DAQ-2025-002461

1

DAQC-426-25
Site ID 10327 (B5)

MEMORANDUM

TO: CEM FILE – INTERMOUNTAIN POWER SERVICE CORPORATION (IPSC)

THROUGH: Harold Burge, Major Source Compliance Section Manager

FROM: Rob Leishman, Environmental Scientist

DATE: May 5, 2025

SUBJECT: Source: Units 3 and 4 (CNG and Hydrogen fired turbine generator units)
Contact: Mike Utley – 435-864-6489
Trevor Johnson – 435-864-6493
Location: 850 Brush Wellman Road, Delta, Millard County, UT
Test Contractor: Alliance Source Testing, LLC
FRS ID#: UT0000004902700010
Permit/AO#: Title V operating permit# 2700010006 dated November 21, 2023
Approval Order (AO) DAQE-AN103270030-22 dated December
5, 2022
40 CFR 75 Appendix A
Subject: Review of RA/PST Protocol dated March 31, 2025
On April 4, 2025, Utah Division of Air Quality (DAQ) received a protocol for a RA/PST (relative
accuracy/performance specification test) of the IPSC Units 3 and 4 in Delta, Utah. Additional testing
information was submitted on May 2, 2025. Testing will be performed on June 18-19, 2025, to determine
the relative accuracy of the O2, NOX, CO, and CO2 and flow monitoring systems.

PROTOCOL CONDITIONS:

1. RM 3A used to determine dry molecular weight of the gas stream: OK
2. RM 7E used to determine NOX concentrations of emissions: OK
3. RM 10 used to determine CO concentrations of emissions: OK
4. RM 19 used to determine volumetric flow: OK
DEVIATIONS: No deviations were noted.

CONCLUSION: The protocol appears to be acceptable.

RECOMMENDATION: Send attached protocol review and test date confirmation notice.

1 8 2

Intermountain Power Service Corporation
850 West Brush Wellman Road, Delta, Utah, 84624 / Telephone: [phone] / FAX: [phone] / Fed. I.D. #87-0388573

March 31, 2025

Mr. Bryce Bird, Director Utah Division of Air Quality 195 North 1950 West P.O. Box 144820
Salt Lake City, Utah 84114- 4820 CEMS Initial Certification Testing and RATA Notification Intermountain Power Service Corporation (IPSC) Title V Operating Permit #2700010006
Dear Director Bird:
This letter is written to notify the Utah Department of Air Quality (UDAQ) of the initial 7-day Calibration Error test, the initial Cycle Time test, and the initial Linearity test for the Unit 3SGA and Unit 4SGA Continuous Emissions Monitoring System’s (CEMS) at
the Intermountain Generating Station (IGS). These tests are scheduled to begin on April 30, 2025. This letter is also written to notify UDAQ that the Relative Accuracy Test Audit (RATA) for the Unit 3SGA CEMS is scheduled to begin on June 2, 2025, and the Unit
4SGA CEMS RATA is scheduled to begin on June 9, 2025. Attached is TIC’s CEMS Notification Test Procedure for your review and approval. TIC, Mitsubishi, and Alliance will be overseeing and conducting these tests. UDAQ personnel are invited to observe the testing.
Based on information and belief formed after reasonable inquiry, I certify that the statements and information in the document are true, accurate, and complete. Questions or comments may be directed to Mr. Mike Utley at [phone] or [e-mail].

Sincerely,

Dahl J. Dalton President and Chief Operations Officer and Responsible Official
KS/HBI:jmj
Page 2 March 31, 2025 Mr. Bryce Bird

Attachment: IPP CEMS Notification Procedure Documentation cc: Kevin Peng, LADWP Tamer Ellyahky, LADWP
Andrea Villarin, LADWP Shudeish Mahadev, LADWP
Trevor Johnson

The purpose of this document is to provide additional context on the testing procedure TIC,
Mitsubishi, and Alliance will be following when conducting Continuous Emissions Testing
of the IPP Renewed Combined Cycle Power Plant Stacks. In conjuncture with the
Mitsubishi Emission Measurement Test Procedure, Appendix A of 40 CFR 75 Continuous
Emission Monitoring Specifications and Test Procedures will also be followed as listed in
the IPP Renewal Project Generation EPC Contract.

Figure 1: EPC Contract IPP HRSG Stack CEMS Performance and Design Requirements

Requirements for Air Emission Testing – 40 CFR Appendix-A-to-Part-75 6.1.2
Linearity check (General Procedures) – 40 CFR Appendix-A-to-Part-75 6.2
7-Day Calibration Error Test – 40 CFR Appendix-A-to-Part-75 6.3
Cycle Time Test – 40 CFR Appendix-A-to-Part-75 6.4
Relative Accuracy and Bias Tests – 40 CFR Appendix-A-to-Part-75 6.5

