitor Span
Code
Description
C02
CO2 Concentration (percent)
FLOW
Stack Flow
HCL
HC1 Concentration (ppm)
HG
Hg concentration (|ig/scm)
NOX
NOx Concentration (ppm)
02
O2 Concentration (percent)
S02
SO2 Concentration (ppm)
Span Scale Code (SpanScaleCode)
Report either "H" to indicate high scale or "L" to indicate low scale, as appropriate for the
component types in Table 59, except for FLOW. For HG and HCL, the span scale code must be
"H." For FLOW leave this field blank.
Span Method Code (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 60:
Table 60: 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 Value or Other Default Value from
Part 75 or from 40 CFR Part 63, Subpart
UUUUU, Appendix A
OL
Other Limit
GS
Low Scale Default for SO2 for Gas Units
PL
NOx MEC Based on Permit Limit
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Code
Description
ME
NOx MPC Based on Manufacturer's
Estimate of Uncontrolled Emissions
FS
Fuel Sampling and Analysis (for Hg MPC)
• Table 61 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-la or A-lb 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 %C02 value observed in the historical look-back period as the MPC.
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Table 61: Criteria for MPC/MEC/MPF Determinations
Component
Type
Scale
Met hod I sed lo Determine
Ml»( /MIX /MPI
Selection Criteria
Method
C ode
NOX
High
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
MPC as described in Section 2.1.2.5 of
Appendix A
HD
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
Low
Equation A-2
For units with emission controls
F
Historical CEM data
For initial determination or for changes in
MEC as described in Sections 2.1.2.2(c)
and 2.1.2.5 of Appendix A
HD
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
HCL
High
Other, including other
state/federal requirements
As justified
OL
HG
High
Fuel-Specific Default MPC
Values from 40 CFR Part 63,
Subpart UUUUU, Appendix A
10 ng/scm Bituminous coal
10 ng/scm Sub-bituminous coal
16 ng/scm Lignite
10 ng/scm Waste coal
TB
Site-Specific Emission Testing
Use the highest observed test results
TR
Fuel Sampling and Analysis
Use the average weight percent of Hg
from 3 samples, together with maximum
fuel feed rate, fuel GCV, appropriate F-
factor, etc.
FS
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Component
Type
Scale
Method Used to Determine
MPC/MEC/MPF
Selection Criteria
Method
Code
FLOW
N/A
Equation A-3a and Equation of
Continuity*
Based on %C02
F
Equation A-3b and Equation of
Continuity*
Based on %02
F
Historical data
For changes in MPF, as described in
Section 2.1.4.3 of Appendix A
HD
Test results
If available
TR
S02
High
Equation A-la
Based on %C02
F
Equation A-lb
Based on %02
F
Historical CEM data
For initial determination or for changes in
MPC as described in Section 2.1.1.5 of
Appendix A
HD
Test results
If available
TR
Other, including other
state/federal requirements
As justified
OL
Low
Equation A-2
For units with emission controls
F
Historical CEM data
For initial determination or for changes in
MEC as described in Section 2.1.1.5 of
Appendix A
HD
# 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 (MECValuej
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 (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, SO2, and Hg to one decimal place. For O2,
leave this field blank.
MPF Value (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.
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Span Value (SpanValue)
Report the Span Value determined according to the requirements of Part 75 or (if applicable) 40
CFR Part 63, Subpart UUUUU. If using a default high range value for SO2 or NOx, leave this
field blank in the high scale record.
For HC1, determine the span value as follows. Multiply the HC1 concentration (ppm)
corresponding to the emissions standard by two and round off the result to the next highest
multiple of 5 ppm. Span values must be between 1 ppm and 20 ppm.
For Hg, determine the span value as follows. Multiply the Hg concentration (|ig/scm)
corresponding to the emission standard by two and round off the result to either: the next highest
integer; the next highest multiple of 5 |ig/scm; or the next highest multiple of 10 |ig/scm.
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). Low-
scale 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 (FullScaleRange)
Report the full-scale range in the units used for daily calibrations for SO2, NOx, CO2, O2, HC1,
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. For Hg, the analyzer range must be high enough to read the MPC value.