Appendix A of 40 CFR 75
Continuous Emission Monitoring
Specifications and Test Procedures
Title 40 —Protection of Environment
Chapter I —Environmental Protection Agency
Subchapter C —Air Programs
Part 75 —Continuous Emission Monitoring
Source:63 FR 57507, Oct. 27, 1998, unless otherwise noted.
Authority:42 U.S.C. 7401-7671q and 7651k note.
Source:58 FR 3701, Jan. 11, 1993, unless otherwise noted.
Appendix A to Part 75—Specifications and Test Procedures
1. Installation and Measurement Location
1.1 Gas Monitors
1.1.1 Point Monitors
1.1.2 Path Monitors
1.2 Flow Monitors
This content is from the eCFR and is authoritative but unofficial.
(a)Following the procedures in section 8.1.1 of Performance Specification 2 in appendix B to part
60 of this chapter, install the pollutant concentration monitor or monitoring system at a
location where the pollutant concentration and emission rate measurements are directly
representative of the total emissions from the affected unit. Select a representative
measurement point or path for the monitor probe(s) (or for the path from the transmitter to the
receiver) such that the SO2, CO2, O2, or NOX concentration monitoring system or NOX-diluent
CEMS (NOX pollutant concentration monitor and diluent gas monitor) will pass the relative
accuracy test (see section 6 of this appendix).
(b)It is recommended that monitor measurements be made at locations where the exhaust gas
temperature is above the dew-point temperature. If the cause of failure to meet the relative
accuracy tests is determined to be the measurement location, relocate the monitor probe(s).
Locate the measurement point (1) within the centroidal area of the stack or duct cross section,
or (2) no less than 1.0 meter from the stack or duct wall.
Locate the measurement path (1) totally within the inner area bounded by a line 1.0 meter from
the stack or duct wall, or (2) such that at least 70.0 percent of the path is within the inner 50.0
percent of the stack or duct cross-sectional area, or (3) such that the path is centrally located
within any part of the centroidal area.
Editorial Note:Nomenclature changes to part 75 appear at 67 FR 40476, June 12, 2002.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures Appendix A to Part 75, Title 40 (Mar. 27, 2025)
40 CFR Appendix-A-to-Part-75 1.1(b) (enhanced display)page 1 of 59
1.2.1 Acceptability of Monitor Location
1.2.2 Alternative Monitoring Location
Install the flow monitor in a location that provides representative volumetric flow over all operating
conditions. Such a location is one that provides an average velocity of the flue gas flow over the
stack or duct cross section, provides a representative SO2 emission rate (in lb/hr), and is
representative of the pollutant concentration monitor location. Where the moisture content of the
flue gas affects volumetric flow measurements, use the procedures in both Reference Methods 1
and 4 of appendix A to part 60 of this chapter to establish a proper location for the flow monitor. The
EPA recommends (but does not require) performing a flow profile study following the procedures in
40 CFR part 60, appendix A, method, 1, sections 11.5 or 11.4 for each of the three operating or load
levels indicated in section 6.5.2.1 of this appendix to determine the acceptability of the potential
flow monitor location and to determine the number and location of flow sampling points required to
obtain a representative flow value. The procedure in 40 CFR part 60, appendix A, Test Method 1,
section 11.5 may be used even if the flow measurement location is greater than or equal to 2
equivalent stack or duct diameters downstream or greater than or equal to 1⁄2 duct diameter
upstream from a flow disturbance. If a flow profile study shows that cyclonic (or swirling) or
stratified flow conditions exist at the potential flow monitor location that are likely to prevent the
monitor from meeting the performance specifications of this part, then EPA recommends either (1)
selecting another location where there is no cyclonic (or swirling) or stratified flow condition, or (2)
eliminating the cyclonic (or swirling) or stratified flow condition by straightening the flow, e.g., by
installing straightening vanes. EPA also recommends selecting flow monitor locations to minimize
the effects of condensation, coating, erosion, or other conditions that could adversely affect flow
monitor performance.
The installation of a flow monitor is acceptable if either (1) the location satisfies the minimum
siting criteria of method 1 in appendix A to part 60 of this chapter (i.e., the location is greater
than or equal to eight stack or duct diameters downstream and two diameters upstream from a
flow disturbance; or, if necessary, two stack or duct diameters downstream and one-half stack
or duct diameter upstream from a flow disturbance), or (2) the results of a flow profile study, if
performed, are acceptable (i.e., there are no cyclonic (or swirling) or stratified flow conditions),
and the flow monitor also satisfies the performance specifications of this part. If the flow
monitor is installed in a location that does not satisfy these physical criteria, but nevertheless
the monitor achieves the performance specifications of this part, then the location is
acceptable, notwithstanding the requirements of this section.
Whenever the owner or operator successfully demonstrates that modifications to the exhaust
duct or stack (such as installation of straightening vanes, modifications of ductwork, and the
like) are necessary for the flow monitor to meet the performance specifications, the
Administrator may approve an interim alternative flow monitoring methodology and an
extension to the required certification date for the flow monitor.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 1.1(b)
40 CFR Appendix-A-to-Part-75 1.1(b) (enhanced display)page 2 of 59
2. Equipment Specifications
2.1 Instrument Span and Range
2.1.1 SO2 Pollutant Concentration Monitors
2.1.1.1 Maximum Potential Concentration
Where no location exists that satisfies the physical siting criteria in section 1.2.1, where the
results of flow profile studies performed at two or more alternative flow monitor locations are
unacceptable, or where installation of a flow monitor in either the stack or the ducts is
demonstrated to be technically infeasible, the owner or operator may petition the Administrator
for an alternative method for monitoring flow.
In implementing sections 2.1.1 through 2.1.6 of this appendix, set the measurement range for each
parameter (SO2, NOX, CO2, O2, or flow rate) high enough to prevent full-scale exceedances from
occurring, yet low enough to ensure good measurement accuracy and to maintain a high signal-to-
noise ratio. To meet these objectives, select the range such that the majority of the readings
obtained during typical unit operation are kept, to the extent practicable, between 20.0 and 80.0
percent of the full-scale range of the instrument. These guidelines do not apply to: (1) SO2 readings
obtained during the combustion of very low sulfur fuel (as defined in § 72.2 of this chapter); (2) SO2
or NOX readings recorded on the high measurement range, for units with SO2 or NOX emission
controls and two span values, unless the emission controls are operated seasonally (for example,
only during the ozone season); or (3) SO2 or NOX readings less than 20.0 percent of full-scale on the
low measurement range for a dual span unit, provided that the maximum expected concentration
(MEC), low-scale span value, and low-scale range settings have been determined according to
sections 2.1.1.2, 2.1.1.4(a), (b), and (g) of this appendix (for SO2), or according to sections 2.1.2.2,
2.1.2.4(a) and (f) of this appendix (for NOX).
Determine, as indicated in sections 2.1.1.1 through 2.1.1.5 of this appendix the span value(s)
and range(s) for an SO2 pollutant concentration monitor so that all potential and expected
concentrations can be accurately measured and recorded. Note that if a unit exclusively
combusts fuels that are very low sulfur fuels (as defined in § 72.2 of this chapter), the SO2
monitor span requirements in § 75.11(e)(3)(iv)apply in lieu of the requirements of this section.
(a)Make an initial determination of the maximum potential concentration (MPC) of SO2
by using Equation A-1a or A-1b. Base the MPC calculation on the maximum percent
sulfur and the minimum gross calorific value (GCV) for the highest-sulfur fuel to be
burned. The maximum sulfur content and minimum GCV shall be determined from all
available fuel sampling and analysis data for that fuel from the previous 12 months
(minimum), excluding clearly anomalous fuel sampling values. If both the fuel sulfur
content and the GCV are routinely determined from each fuel sample, the owner or
operator may, as an alternative to using the highest individual percent sulfur and
lowest individual GCV values in the MPC calculation, pair the sulfur content and GCV
values from each sample analysis and calculate the ratio of percent sulfur to GCV
(i.e.,%S/GCV) for each pair of values. If this option is selected, the MPC shall be
calculated using the highest %S/GCV ratio in Equation A-1a or A-1b. If the designated
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.1.1(a)
40 CFR Appendix-A-to-Part-75 2.1.1.1(a) (enhanced display)page 3 of 59
Note:All percent values to be inserted in the equations of this section are to be
expressed as a percentage, not a fractional value (e.g., 3, not .03).
representative certifies that the highest-sulfur fuel is never burned alone in the unit
during normal operation but is always blended or co-fired with other fuel(s), the MPC
may be calculated using a best estimate of the highest sulfur content and lowest
gross calorific value expected for the blend or fuel mixture and inserting these values
into Equation A-1a or A-1b. Derive the best estimate of the highest percent sulfur and
lowest GCV for a blend or fuel mixture from weighted-average values based upon the
historical composition of the blend or mixture in the previous 12 (or more) months. If
insufficient representative fuel sampling data are available to determine the
maximum sulfur content and minimum GCV, use values from contract(s) for the
fuel(s) that will be combusted by the unit in the MPC calculation.
or
Where,
MPC = Maximum potential concentration (ppm, wet basis). (To convert to dry basis,
divide the MPC by 0.9.)
MEC = Maximum expected concentration (ppm, wet basis). (To convert to dry basis,
divide the MEC by 0.9).
%S = Maximum sulfur content of fuel to be fired, wet basis, weight percent, as
determined according to the applicable method in paragraph (c) of section 2.1.1.1.
%O2w = Minimum oxygen concentration, percent wet basis, under typical operating
conditions.
%CO2w = Maximum carbon dioxide concentration, percent wet basis, under typical
operating conditions.
GCV = Minimum gross calorific value of the fuel or blend to be combusted, based on
historical fuel sampling and analysis data or, if applicable, based on the fuel contract
specifications (Btu/lb). If based on fuel sampling and analysis, the GCV shall be
determined according to the applicable method in paragraph (c) of section 2.1.1.1.
11.32 × 106 = Oxygen-based conversion factor in Btu/lb (ppm)/%.
66.93 × 106 = Carbon dioxide-based conversion factor in Btu/lb (ppm)/%.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.1.1(a)
40 CFR Appendix-A-to-Part-75 2.1.1.1(a) (enhanced display)page 4 of 59
2.1.1.2 Maximum Expected Concentration
(b)Alternatively, if a certified SO2 CEMS is already installed, the owner or operator may
make the initial MPC determination based upon quality-assured historical data
recorded by the CEMS. For the purposes of this section, 2.1.1.1, a “certified” CEMS
means a CEM system that has met the applicable certification requirements of
either: This part, or part 60 of this chapter, or a State CEM program, or the source
operating permit. If this option is chosen, the MPC shall be the maximum SO2
concentration observed during the previous 720 (or more) quality-assured monitor
operating hours when combusting the highest-sulfur fuel (or highest-sulfur blend if
fuels are always blended or co-fired) that is to be combusted in the unit or units
monitored by the SO2 monitor. For units with SO2 emission controls, the certified SO2
monitor used to determine the MPC must be located at or before the control device
inlet. Report the MPC and the method of determination in the monitoring plan
required under § 75.53. Note that the initial MPC value is subject to periodic review
under section 2.1.1.5 of this appendix. If an MPC value is found to be either
inappropriately high or low, the MPC shall be adjusted in accordance with section
2.1.1.5, and corresponding span and range adjustments shall be made, if necessary.
(c)When performing fuel sampling to determine the MPC, use ASTM Methods: ASTM
D129-00, ASTM D240-00, ASTM D1552-01, ASTM D2622-98, ASTM D3176-89
(Reapproved 2002), ASTM D3177-02 (Reapproved 2007), ASTM D4239-02, ASTM
D4294-98, ASTM D5865-01a, or ASTM D5865-10 (all incorporated by reference under
§ 75.6).
(a)Make an initial determination of the maximum expected concentration (MEC) of SO2
whenever: (a) SO2 emission controls are used; or (b) both high-sulfur and low-sulfur
fuels (e.g., high-sulfur coal and low-sulfur coal or different grades of fuel oil) or high-
sulfur and low-sulfur fuel blends are combusted as primary or backup fuels in a unit
without SO2 emission controls. For units with SO2 emission controls, use Equation
A-2 to make the initial MEC determination. When high-sulfur and low-sulfur fuels or
blends are burned as primary or backup fuels in a unit without SO2 controls, use
Equation A-1a or A-1b to calculate the initial MEC value for each fuel or blend, except
for: (1) the highest-sulfur fuel or blend (for which the MPC was previously calculated
in section 2.1.1.1 of this appendix); (2) fuels or blends that are very low sulfur fuels
(as defined in § 72.2 of this chapter); or (3) fuels or blends that are used only for unit
startup. Each initial MEC value shall be documented in the monitoring plan required
under § 75.53. Note that each initial MEC value is subject to periodic review under
section 2.1.1.5 of this appendix. If an MEC value is found to be either inappropriately
high or low, the MEC shall be adjusted in accordance with section 2.1.1.5, and
corresponding span and range adjustments shall be made, if necessary.
(b)For each MEC determination, substitute into Equation A-1a or A-1b the highest sulfur
content and minimum GCV value for that fuel or blend, based upon all available fuel
sampling and analysis results from the previous 12 months (or more), or, if fuel
sampling data are unavailable, based upon fuel contract(s).
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.1.1(b)
40 CFR Appendix-A-to-Part-75 2.1.1.2(b) (enhanced display)page 5 of 59
2.1.1.3 Span Value(s) and Range(s)
(c)Alternatively, if a certified SO2 CEMS is already installed, the owner or operator may
make the initial MEC determination(s) based upon historical monitoring data. For the
purposes of this section, 2.1.1.2, a “certified” CEMS means a CEM system that has
met the applicable certification requirements of either: This part, or part 60 of this
chapter, or a State CEM program, or the source operating permit. If this option is
chosen for a unit with SO2 emission controls, the MEC shall be the maximum SO2
concentration measured downstream of the control device outlet by the CEMS over
the previous 720 (or more) quality-assured monitor operating hours with the unit and
the control device both operating normally. For units that burn high- and low-sulfur
fuels or blends as primary and backup fuels and have no SO2 emission controls, the
MEC for each fuel shall be the maximum SO2 concentration measured by the CEMS
over the previous 720 (or more) quality-assured monitor operating hours in which
that fuel or blend was the only fuel being burned in the unit.
Where:
MEC = Maximum expected concentration (ppm).
MPC = Maximum potential concentration (ppm), as determined by Eq. A-1a or A-1b in
section 2.1.1.1 of this appendix.
RE = Expected average design removal efficiency of control equipment (%).
Determine the high span value and the high full-scale range of the SO2 monitor as follows.
(Note: For purposes of this part, the high span and range refer, respectively, either to the
span and range of a single span unit or to the high span and range of a dual span unit.)
The high span value shall be obtained by multiplying the MPC by a factor no less than 1.00
and no greater than 1.25. Round the span value upward to the next highest multiple of 100
ppm. If the SO2 span concentration is ≤500 ppm, the span value may either be rounded
upward to the next highest multiple of 10 ppm, or to the next highest multiple of 100 ppm.
The high span value shall be used to determine concentrations of the calibration gases
required for daily calibration error checks and linearity tests. Select the full-scale range of
the instrument to be consistent with section 2.1 of this appendix and to be greater than or
equal to the span value. Report the full-scale range setting and calculations of the MPC
and span in the monitoring plan for the unit. Note that for certain applications, a second
(low) SO2 span and range may be required (see section 2.1.1.4 of this appendix). If an
existing State, local, or federal requirement for span of an SO2 pollutant concentration
monitor requires or allows the use of a span value lower than that required by this section
or by section 2.1.1.4 of this appendix, the State, local, or federal span value may be used if
a satisfactory explanation is included in the monitoring plan, unless span and/or range
adjustments become necessary in accordance with section 2.1.1.5 of this appendix. Span
values higher than those required by either this section or section 2.1.1.4 of this appendix
must be approved by the Administrator.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.1.2(c)
40 CFR Appendix-A-to-Part-75 2.1.1.2(c) (enhanced display)page 6 of 59
2.1.1.4 Dual Span and Range Requirements
For most units, the high span value based on the MPC, as determined under section
2.1.1.3 of this appendix will suffice to measure and record SO2 concentrations (unless
span and/or range adjustments become necessary in accordance with section 2.1.1.5 of
this appendix). In some instances, however, a second (low) span value based on the MEC
may be required to ensure accurate measurement of all possible or expected SO2
concentrations. To determine whether two SO2 span values are required, proceed as
follows:
(a)For units with SO2 emission controls, compare the MEC from section 2.1.1.2 of this
appendix to the high full-scale range value from section 2.1.1.3 of this appendix. If
the MEC is ≥20.0 percent of the high range value, then the high span value and range
determined under section 2.1.1.3 of this appendix are sufficient. If the MEC is <20.0
percent of the high range value, then a second (low) span value is required.
(b)For units that combust high- and low-sulfur primary and backup fuels (or blends) and
have no SO2 controls, compare the high range value from section 2.1.1.3 of this
appendix (for the highest-sulfur fuel or blend) to the MEC value for each of the other
fuels or blends, as determined under section 2.1.1.2 of this appendix. If all of the
MEC values are ≥20.0 percent of the high range value, the high span and range
determined under section 2.1.1.3 of this appendix are sufficient, regardless of which
fuel or blend is burned in the unit. If any MEC value is <20.0 percent of the high range
value, then a second (low) span value must be used when that fuel or blend is
combusted.
(c)When two SO2 spans are required, the owner or operator may either use a single SO2
analyzer with a dual range (i.e., low- and high-scales) or two separate SO2 analyzers
connected to a common sample probe and sample interface. Alternatively, if RATAs
are performed and passed on both measurement ranges, the owner or operator may
use two separate SO2 analyzers connected to separate probes and sample
interfaces. For units with SO2 emission controls, the owner or operator may use a low
range analyzer and a default high range value, as described in paragraph (f)of this
section, in lieu of maintaining and quality assuring a high-scale range. Other monitor
configurations are subject to the approval of the Administrator.
(d)The owner or operator shall designate the monitoring systems and components in
the monitoring plan under § 75.53 as follows: when a single probe and sample
interface are used, either designate the low and high monitor ranges as separate SO2
components of a single, primary SO2 monitoring system; designate the low and high
monitor ranges as the SO2 components of two separate, primary SO2 monitoring
systems; designate the normal monitor range as a primary monitoring system and
the other monitor range as a non-redundant backup monitoring system; or, when a
single, dual-range SO2 analyzer is used, designate the low and high ranges as a
single SO2 component of a primary SO2 monitoring system (if this option is selected,
use a special dual-range component type code, as specified by the Administrator, to
satisfy the requirements of § 75.53(e)(1)(iv)(D)). When two SO2 analyzers are
connected to separate probes and sample interfaces, designate the analyzers as the
SO2 components of two separate, primary SO2 monitoring systems. For units with
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.1.4(a)
40 CFR Appendix-A-to-Part-75 2.1.1.4(d) (enhanced display)page 7 of 59
2.1.1.5 Adjustment of Span and Range
SO2 controls, if the default high range value is used, designate the low range analyzer
as the SO2 component of a primary SO2 monitoring system. Do not designate the
default high range as a monitoring system or component. Other component and
system designations are subject to approval by the Administrator. Note that the
component and system designations for redundant backup monitoring systems shall