Span Units of Measure Code (SpanUnitsOjMeasureCode)
For SO2, HC1, and NOx, report PPM. For O2 and CO2, report PCT.
For Hg, report UGSCM, which represents micrograms per standard cubic meter.
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:
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11.0 Monitoring Span Data
Table 62: 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
AFSEC
Actual Feet of Stack Flow per Second
AMSEC
Actual Meters of Stack Flow per Second
INH20
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
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
Scale Transition Point (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, HC1, and Hg span.
Default High Range (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 HG, HC1, CO2, O2, or FLOW, leave this field blank.
Flow Span Value (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.
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Flow Full Scale Range (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 (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 (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.
End Date (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 (EndHour)
Report the last hour in which the span record was in effect. Leave this field blank for active span
records.
CEMS Methodology
• If you are using a CEMS methodology, Monitoring Span Data must be included for
each parameter (e.g., NOX, S02, C02, 02, HCL, HG, 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 generally based on
the fuel that produces the highest pollutant concentration or emission rate. However, 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 for the
highest emitting fuel 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
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11.0 Monitoring Span Data
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).
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-l) 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
12 J Rectangular Duct WAF Data
Rectangular Duct WAF Data Overview
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
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.
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12.0 Rectangular Duct WAF Data
RectMmsulo.rDm.ct WAF Data XML Model
Figure 22: Rectangular Duct WAF Data XML Elements
Retfang u larDuctWA F Data [j—jE5~
— WAFDetermi nation Date
WAFBeginDate
WAFBeginHour
WAF M ethod C ode
'WAFValue
' NumberOfTestRuns
' NumberQfT raversePointsWAF
' NumberOfT estPorts
' N urn berOfT ravers e Poi nts Ref
' DucfWidth
' DuctDepth
'WAFEndDate
''."•.'AFEndHour
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. XML Elements
WAF Determination Date (WAFDeterminationDatej
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 (WAFBeginDate)
Report the date on which the WAF was first applied to the flow rate data.
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WAF Begin Hour (WAFBeginHour)
Report the hour in which the WAF was first applied to the flow rate data.
WAF Method Code (WAFMethodCodej
Report the appropriate WAF Method Code displayed in Table 63 to indicate the WAF
calculation approach.
Table 63: 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 (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 (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 (NumberOfTraversePointsWAF)
Report the number of Method 1 traverse points in the WAF test runs.
Number of Test Ports (NumberOfTestPorts)
Report the number of test ports at which measurements were made during the WAF test runs.
Number of Traverse Points Reference (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 RAT As must equal the Number of Traverse
Points WAF data element, for the WAF test run(s). If you wish to increase the number of
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 (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 (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.
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12.0 Rectangular Duct WAF Data
WAF End Date (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 (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
13.0 Monitoring Load Data
Monitoring Load Data Overview
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.
Monitoring Load Data XML Model
Figure 23: Monitoring Load Data XML Elements
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.
Monitoring Load Data XML Elements
mmmmrr.-Av,
Maximum Load Value (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:
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13.0 Monitoring Load Data
• 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.
• For units subject to the MATS rule that use CEMS or sorbent trap monitoring systems to
continuously monitor the Hg emissions rate in units of lb/GWh, or for MATS units that
use CEMS to continuously monitor the SO2, HC1, or HF emission rate in units of
lb/MWh:
1) If, for Part 75 purposes, you report gross electrical load in megawatts (MW) in the
Hourly Operating Data records, report the maximum gross electrical load value in
MW in this field. In this case, the hourly load data stream, in megawatts, in the
Hourly Operating Data records will suffice for both Part 75 and MATS purposes.
Otherwise:
2) If, for Part 75 purposes, you report steam load or mmBtu/hr in the HOURLY
Operating Data records, report the maximum steam load or the maximum
mmBtu/hr value in this field (as applicable). However, for the purposes of the MATS
rule, you must report a second hourly load data stream, i.e., the equivalent hourly
gross electrical load in megawatts, in the Hourly Operating Data records.
• Leave this field blank for units that do not produce electrical or steam load.