be the same as for primary monitoring systems.
(e)Each monitoring system designated as primary or redundant backup shall meet the
initial certification and quality assurance requirements for primary monitoring
systems in § 75.20(c)or § 75.20(d)(1), as applicable, and appendices A and B to this
part, with one exception: relative accuracy test audits (RATAs) are required only on
the normal range (for units with SO2 emission controls, the low range is considered
normal). Each monitoring system designated as a non-redundant backup shall meet
the applicable quality assurance requirements in § 75.20(d)(2).
(f)For dual span units with SO2 emission controls, the owner or operator may, as an
alternative to maintaining and quality assuring a high monitor range, use a default
high range value. If this option is chosen, the owner or operator shall report a default
SO2 concentration of 200 percent of the MPC for each unit operating hour in which
the full-scale of the low range SO2 analyzer is exceeded.
(g)The high span value and range shall be determined in accordance with section
2.1.1.3 of this appendix. The low span value shall be obtained by multiplying the MEC
by a factor no less than 1.00 and no greater than 1.25, and rounding the result
upward to the next highest multiple of 10 ppm (or 100 ppm, as appropriate). For units
that burn high- and low-sulfur primary and backup fuels or blends and have no SO2
emission controls, select, as the basis for calculating the appropriate low span value
and range, the fuel-specific MEC value closest to 20.0 percent of the high full-scale
range value (from paragraph (b)of this section). The low range must be greater than
or equal to the low span value, and the required calibration gases must be selected
based on the low span value. However, if the default high range option in paragraph
(f)of this section is selected, the full-scale of the low measurement range shall not
exceed five times the MEC value (where the MEC is rounded upward to the next
highest multiple of 10 ppm). For units with two SO2 spans, use the low range
whenever the SO2 concentrations are expected to be consistently below 20.0 percent
of the high full-scale range value, i.e., when the MEC of the fuel or blend being
combusted is less than 20.0 percent of the high full-scale range value. When the full-
scale of the low range is exceeded, the high range shall be used to measure and
record the SO2 concentrations; or, if applicable, the default high range value in
paragraph (f)of this section shall be reported for each hour of the full-scale
exceedance.
For each affected unit or common stack, the owner or operator shall make a periodic
evaluation of the MPC, MEC, span, and range values for each SO2 monitor (at a minimum,
an annual evaluation is required) and shall make any necessary span and range
adjustments, with corresponding monitoring plan updates, as described in paragraphs (a),
(b), and (c)of this section. Span and range adjustments may be required, for example, as a
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.1.4(e)
40 CFR Appendix-A-to-Part-75 2.1.1.4(g) (enhanced display)page 8 of 59
result of changes in the fuel supply, changes in the manner of operation of the unit, or
installation or removal of emission controls. In implementing the provisions in paragraphs
(a)and (b)of this section, SO2 data recorded during short-term, non-representative
process operating conditions (e.g., a trial burn of a different type of fuel) shall be excluded
from consideration. The owner or operator shall keep the results of the most recent span
and range evaluation on-site, in a format suitable for inspection. Make each required span
or range adjustment no later than 45 days after the end of the quarter in which the need to
adjust the span or range is identified, except that up to 90 days after the end of that
quarter may be taken to implement a span adjustment if the calibration gases currently
being used for daily calibration error tests and linearity checks are unsuitable for use with
the new span value.
(a)If the fuel supply, the composition of the fuel blend(s), the emission controls, or the
manner of operation change such that the maximum expected or potential
concentration changes significantly, adjust the span and range setting to assure the
continued accuracy of the monitoring system. A “significant” change in the MPC or
MEC means that the guidelines in section 2.1 of this appendix can no longer be met,
as determined by either a periodic evaluation by the owner or operator or from the
results of an audit by the Administrator. The owner or operator should evaluate
whether any planned changes in operation of the unit may affect the concentration of
emissions being emitted from the unit or stack and should plan any necessary span
and range changes needed to account for these changes, so that they are made in as
timely a manner as practicable to coordinate with the operational changes.
Determine the adjusted span(s) using the procedures in sections 2.1.1.3 and 2.1.1.4
of this appendix (as applicable). Select the full-scale range(s) of the instrument to be
greater than or equal to the new span value(s) and to be consistent with the
guidelines of section 2.1 of this appendix.
(b)Whenever a full-scale range is exceeded during a quarter and the exceedance is not
caused by a monitor out-of-control period, proceed as follows:
(1)For exceedances of the high range, report 200.0 percent of the current full-scale
range as the hourly SO2 concentration for each hour of the full-scale
exceedance and make appropriate adjustments to the MPC, span, and range to
prevent future full-scale exceedances.
(2)For units with two SO2 spans and ranges, if the low range is exceeded, no
further action is required, provided that the high range is available and its most
recent calibration error test and linearity check have not expired. However, if
either of these quality assurance tests has expired and the high range is not
able to provide quality assured data at the time of the low range exceedance or
at any time during the continuation of the exceedance, report the MPC as the
SO2 concentration until the readings return to the low range or until the high
range is able to provide quality assured data (unless the reason that the high-
scale range is not able to provide quality assured data is because the high-scale
range has been exceeded; if the high-scale range is exceeded follow the
procedures in paragraph (b)(1)of this section).
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
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2.1.2 NOX Pollutant Concentration Monitors
2.1.2.1 Maximum Potential Concentration
(c)Whenever changes are made to the MPC, MEC, full-scale range, or span value of the
SO2 monitor, as described in paragraphs (a)or (b)of this section, record and report
(as applicable) the new full-scale range setting, the new MPC or MEC and
calculations of the adjusted span value in an updated monitoring plan. The
monitoring plan update shall be made in the quarter in which the changes become
effective. In addition, record and report the adjusted span as part of the records for
the daily calibration error test and linearity check specified by appendix B to this part.
Whenever the span value is adjusted, use calibration gas concentrations that meet
the requirements of section 5.1 of this appendix, based on the adjusted span value.
When a span adjustment is so significant that the calibration gases currently being
used for daily calibration error tests and linearity checks are unsuitable for use with
the new span value, then a diagnostic linearity test using the new calibration gases
must be performed and passed. Use the data validation procedures in § 75.20(b)(3),
beginning with the hour in which the span is changed.
Determine, as indicated in sections 2.1.2.1 through 2.1.2.5 of this appendix, the span and range
value(s) for the NOX pollutant concentration monitor so that all expected NOX concentrations
can be determined and recorded accurately.
(a)The maximum potential concentration (MPC) of NOX for each affected unit shall be
based upon whichever fuel or blend combusted in the unit produces the highest level
of NOX emissions. For the purposes of this section, 2.1.2.1, and section 2.1.2.2 of
this appendix, a “blend” means a frequently-used fuel mixture having a consistent
composition (e.g., an oil and gas mixture where the relative proportions of the two
fuels vary by no more than 10%, on average). Make an initial determination of the
MPC using the appropriate option as follows:
Option 1: Use 800 ppm for coal-fired and 400 ppm for oil- or gas-fired units as the
maximum potential concentration of NOX (if an MPC of 1600 ppm for coal-fired units
or 480 ppm for oil- or gas-fired units was previously selected under this section, that
value may still be used, provided that the guidelines of section 2.1 of this appendix
are met); For cement kilns, use 2000 ppm as the MPC. For process heaters, use 200
ppm if the unit burns only gaseous fuel and 500 ppm if the unit burns oil;
Option 2: Use the specific values based on boiler type and fuel combusted, listed in
Table 2-1 or Table 2-2; For a new gas-fired or oil-fired combustion turbine, if a default
MPC value of 50 ppm was previously selected from Table 2-2, that value may be used
until March 31, 2003;
Option 3: Use NOX emission test results;
Option 4: Use historical CEM data over the previous 720 (or more) unit operating
hours when combusting the fuel or blend with the highest NOX emission rate; or
Option 5: If a reliable estimate of the uncontrolled NOX emissions from the unit is
available from the manufacturer, the estimated value may be used.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
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(b)For the purpose of providing substitute data during NOX missing data periods in
accordance with §§ 75.31 and 75.33 and as required elsewhere under this part, the
owner or operator shall also calculate the maximum potential NOX emission rate
(MER), in lb/mmBtu, by substituting the MPC for NOX in conjunction with the
minimum expected CO2 or maximum O2 concentration (under all unit operating
conditions except for unit startup, shutdown, and upsets) and the appropriate F-
factor into the applicable equation in appendix F to this part. The diluent cap value of
5.0 percent CO2 (or 14.0 percent O2) for boilers or 1.0 percent CO2 (or 19.0 percent
O2) for combustion turbines may be used in the NOX MER calculation. As a second
alternative, when the NOX MPC is determined from emission test results or from
historical CEM data, as described in paragraphs (a),(d)and (e)of this section,
quality-assured diluent gas (i.e., O2 or CO2) data recorded concurrently with the MPC
may be used to calculate the MER.
(c)Report the method of determining the initial MPC and the calculation of the
maximum potential NOX emission rate in the monitoring plan for the unit. Note that
whichever MPC option in paragraph 2.1.2.1(a) of this appendix is selected, the initial
MPC value is subject to periodic review under section 2.1.2.5 of this appendix. If an
MPC value is found to be either inappropriately high or low, the MPC shall be
adjusted in accordance with section 2.1.2.5, and corresponding span and range
adjustments shall be made, if necessary.
(d)For units with add-on NOX controls (whether or not the unit is equipped with low-NOX
burner technology), or for units equipped with dry low-NOX (DLN) technology, NOX
emission testing may only be used to determine the MPC if testing can be performed
either upstream of the add-on controls or during a time or season when the add-on
controls are not in operation or when the DLN controls are not in the premixed (low-
NOX) mode. If NOX emission testing is performed, use the following guidelines. Use
Method 7E from appendix A to part 60 of this chapter to measure total NOX
concentration. (Note: Method 20 from appendix A to part 60 may be used for gas
turbines, instead of Method 7E.) Operate the unit, or group of units sharing a
common stack, at the minimum safe and stable load, the normal load, and the
maximum load. If the normal load and maximum load are identical, an intermediate
level need not be tested. Operate at the highest excess O2 level expected under
normal operating conditions. Make at least three runs of 20 minutes (minimum)
duration with three traverse points per run at each operating condition. Select the
highest point NOX concentration from all test runs as the MPC for NOX.
(e)If historical CEM data are used to determine the MPC, the data must, for uncontrolled
units or units equipped with low-NOX burner technology and no other NOX controls,
represent a minimum of 720 quality-assured monitor operating hours from the NOX
component of a certified monitoring system, obtained under various operating
conditions including the minimum safe and stable load, normal load (including
periods of high excess air at normal load), and maximum load. For the purposes of
this section, 2.1.2.1, a “certified” CEMS means a CEM system that has met the
applicable certification requirements of either: this part, or part 60 of this chapter, or
a State CEM program, or the source operating permit. For a unit with add-on NOX
controls (whether or not the unit is equipped with low-NOX burner technology), or for
a unit equipped with dry low-NOX (DLN) technology, historical CEM data may only be
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
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40 CFR Appendix-A-to-Part-75 2.1.2.1(e) (enhanced display)page 11 of 59
TABLE 2-1—MAXIMUM POTENTIAL CONCENTRATION FOR NOX—COAL-FIRED UNITS
Unit type Maximum potential concentration for NOX
(ppm)
Tangentially-fired dry bottom and fluidized bed 460
Wall-fired dry bottom, turbo-fired dry bottom, stokers 675
Roof-fired (vertically-fired) dry bottom, cell burners,
arch-fired
975
Cyclone, wall-fired wet bottom, wet bottom turbo-fired 1200
Others (1)
1 As approved by the Administrator.
2.1.2.2 Maximum Expected Concentration
used to determine the MPC if the 720 quality-assured monitor operating hours of
CEM data are collected upstream of the add-on controls or if the 720 hours of data
include periods when the add-on controls are not in operation or when the DLN
controls are not in the premixed (low-NOX mode). For units that do not produce
electrical or thermal output, the data must represent the full range of normal process
operation. The highest hourly NOX concentration in ppm shall be the MPC.
(a)Make an initial determination of the maximum expected concentration (MEC) of NOX
during normal operation for affected units with add-on NOX controls of any kind (e.g.,
steam injection, water injection, SCR, or SNCR) and for turbines that use dry low-NOX
technology. Determine a separate MEC value for each type of fuel (or blend)
combusted in the unit, except for fuels that are only used for unit startup and/or
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
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2.1.2.3 Span Value(s) and Range(s)
flame stabilization. Calculate the MEC of NOX using Equation A-2, if applicable,
inserting the maximum potential concentration, as determined using the procedures
in section 2.1.2.1 of this appendix. Where Equation A-2 is not applicable, set the MEC
either by:
(1)measuring the NOX concentration using the testing procedures in this section;
(2)using historical CEM data over the previous 720 (or more) quality-assured
monitor operating hours; or
(3)if the unit has add-on NOX controls or uses dry low NOX technology, and has a
federally-enforceable permit limit for NOX concentration, the permit limit may be
used as the MEC. Include in the monitoring plan for the unit each MEC value
and the method by which the MEC was determined. Note that each initial MEC
value is subject to periodic review under section 2.1.2.5 of this appendix. If an
MEC value is found to be either inappropriately high or low, the MEC shall be
adjusted in accordance with section 2.1.2.5, and corresponding span and range
adjustments shall be made, if necessary.
(b)If NOX emission testing is used to determine the MEC value(s), the MEC for each type
of fuel (or blend) shall be based upon testing at minimum load, normal load, and
maximum load. At least three tests of 20 minutes (minimum) duration, using at least
three traverse points, shall be performed at each load, using Method 7E from
appendix A to part 60 of this chapter (Note: Method 20 from appendix A to part 60
may be used for gas turbines instead of Method 7E). The test must be performed at
a time when all NOX control devices and methods used to reduce NOX emissions (if
applicable) are operating properly. The testing shall be conducted downstream of all
NOX controls. The highest point NOX concentration (e.g., the highest one-minute
average) recorded during any of the test runs shall be the MEC.
(c)If historical CEM data are used to determine the MEC value(s), the MEC for each type
of fuel shall be based upon 720 (or more) hours of quality-assured data from the NOX
component of a certified monitoring system representing the entire load range under
stable operating conditions. For the purposes of this section, 2.1.2.2, a “certified”
CEMS means a CEM system that has met the applicable certification requirements
of either: this part, or part 60 of this chapter, or a State CEM program, or the source
operating permit. The data base for the MEC shall not include any CEM data
recorded during unit startup, shutdown, or malfunction or (for units with add-on NOX
controls or turbines using dry low NOX technology) during any NOX control device
malfunctions or outages. All NOX control devices and methods used to reduce NOX
emissions (if applicable) must be operating properly during each hour. The CEM data
shall be collected downstream of all NOX controls. For each type of fuel, the highest
of the 720 (or more) quality-assured hourly average NOX concentrations recorded by
the CEMS shall be the MEC.
(a)Determine the high span value of the NOX monitor as follows. The high span value
shall be obtained by multiplying the MPC by a factor no less than 1.00 and no greater
than 1.25. Round the span value upward to the next highest multiple of 100 ppm. If
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2.1.2.4 Dual Span and Range Requirements
the NOX span concentration is ≤500 ppm, the span value may either be rounded
upward to the next highest multiple of 10 ppm, or to the next highest multiple of 100
ppm. The high span value shall be used to determine the concentrations of the
calibration gases required for daily calibration error checks and linearity tests. Note
that for certain applications, a second (low) NOX span and range may be required
(see section 2.1.2.4 of this appendix).
(b)If an existing State, local, or federal requirement for span of a NOX pollutant
concentration monitor requires or allows the use of a span value lower than that
required by this section or by section 2.1.2.4 of this appendix, the State, local, or
federal span value may be used, where a satisfactory explanation is included in the
monitoring plan, unless span and/or range adjustments become necessary in
accordance with section 2.1.2.5 of this appendix. Span values higher than required
by this section or by section 2.1.2.4 of this appendix must be approved by the
Administrator.
(c)Select the full-scale range of the instrument to be consistent with section 2.1 of this
appendix and to be greater than or equal to the high span value. Include the full-scale
range setting and calculations of the MPC and span in the monitoring plan for the
unit.
For most units, the high span value based on the MPC, as determined under section
2.1.2.3 of this appendix will suffice to measure and record NOX concentrations (unless
span and/or range adjustments must be made in accordance with section 2.1.2.5 of this
appendix). In some instances, however, a second (low) span value based on the MEC may
be required to ensure accurate measurement of all expected and potential NOX
concentrations. To determine whether two NOX spans are required, proceed as follows:
(a)Compare the MEC value(s) determined in section 2.1.2.2 of this appendix to the high
full-scale range value determined in section 2.1.2.3 of this appendix. If the MEC
values for all fuels (or blends) are ≥20.0 percent of the high range value, the high
span and range values determined under section 2.1.2.3 of this appendix are
sufficient, irrespective of which fuel or blend is combusted in the unit. If any of the
MEC values is <20.0 percent of the high range value, two spans (low and high) are
required, one based on the MPC and the other based on the MEC.
(b)When two NOX spans are required, the owner or operator may either use a single NOX
analyzer with a dual range (low-and high-scales) or two separate NOX analyzers
connected to a common sample probe and sample interface. Two separate NOX
analyzers connected to separate probes and sample interfaces may be used if
RATAs are passed on both ranges. For units with add-on NOX emission controls (e.g.,
steam injection, water injection, SCR, or SNCR) or units equipped with dry low-NOX
technology, the owner or operator may use a low range analyzer and a “default high
range value,” as described in paragraph 2.1.2.4(e) of this section, in lieu of
maintaining and quality assuring a high-scale range. Other monitor configurations are
subject to the approval of the Administrator.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
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40 CFR Appendix-A-to-Part-75 2.1.2.4(b) (enhanced display)page 14 of 59
(c)The owner or operator shall designate the monitoring systems and components in
the monitoring plan under § 75.53 as follows: when a single probe and sample
interface are used, either designate the low and high ranges as separate NOX
components of a single, primary NOX monitoring system; designate the low and high
ranges as the NOX components of two separate, primary NOX monitoring systems;