Maximum Load Units of Measure Code (MaximumLoadUnitsOjMeasureCodej
Identify the type of load information reported in this record by using the appropriate uppercase
codes as shown in Table 64. Note that you must report the same units of measure in this field as
are used to report hourly load for Part 75 purposes in the Hourly Operating Data records.
Table 64: 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.
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13.0 Monitoring Load Data
Lower Operation Boundary (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.
Upper Operation Boundary (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 (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
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13.0 Monitoring Load Data
described in Section 6.5.2.1(c) of Appendix A. For all SO2, NOx, and flowRATAs 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 (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).
Second Normal Indicator (SecondNormallndicator)
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 (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 (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.
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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 (BeginHour)
Report the hour in which the load information became effective.
End Date (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 (EndHour)
Report the last date on which the load information was in effect. This value should be left blank
for active records.
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 two load levels are
designated as normal and 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
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 "FT (for high-load) when the normal load level should
have been "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.
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.
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13.0 Monitoring Load Data
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.
MATS Units Reporting Steam Load or mmBtu/hr for Part 75
If you seek to comply with one or more electrical output-based SO2, Hg, HF, or HC1 emission
rate limits under the MATS rule, you must report gross electrical load in megawatts. However,
if, for Part 75 purposes, you report steam load or mmBtu/hr in the Hourly Operating Data
records and in the Maximum Load Value data element of this section, you must report the
equivalent hourly electrical load (MW) in the MATS Hour Load data element in the HOURLY
Operating Data records.
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14.0 Monitoring Qualification Data
140 Monitoring Qualification Data
Monitoring Qualification, Data Overv iew
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. Also, you are strongly encouraged to report an optional
Monitoring Qualification Data record if your EGU is subject to the MATS rule and you are
using the low-emitting EGU (LEE) option to demonstrate:
• Hg compliance for any EGU(s); or
• HC1 compliance for any coal-fired, petroleum coke-fired, or IGCC EGU(s).
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 using the applicable Qualification Type Code (PRATA1 or
PRATA2).
To indicate that a MATS-affected unit or units are in an emissions averaging group, report this
record with the applicable Qualification Type Code (HGAVG).
Monitorine Qualification. Data XML Model
Figure 24: Monitoring Qualification Data XML Elements
~ QualiicatlonTy peCode
— BeglnDate
r--l MonitoringQuatLEEData 1+1
, i™
—(-J3- Fl- + - MonitoringQualLMEData |$|
1 - -J MonitoringQualPercentData ffl
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14.0 Monitoring Qualification Data
Dependencies for Monitoring Qualification. Data
mmmmeffi&mmi&xn
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
• Monitoring Qual LEE Data
The complex elements cannot be submitted for a monitoring plan unless an applicable
Monitoring Qualification Data record is included.
Monitoring Qualification Data XML Elements
i-fr.':r
Qualification Type Code (QualificationTypeCode)
Report a code from the Table 65 specifying the type of qualification being sought:
Table 65: Qualification Type Codes and Descriptions
Category
Code
Description
Low-emitting EGU
(LEE)— Hg or HC1
LEE
LEE qualification
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
Peaking
PK
Peaking Unit Qualification (Annual)
SK
Peaking Unit Qualification for Ozone Season (applies
exclusivelv to sources that reoort on an ozone season-onlv
basis)
QA Test Exemption
pratai
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
MATS Emissions
Averaging
HGAVG
MATS-affected unit in an emission averaging group
Begin Date (BeginDate)
Report the date on which qualification will become effective.
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14.0 Monitoring Qualification Data
For gas-fired and peaking unit qualifications and for LME, LEE, and HGAVG 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.
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 (EndDate)
If applicable, report the date on which the qualification ended.
For gas-fired and peaking unit qualifications and for LME and LEE 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 or the MATS Rule.
For HGAVG qualifications, this would be the last day the unit was associated with an emission
averaging group.
Specific Considerations
Optional Reporting of LEE Qualification Data
For units that qualify for and elect to use the LEE compliance option for Hg or HC1, EPA
strongly encourages you to report an optional Hg or HC1 LEE qualification record. Although
reporting of this record is not required, if reported, it must be filled out correctly and completely.