designate the normal range as a primary monitoring system and the other range as a
non-redundant backup monitoring system; or, when a single, dual-range NOX analyzer
is used, designate the low and high ranges as a single NOX component of a primary
NOX monitoring system (if this option is selected, use a special dual-range
component type code, as specified by the Administrator, to satisfy the requirements
of § 75.53(e)(1)(iv)(D)). When two NOX analyzers are connected to separate probes
and sample interfaces, designate the analyzers as the NOX components of two
separate, primary NOX monitoring systems. For units with add-on NOX controls or
units equipped with dry low-NOX technology, if the default high range value is used,
designate the low range analyzer as the NOX component of the primary NOX
monitoring system. Do not designate the default high range as a monitoring system
or component. Other component and system designations are subject to approval by
the Administrator. Note that the component and system designations for redundant
backup monitoring systems shall be the same as for primary monitoring systems.
(d)Each monitoring system designated as primary or redundant backup shall meet the
initial certification and quality assurance requirements in § 75.20(c)(for primary
monitoring systems), in § 75.20(d)(1)(for redundant backup monitoring systems)
and appendices A and B to this part, with one exception: relative accuracy test audits
(RATAs) are required only on the normal range (for dual span units with add-on NOX
emission controls, the low range is considered normal). Each monitoring system
designated as non-redundant backup shall meet the applicable quality assurance
requirements in § 75.20(d)(2).
(e)For dual span units with add-on NOX emission controls (e.g., steam injection, water
injection, SCR, or SNCR), or, for units that use dry low NOX technology, the owner or
operator may, as an alternative to maintaining and quality assuring a high monitor
range, use a default high range value. If this option is chosen, the owner or operator
shall report a default value of 200.0 percent of the MPC for each unit operating hour
in which the full-scale of the low range NOX analyzer is exceeded.
(f)The high span and range shall be determined in accordance with section 2.1.2.3 of
this appendix. The low span value shall be 100.0 to 125.0 percent of the MEC,
rounded up to the next highest multiple of 10 ppm (or 100 ppm, if appropriate). If
more than one MEC value (as determined in section 2.1.2.2 of this appendix) is <20.0
percent of the high full-scale range value, the low span value shall be based upon
whichever MEC value is closest to 20.0 percent of the high range value. The low
range must be greater than or equal to the low span value, and the required
calibration gases for the low range must be selected based on the low span value.
However, if the default high range option in paragraph (e)of this section is selected,
the full-scale of the low measurement range shall not exceed five times the MEC
value (where the MEC is rounded upward to the next highest multiple of 10 ppm). For
units with two NOX spans, use the low range whenever NOX concentrations are
expected to be consistently <20.0 percent of the high range value, i.e., when the MEC
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2.1.2.5 Adjustment of Span and Range
of the fuel being combusted is <20.0 percent of the high range value. When the full-
scale of the low range is exceeded, the high range shall be used to measure and
record the NOX concentrations; or, if applicable, the default high range value in
paragraph (e)of this section shall be reported for each hour of the full-scale
exceedance.
For each affected unit or common stack, the owner or operator shall make a periodic
evaluation of the MPC, MEC, span, and range values for each NOX monitor (at a minimum,
an annual evaluation is required) and shall make any necessary span and range
adjustments, with corresponding monitoring plan updates, as described in paragraphs (a),
(b), and (c)of this section. Span and range adjustments may be required, for example, as a
result of changes in the fuel supply, changes in the manner of operation of the unit, or
installation or removal of emission controls. In implementing the provisions in paragraphs
(a)and (b)of this section, note that NOX data recorded during short-term, non-
representative operating conditions (e.g., a trial burn of a different type of fuel) shall be
excluded from consideration. The owner or operator shall keep the results of the most
recent span and range evaluation on-site, in a format suitable for inspection. Make each
required span or range adjustment no later than 45 days after the end of the quarter in
which the need to adjust the span or range is identified, except that up to 90 days after the
end of that quarter may be taken to implement a span adjustment if the calibration gases
currently being used for daily calibration error tests and linearity checks are unsuitable for
use with the new span value.
(a)If the fuel supply, emission controls, or other process parameters change such that
the maximum expected concentration or the maximum potential concentration
changes significantly, adjust the NOX pollutant concentration span(s) and (if
necessary) monitor range(s) to assure the continued accuracy of the monitoring
system. A “significant” change in the MPC or MEC means that the guidelines in
section 2.1 of this appendix can no longer be met, as determined by either a periodic
evaluation by the owner or operator or from the results of an audit by the
Administrator. The owner or operator should evaluate whether any planned changes
in operation of the unit or stack may affect the concentration of emissions being
emitted from the unit and should plan any necessary span and range changes
needed to account for these changes, so that they are made in as timely a manner as
practicable to coordinate with the operational changes. An example of a change that
may require a span and range adjustment is the installation of low-NOX burner
technology on a previously uncontrolled unit. Determine the adjusted span(s) using
the procedures in section 2.1.2.3 or 2.1.2.4 of this appendix (as applicable). Select
the full-scale range(s) of the instrument to be greater than or equal to the adjusted
span value(s) and to be consistent with the guidelines of section 2.1 of this
appendix.
(b)Whenever a full-scale range is exceeded during a quarter and the exceedance is not
caused by a monitor out-of-control period, proceed as follows:
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
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40 CFR Appendix-A-to-Part-75 2.1.2.5(b) (enhanced display)page 16 of 59
2.1.3 CO2 and O2 Monitors
(1)For exceedances of the high range, report 200.0 percent of the current full-scale
range as the hourly NOX concentration for each hour of the full-scale
exceedance and make appropriate adjustments to the MPC, span, and range to
prevent future full-scale exceedances.
(2)For units with two NOX spans and ranges, if the low range is exceeded, no
further action is required, provided that the high range is available and its most
recent calibration error test and linearity check have not expired. However, if
either of these quality assurance tests has expired and the high range is not
able to provide quality assured data at the time of the low range exceedance or
at any time during the continuation of the exceedance, report the MPC as the
NOX concentration until the readings return to the low range or until the high
range is able to provide quality assured data (unless the reason that the high-
scale range is not able to provide quality assured data is because the high-scale
range has been exceeded; if the high-scale range is exceeded, follow the
procedures in paragraph (b)(1)of this section).
(c)Whenever changes are made to the MPC, MEC, full-scale range, or span value of the
NOX monitor as described in paragraphs (a)and (b)of this section, record and report
(as applicable) the new full-scale range setting, the new MPC or MEC, maximum
potential NOX emission rate, and the adjusted span value in an updated monitoring
plan for the unit. The monitoring plan update shall be made in the quarter in which
the changes become effective. In addition, record and report the adjusted span as
part of the records for the daily calibration error test and linearity check required by
appendix B to this part. Whenever the span value is adjusted, use calibration gas
concentrations that meet the requirements of section 5.1 of this appendix, based on
the adjusted span value. When a span adjustment is significant enough that the
calibration gases currently being used for daily calibration error tests and linearity
checks are unsuitable for use with the new span value, a diagnostic linearity test
using the new calibration gases must be performed and passed. Use the data
validation procedures in § 75.20(b)(3), beginning with the hour in which the span is
changed.
For an O2 monitor (including O2 monitors used to measure CO2 emissions or percentage
moisture), select a span value between 15.0 and 25.0 percent O2. For a CO2 monitor installed
on a boiler, select a span value between 14.0 and 20.0 percent CO2. For a CO2 monitor installed
on a combustion turbine, an alternative span value between 6.0 and 14.0 percent CO2 may be
used. An alternative CO2 span value below 6.0 percent may be used if an appropriate technical
justification is included in the hardcopy monitoring plan. An alternative O2 span value below
15.0 percent O2 may be used if an appropriate technical justification is included in the
monitoring plan (e.g., O2 concentrations above a certain level create an unsafe operating
condition). Select the full-scale range of the instrument to be consistent with section 2.1 of this
appendix and to be greater than or equal to the span value. Select the calibration gas
concentrations for the daily calibration error tests and linearity checks in accordance with
section 5.1 of this appendix, as percentages of the span value. For O2 monitors with span
values ≥21.0 percent O2, purified instrument air containing 20.9 percent O2 may be used as the
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2.1.3.1 Maximum Potential Concentration of CO2
2.1.3.2 Minimum Potential Concentration of O2
2.1.3.3 Adjustment of Span and Range
2.1.4 Flow Monitors
high-level calibration material. If a dual-range or autoranging diluent analyzer is installed, the
analyzer may be represented in the monitoring plan as a single component, using a special
component type code specified by the Administrator to satisfy the requirements of §
75.53(e)(1)(iv)(D).
The MPC and MEC values for diluent monitors are subject to the same periodic review as
SO2 and NOX monitors (see sections 2.1.1.5 and 2.1.2.5 of this appendix). If an MPC or
MEC value is found to be either inappropriately high or low, the MPC shall be adjusted and
corresponding span and range adjustments shall be made, if necessary.
For CO2 pollutant concentration monitors, the maximum potential concentration shall be
14.0 percent CO2 for boilers and 6.0 percent CO2 for combustion turbines. Alternatively,
the owner or operator may determine the MPC based on a minimum of 720 hours of
quality-assured historical CEM data representing the full operating load range of the
unit(s). Note that the MPC for CO2 monitors shall only be used for the purpose of
providing substitute data under this part. The CO2 monitor span and range shall be
determined according to section 2.1.3 of this appendix.
The owner or operator of a unit that uses a flow monitor and an O2 diluent monitor to
determine heat input in accordance with Equation F-17 or F-18 in appendix F to this part
shall, for the purposes of providing substitute data under § 75.36, determine the minimum
potential O2 concentration. The minimum potential O2 concentration shall be based upon
720 hours or more of quality-assured CEM data, representing the full operating load range
of the unit(s). The minimum potential O2 concentration shall be the lowest quality-assured
hourly average O2 concentration recorded in the 720 (or more) hours of data used for the
determination.
The MPC and MEC values for diluent monitors are subject to the same periodic review as
SO2 and NOX monitors (see sections 2.1.1.5 and 2.1.2.5 of this appendix). If an MPC or
MEC value is found to be either inappropriately high or low, the MPC shall be adjusted and
corresponding span and range adjustments shall be made, if necessary. Adjust the span
value and range of a CO2 or O2 monitor in accordance with section 2.1.1.5 of this appendix
(insofar as those provisions are applicable), with the term “CO2 or O2” applying instead of
the term “SO2”. Set the new span and range in accordance with section 2.1.3 of this
appendix and report the new span value in the monitoring plan.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.2.5(c)
40 CFR Appendix-A-to-Part-75 2.1.2.5(c) (enhanced display)page 18 of 59
2.1.4.1 Maximum Potential Velocity and Flow Rate
Select the full-scale range of the flow monitor so that it is consistent with section 2.1 of this
appendix and can accurately measure all potential volumetric flow rates at the flow monitor
installation site.
For this purpose, determine the span value of the flow monitor using the following
procedure. Calculate the maximum potential velocity (MPV) using Equation A-3a or A-3b
or determine the MPV (wet basis) from velocity traverse testing using Reference Method 2
(or its allowable alternatives) in appendix A to part 60 of this chapter. If using test values,
use the highest average velocity (determined from the Method 2 traverses) measured at or
near the maximum unit operating load (or, for units that do not produce electrical or
thermal output, at the normal process operating conditions corresponding to the
maximum stack gas flow rate). Express the MPV in units of wet standard feet per minute
(fpm). For the purpose of providing substitute data during periods of missing flow rate
data in accordance with §§ 75.31 and 75.33 and as required elsewhere in this part,
calculate the maximum potential stack gas flow rate (MPF) in units of standard cubic feet
per hour (scfh), as the product of the MPV (in units of wet, standard fpm) times 60, times
the cross-sectional area of the stack or duct (in ft2) at the flow monitor location.
or
Where:
MPV = maximum potential velocity (fpm, standard wet basis).
Fd = dry-basis F factor (dscf/mmBtu) from Table 1, Appendix F to this part.
Fc = carbon-based F factor (scf CO2/mmBtu) from Table 1, Appendix F to this part.
Hf = maximum heat input (mmBtu/minute) for all units, combined, exhausting to the stack
or duct where the flow monitor is located.
A = inside cross sectional area (ft2) of the flue at the flow monitor location.
%O2d = maximum oxygen concentration, percent dry basis, under normal operating
conditions.
%CO2d = minimum carbon dioxide concentration, percent dry basis, under normal
operating conditions.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.2.5(c)
40 CFR Appendix-A-to-Part-75 2.1.2.5(c) (enhanced display)page 19 of 59
2.1.4.2 Span Values and Range
2.1.4.3 Adjustment of Span and Range
%H2O = maximum percent flue gas moisture content under normal operating conditions.
Determine the span and range of the flow monitor as follows. Convert the MPV, as
determined in section 2.1.4.1 of this appendix, to the same measurement units of flow
rate that are used for daily calibration error tests (e.g., scfh, kscfh, kacfm, or differential
pressure (inches of water)). Next, determine the “calibration span value” by multiplying the
MPV (converted to equivalent daily calibration error units) by a factor no less than 1.00
and no greater than 1.25, and rounding up the result to at least two significant figures. For
calibration span values in inches of water, retain at least two decimal places. Select
appropriate reference signals for the daily calibration error tests as percentages of the
calibration span value, as specified in section 2.2.2.1 of this appendix. Finally, calculate
the “flow rate span value” (in scfh) as the product of the MPF, as determined in section
2.1.4.1 of this appendix, times the same factor (between 1.00 and 1.25) that was used to
calculate the calibration span value. Round off the flow rate span value to the nearest
1000 scfh. Select the full-scale range of the flow monitor so that it is greater than or equal
to the span value and is consistent with section 2.1 of this appendix. Include in the
monitoring plan for the unit: calculations of the MPV, MPF, calibration span value, flow rate
span value, and full-scale range (expressed both in scfh and, if different, in the
measurement units of calibration).
For each affected unit or common stack, the owner or operator shall make a periodic
evaluation of the MPV, MPF, span, and range values for each flow rate monitor (at a
minimum, an annual evaluation is required) and shall make any necessary span and range
adjustments with corresponding monitoring plan updates, as described in paragraphs (a)
through (c)of this section 2.1.4.3. Span and range adjustments may be required, for
example, as a result of changes in the fuel supply, changes in the stack or ductwork
configuration, changes in the manner of operation of the unit, or installation or removal of
emission controls. In implementing the provisions in paragraphs (a)and (b)of this section
2.1.4.3, note that flow rate data recorded during short-term, non-representative operating
conditions (e.g., a trial burn of a different type of fuel) shall be excluded from
consideration. The owner or operator shall keep the results of the most recent span and
range evaluation on-site, in a format suitable for inspection. Make each required span or
range adjustment no later than 45 days after the end of the quarter in which the need to
adjust the span or range is identified.
(a)If the fuel supply, stack or ductwork configuration, operating parameters, or other
conditions change such that the maximum potential flow rate changes significantly,
adjust the span and range to assure the continued accuracy of the flow monitor. A
“significant” change in the MPV or MPF means that the guidelines of section 2.1 of
this appendix can no longer be met, as determined by either a periodic evaluation by
the owner or operator or from the results of an audit by the Administrator. The owner
or operator should evaluate whether any planned changes in operation of the unit
may affect the flow of the unit or stack and should plan any necessary span and
range changes needed to account for these changes, so that they are made in as
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.4.3(a)
40 CFR Appendix-A-to-Part-75 2.1.4.3(a) (enhanced display)page 20 of 59
2.1.5 Minimum Potential Moisture Percentage
2.1.6 Maximum Potential Moisture Percentage
timely a manner as practicable to coordinate with the operational changes. Calculate
the adjusted calibration span and flow rate span values using the procedures in
section 2.1.4.2 of this appendix.
(b)Whenever the full-scale range is exceeded during a quarter, provided that the
exceedance is not caused by a monitor out-of-control period, report 200.0 percent of
the current full-scale range as the hourly flow rate for each hour of the full-scale
exceedance. If the range is exceeded, make appropriate adjustments to the MPF,
flow rate span, and range to prevent future full-scale exceedances. Calculate the new
calibration span value by converting the new flow rate span value from units of scfh
to units of daily calibration. A calibration error test must be performed and passed to
validate data on the new range.
(c)Whenever changes are made to the MPV, MPF, full-scale range, or span value of the
flow monitor, as described in paragraphs (a)and (b)of this section, record and report
(as applicable) the new full-scale range setting, calculations of the flow rate span
value, calibration span value, MPV, and MPF in an updated monitoring plan for the
unit. The monitoring plan update shall be made in the quarter in which the changes
become effective. Record and report the adjusted calibration span and reference
values as parts of the records for the calibration error test required by appendix B to
this part. Whenever the calibration span value is adjusted, use reference values for
the calibration error test that meet the requirements of section 2.2.2.1 of this
appendix, based on the most recent adjusted calibration span value. Perform a
calibration error test according to section 2.1.1 of appendix B to this part whenever
making a change to the flow monitor span or range, unless the range change also
triggers a recertification under § 75.20(b).
Except as provided in section 2.1.6 of this appendix, the owner or operator of a unit that uses a
continuous moisture monitoring system to correct emission rates and heat inputs from a dry
basis to a wet basis (or vice-versa) shall, for the purpose of providing substitute data under §
75.37, use a default value of 3.0 percent H2O as the minimum potential moisture percentage.
Alternatively, the minimum potential moisture percentage may be based upon 720 hours or
more of quality-assured CEM data, representing the full operating load range of the unit(s). If
this option is chosen, the minimum potential moisture percentage shall be the lowest quality-
assured hourly average H2O concentration recorded in the 720 (or more) hours of data used for
the determination.
When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used
to determine NOX emission rate, the owner or operator of a unit that uses a continuous
moisture monitoring system shall, for the purpose of providing substitute data under § 75.37,
determine the maximum potential moisture percentage. The maximum potential moisture
percentage shall be based upon 720 hours or more of quality-assured CEM data, representing
the full operating load range of the unit(s). The maximum potential moisture percentage shall
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.1.4.3(b)