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Monitoring Plan Reporting Instructions
14.1 Monitoring Qual LME Data
14,1 Monitoring Qual LME Data
Monitoring Qual 1, ita Overview
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, report a
Monitoring Qualification Data record with a QualificationTypeCode of "LMES" 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 66 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 66: Data Requirements for Monitoring Qual LME
Linked to MONITORING QUALIFICATION DATA
Record with QualificationTypeCode:
LMEA
LMES
Reporting
Frequency
Program Applicability
so2
Tons
NOx
Tons
S02
Tons
NOx
Tons
Annual
Subject to Acid Rain
Program (or CSS02G1/
CSS02G2 plus CSNOX), but
not subject to Ozone Season
NOx program
V
V
Do not report LMES
record
Subject to Acid Rain
Program (or CSS02G1/
CSS02G2 plus CSNOX),
and also subject to Ozone
Season NOx program
V
V
Subject toCSS02Gl/
CSS02G2, but not subject to
any NOx program
V
—
Do not report LMES
record
Subject to Ozone Season
NOx program and reporting
year-round, but not subject to
CSS02G1/ CSS02G2
V
•/
Subject to CSNOX, but not
subject to CSS02G1/
CSS02G2or Ozone Season
NOx program
V
Do not report LMES
record
Ozone Season
Only
Subject to Ozone Season
NOx program and reporting
during Ozone Season only
Do not report LMEA
record
—
•/
Monitoring Qual LME Data XML Model
Figure 25: Monitoring Qual LME Data XML Elements
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14.1 Monitoring Qual LME Data
Dependencies for Monitoring OualLME Data
¦ — ri'."-n- raeBgatttasMsg
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.
Monitoring (Mai LME Data XML Elements
Qualification Data Year (QualificationDataYear)
Report the calendar year used for the measured, estimated, or projected SO2 and/or NOx mass
emissions.
Operating Hours (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 (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 (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.
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.
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14.1 Monitoring Qual LME Data
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.
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.
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14.1 Monitoring Qual LME Data
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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Monitoring Plan Reporting Instructions
14.2 Monitoring Qual Percent Data
14,2 Monitoring Qual Percent Data
Monitoring Qual Percent Data Overview
mi
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)(l 1) 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).
Monitoring Qual Percent Data X odel
Figure 26: Monitoring Qual Percent Data XML Elements
Dependencies for Monitoring Qual Percent Data
¦ ui'i.yn inaswHww -in
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.
Monitoring Qual Percent Data XML Elements
tfr,""itrr"iil', y iii'i'i
Qualification Year (QualificationYear)
Report the year for which qualification is sought.
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14.2 Monitoring Qual Percent Data
Average Percentage Value (AveragePercentageValue)
Report the average of the three years' Percentage Values.
Year 1 Qualification Data Year (YrlQualificationDataYear)
Report the calendar year or season represented by Year 1.
Year 1 Qualification Data Type Code (YrlQualificationDataTypeCode)
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 67: Qualification Data Type Codes 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 (YrIPercentageValue)
Report the percent capacity factor or the percent of heat input from gaseous fuel for Year 1.
Year 2 Qualification Data Year (Yr2QualificationDataYear)
Report the calendar year or season represented by Year 2.
Year 2 Qualification Data Type Code (Yr2QualificationDataTypeCodej
Report one of the codes from Table 65, 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 (Yr2PercentageValue)
Report the percent capacity factor or the percent of heat input from gaseous fuel for Year 2.
Year 3 Qualification Data Year (Yr3QualificationDataYear)
Report the calendar year or season represented by Year 3.
Year 3 Qualification Data Type Code (Yr3QualificationDataTypeCodej
Report one of the codes from Table 65, 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 (Yr3PercentageValuej
Report the percent capacity factor or the percent of heat input from gaseous fuel for Year 3.
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.
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14.2 Monitoring Qual Percent Data
• 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 68: Example Data for Qualification Based on Historical and Projected Data
Initial
Qiialil'vin^
Methodology
Data 1
Current
Year
leporled in
Year 1
Momio
Type
iiv; Qi \l
Year 2
Pi k( i yi
Type
Data Rei
Year 3
oi'd
Type
Actual Historical
Data
2000
1997
A
1998
A
1999
A
2001
1998
A
1999
A
2000
A
2002
1999
A
2000
A
2001
A
Projected Data
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
Actual Historical
Data and Projected
Data
2001
2000
A
2001
P
2002
P
2002
2000
A
2001
A
2002
P
2003
2000
A
2001
A
2002
A
* A = Actual historical data; P = Projected data
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.
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Monitoring Plan Reporting Instructions 14.2 Monitoring Qual Percent Data
• 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 69, below).
Table 69: Example of Gas-Fired Qualification Based on Unit Operating Data
Initial Qualifying
Methodology
Data R
Current
Year
eporled in
Year 1
Momtoi
Type
ilNc; Ql \l.
Year 2
l>l K( 1 VI
Type
Data Rec
Year 3
ord
Type
Qualifying Based on
720 Hours of Unit
Operating Data
After the first year,
available historical
data must be provided.
2000
2000
D**
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
** Initial qualification based on 720 hours of unit operating 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 gas-
fired 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
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Monitoring Plan Reporting Instructions
14.2 Monitoring Qual Percent Data
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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14.3 Monitoring Qual LEE Data
14,3 Monitoring Qual LEE Data
Monitoring Qual LEE Data Overview
For EGUs subject to the MATS Rule, you are encouraged to report a Monitoring Qual LEE
Data record to provide initial and on-going evidence that an existing EGU (or a group of EGUs
sharing a common stack) qualifies as a low-emitter of Hg or HC1 under 40 CFR 63.10005(h).
Note, however, that for HC1, this record applies only to coal-fired, petroleum coke-fired, and
IGCC EGUs.
(Note: For Hg, use of the LEE methodology is restricted to existing EGUs and is prohibited for
scrubbed units with main stack and bypass stack configurations). For HC1, the LEE option is
available for both new and existing EGUs).
For an EGU with a single unit-single stack configuration, the LEE methodology may be used if it
is demonstrated either that:
• The unit's potential to emit is less than 29.0 lb of Hg per year; or
• The unit's Hg emission rate is less than 10% of the applicable emission standard in Table
2 of 40 CFR Part 63, Subpart UUUUU.
A candidate EGU must undergo a 30 operating day demonstration test using EPA Method 30B
(for Hg concentration) together with other measured parameters to show that the unit qualifies as
a LEE. To retain LEE status, the demonstration test must be repeated annually.
For a group of candidate units that share a common stack, you may either perform the 30
operating day demonstration test on each individual unit or test at the common stack.
• If the common stack testing option is chosen, the individual units sharing the stack will
qualify as LEEs if:
o The average Hg emission rate from the test is < 10% of the applicable emission
standard; or
o The average Hg emission rate from the test meets the applicable emission
standard and the calculated annual Hg mass emissions from the group of units do
not exceed 29.0 lb times the number of units sharing the stack.
• If the group of units sharing the stack qualifies for LEE status, report a Monitoring
Qual LEE Data record for the common stack.
For a candidate EGU with a multiple stack or duct exhaust configuration (excluding scrubbed
units with a main stack and bypass stack), you must separately test each stack or duct. The unit
qualifies for LEE status if:
• The Hg emission rate is < 10% of the applicable Hg emission standard at all of the stacks
or ducts; or
• The sum of the calculated annual Hg mass emissions from all of the stacks or ducts does
not exceed 29.0 lb.
The LEE methodology for HC1 may be used if performance test results show that the HC1
emissions are less than 50 percent of the applicable limit in Table 1 or Table 2 of Subpart
UUUUU for 3 consecutive years.
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14.3 Monitoring Qual LEE Data
Monitoring Qua! LEE Data XML Model
.-iiii-r. ^i;/\-/';r/T/'.-;;ilVL'iwiw.ifr.*iiiiww«aw«gawiMMifeiMWW'i'i'';iii;li;li;li;lrvir)'irr-.'r
Figure 27: Monitoring Qual LEE Data XML Elements
Dependencies for Monitoring Qual LEE Data
The Monitoring Qual LEE Data record is dependent on the Monitoring Qualification
Data record.
No other records are dependent upon the Monitoring Qual LEE Data record.
Monitoring Qual LEE Data XML Elements
Qualification Test Date (QualificationTestDate)
For Hg, report the end date (MMDDYYYY) of the demonstration test (i.e., either the initial LEE
qualifying test or the latest retest, as applicable) showing that the unit (or group of units sharing a
common stack) qualifies to use the LEE methodology.
For HC1, report the end date (MMDDYYYY) of the performance test that completes the 3-year
demonstration for LEE qualification.
Parameter Code (ParameterCode)
Report the appropriate Parameter code (HG or HCL) associated with the LEE qualification.
Qualification Test Type (QualificationTestType)
Indicate whether the LEE qualification test is the initial 30 operating day demonstration test or a
retest. Report "INITIAL" if it is the initial test and "RETEST" if it is a retest.
Potential Annual Hg Mass Emissions (PotentialAnnualHgMassEmissions)
If the unit (or group of units sharing a common stack) seeks to qualify for the LEE methodology
based on its potential annual Hg mass emissions, report the calculated annual emissions in
pounds (rounded off to one decimal place). Calculate the potential annual Hg mass emissions
according to 40 CFR 63.10005(h). Leave this field blank if LEE qualification for Hg is based on
emitting at less than 10% of the applicable emission standard.
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14.3 Monitoring Qual LEE Data
Applicable Emission Standard (ApplicableEmissionStandard)
If the unit (or group of units sharing a common stack) seeks to qualify as a LEE by emitting at
less than 10% of the applicable Hg emission standard, specify the numerical value of that
standard. This field should be reported in standard notation and not scientific notation. Leave this
field blank if LEE qualification is based on the potential annual Hg mass emissions.
Units of Standard (UnitsofStandard)
If the unit (or group of units sharing a common stack) seeks to qualify for LEE by emitting at
less than 10% of the applicable Hg emission standard or less than 50% of the applicable HC1
emission standard, specify the units of measure of that standard. Report "LBTBTU" if the units
of the standard are lb/TBtu, "LBMBTU" if the units of the standard are lb/mmBtu, "LBMWH" if
the units of the standard are lb/MWh, and "LBGWH" if the units of the standard are lb/GWh.
Leave this field blank if Hg LEE qualification is based on the potential annual Hg mass
emissions.
Percentage of Emission Standard (PercentageOfEmissionStandard)
If the unit (or group of units sharing a common stack) qualifies for LEE based on emitting at less
than 10%) of the applicable Hg emission standard or less than 50% of the applicable HC1
emission standard, report the results of the demonstration test (or retest) as a percentage of the
standard, rounded to one decimal place. Leave this field blank if Hg LEE qualification is based
on the potential annual Hg mass emissions.
Specific Considerations
Loss of LEE Status
• If the annual retest of a LEE (or group of LEEs sharing a common stack) shows that the
unit (or group of units) no longer qualifies for Hg LEE status, the owner or operator must
install and certify Hg CEMS or sorbent trap monitoring system(s) within 6 months (see
section 63.10006(b)(2) of Subpart UUUUU).
• If the triennial (i.e., once every 3 years) HC1 retest of a LEE shows that the unit no longer
qualifies for HC1 LEE status, the owner or operator must conduct quarterly emissions
testing for HC1.
• If LEE status is lost, update the Monitoring Qualification Data record by completing
the end date. Also submit Monitoring Method Data or Supplemental MATS
Monitoring Method Data records (as applicable), indicating changes in monitoring
methodologies with the appropriate effective dates (see Sections 6.0 and 6.1, above).
Note that reporting of Supplemental MATS Monitoring Method Data records is
optional.
Updating the Monitoring Qual LEE Data Record
For a unit (or group of units sharing a common stack) that initially qualifies for LEE status, the
Monitoring Qual Hg LEE Data record must be updated annually (for Hg) or every three years
(for HC1), based on the results of each required retest.
September 11, 2019
Page 140
Environmental Protection Agency
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