40 CFR Appendix-A-to-Part-75 2.1.4.3(c) (enhanced display)page 21 of 59
2.2 Design for Quality Control Testing
2.2.1 Pollutant Concentration and CO2 or O2 Monitors
2.2.2 Flow Monitors
2.2.2.1 Calibration Error Test
2.2.2.2 Interference Check
be the highest quality-assured hourly average H2O concentration recorded in the 720 (or more)
hours of data used for the determination. Alternatively, a default maximum potential moisture
value of 15.0 percent H2O may be used.
(a)Design and equip each pollutant concentration and CO2 or O2 monitor with a calibration
gas injection port that allows a check of the entire measurement system when calibration
gases are introduced. For extractive and dilution type monitors, all monitoring
components exposed to the sample gas, (e.g., sample lines, filters, scrubbers,
conditioners, and as much of the probe as practicable) are included in the measurement
system. For in situ type monitors, the calibration must check against the injected gas for
the performance of all active electronic and optical components (e.g. transmitter, receiver,
analyzer).
(b)Design and equip each pollutant concentration or CO2 or O2 monitor to allow daily
determinations of calibration error (positive or negative) at the zero- and mid-or high-level
concentrations specified in section 5.2 of this appendix.
Design all flow monitors to meet the applicable performance specifications.
Design and equip each flow monitor to allow for a daily calibration error test consisting of
at least two reference values: Zero to 20 percent of span or an equivalent reference value
(e.g.,pressure pulse or electronic signal) and 50 to 70 percent of span. Flow monitor
response, both before and after any adjustment, must be capable of being recorded by the
data acquisition and handling system. Design each flow monitor to allow a daily
calibration error test of the entire flow monitoring system, from and including the probe tip
(or equivalent) through and including the data acquisition and handling system, or the flow
monitoring system from and including the transducer through and including the data
acquisition and handling system.
(a)Design and equip each flow monitor with a means to ensure that the moisture
expected to occur at the monitoring location does not interfere with the proper
functioning of the flow monitoring system. Design and equip each flow monitor with
a means to detect, on at least a daily basis, pluggage of each sample line and
sensing port, and malfunction of each resistance temperature detector (RTD),
transceiver or equivalent.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.2.1(a)
40 CFR Appendix-A-to-Part-75 2.2.2.2(a) (enhanced display)page 22 of 59
3. Performance Specifications
3.1 Calibration Error
3.2 Linearity Check
(b)Design and equip each differential pressure flow monitor to provide an automatic,
periodic back purging (simultaneously on both sides of the probe) or equivalent
method of sufficient force and frequency to keep the probe and lines sufficiently free
of obstructions on at least a daily basis to prevent velocity sensing interference, and
a means for detecting leaks in the system on at least a quarterly basis (manual
check is acceptable).
(c)Design and equip each thermal flow monitor with a means to ensure on at least a
daily basis that the probe remains sufficiently clean to prevent velocity sensing
interference.
(d)Design and equip each ultrasonic flow monitor with a means to ensure on at least a
daily basis that the transceivers remain sufficiently clean (e.g.,backpurging system)
to prevent velocity sensing interference.
(a)The calibration error performance specifications in this section apply only to 7-day calibration
error tests under sections 6.3.1 and 6.3.2 of this appendix and to the offline calibration
demonstration described in section 2.1.1.2 of appendix B to this part. The calibration error
limits for daily operation of the continuous monitoring systems required under this part are
found in section 2.1.4(a) of appendix B to this part.
(b)The calibration error of SO2 and NOX pollutant concentration monitors shall not deviate from
the reference value of either the zero or upscale calibration gas by more than 2.5 percent of the
span of the instrument, as calculated using Equation A-5 of this appendix. Alternatively, where
the span value is less than 200 ppm, calibration error test results are also acceptable if the
absolute value of the difference between the monitor response value and the reference value,
|R−A| in Equation A-5 of this appendix, is ≤5 ppm. The calibration error of CO2 or O2 monitors
(including O2 monitors used to measure CO2 emissions or percent moisture) shall not deviate
from the reference value of the zero or upscale calibration gas by >0.5 percent O2 or CO2, as
calculated using the term |R−A| in the numerator of Equation A-5 of this appendix. The
calibration error of flow monitors shall not exceed 3.0 percent of the calibration span value of
the instrument, as calculated using Equation A-6 of this appendix. For differential pressure-type
flow monitors, the calibration error test results are also acceptable if |R−A|, the absolute value
of the difference between the monitor response and the reference value in Equation A-6, does
not exceed 0.01 inches of water.
For SO2 and NOX pollutant concentration monitors, the error in linearity for each calibration gas
concentration (low-, mid-, and high-levels) shall not exceed or deviate from the reference value by
more than 5.0 percent (as calculated using equation A-4 of this appendix). Linearity check results
are also acceptable if the absolute value of the difference between the average of the monitor
response values and the average of the reference values, | R-A | in equation A-4 of this appendix, is
less than or equal to 5 ppm. For CO2 or O2 monitors (including O2 monitors used to measure CO2
emissions or percent moisture):
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 2.2.2.2(b)
40 CFR Appendix-A-to-Part-75 3.1(b) (enhanced display)page 23 of 59
3.3 Relative Accuracy
3.3.1 Relative Accuracy for SO2 Monitors
3.3.2 Relative Accuracy for NOX-Diluent Continuous Emission Monitoring Systems
3.3.3 Relative Accuracy for CO2 and O2 Monitors
3.3.4 Relative Accuracy for Flow Monitors
(1)The error in linearity for each calibration gas concentration (low-, mid-, and high-levels) shall not
exceed or deviate from the reference value by more than 5.0 percent as calculated using
equation A-4 of this appendix; or
(2)The absolute value of the difference between the average of the monitor response values and
the average of the reference values, | R-A| in equation A-4 of this appendix, shall be less than or
equal to 0.5 percent CO2 or O2, whichever is less restrictive.
(a)The relative accuracy for SO2 pollutant concentration monitors shall not exceed 10.0
percent except as provided in this section.
(b)For affected units where the average of the reference method measurements of SO2
concentration during the relative accuracy test audit is less than or equal to 250.0 ppm,
the difference between the mean value of the monitor measurements and the reference
method mean value shall not exceed ±15.0 ppm, wherever the relative accuracy
specification of 10.0 percent is not achieved.
(a)The relative accuracy for NOX-diluent continuous emission monitoring systems shall not
exceed 10.0 percent.
(b)For affected units where the average of the reference method measurements of NOX
emission rate during the relative accuracy test audit is less than or equal to 0.200 lb/
mmBtu, the difference between the mean value of the continuous emission monitoring
system measurements and the reference method mean value shall not exceed ±0.020 lb/
mmBtu, wherever the relative accuracy specification of 10.0 percent is not achieved.
The relative accuracy for CO2 and O2 monitors shall not exceed 10.0 percent. The relative
accuracy test results are also acceptable if the difference between the mean value of the CO2
or O2 monitor measurements and the corresponding reference method measurement mean
value, calculated using equation A-7 of this appendix, does not exceed ±1.0 percent CO2 or O2.
(a)The relative accuracy of flow monitors shall not exceed 10.0 percent at any load (or
operating) level at which a RATA is performed (i.e., the low, mid, or high level, as defined in
section 6.5.2.1 of this appendix).
(b)For affected units where the average of the flow reference method measurements of gas
velocity at a particular load (or operating) level of the relative accuracy test audit is less
than or equal to 10.0 fps, the difference between the mean value of the flow monitor
velocity measurements and the reference method mean value in fps at that level shall not
exceed ±2.0 fps, wherever the 10.0 percent relative accuracy specification is not achieved.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 3.2(1)
40 CFR Appendix-A-to-Part-75 3.3.4(b) (enhanced display)page 24 of 59
3.3.5 Combined SO2/Flow Monitoring System [Reserved]
3.3.6 Relative Accuracy for Moisture Monitoring Systems
3.3.7 Relative Accuracy for NOX Concentration Monitoring Systems
3.4 Bias
3.4.1 SO2 Pollutant Concentration Monitors, NOX Concentration Monitoring Systems and
NOX-Diluent Continuous Emission Monitoring Systems
3.4.2 Flow Monitors
3.5 Cycle Time
The relative accuracy of a moisture monitoring system shall not exceed 10.0 percent. The
relative accuracy test results are also acceptable if the difference between the mean value of
the reference method measurements (in percent H2O) and the corresponding mean value of the
moisture monitoring system measurements (in percent H2O), calculated using Equation A-7 of
this appendix does not exceed ±1.5 percent H2O.
(a)The following requirement applies only to NOX concentration monitoring systems (i.e., NOX
pollutant concentration monitors) that are used to determine NOX mass emissions, where
the owner or operator elects to monitor and report NOX mass emissions using a NOX
concentration monitoring system and a flow monitoring system.
(b)The relative accuracy for NOX concentration monitoring systems shall not exceed 10.0
percent. Alternatively, for affected units where the average of the reference method
measurements of NOX concentration during the relative accuracy test audit is less than or
equal to 250.0 ppm, the difference between the mean value of the continuous emission
monitoring system measurements and the reference method mean value shall not exceed
±15.0 ppm, wherever the 10.0 percent relative accuracy specification is not achieved.
SO2 pollutant concentration monitors, NOX-diluent continuous emission monitoring systems
and NOX concentration monitoring systems used to determine NOX mass emissions, as defined
in § 75.71(a)(2), shall not be biased low as determined by the test procedure in section 7.6 of
this appendix. The bias specification applies to all SO2 pollutant concentration monitors and to
all NOX concentration monitoring systems, including those measuring an average SO2 or NOX
concentration of 250.0 ppm or less, and to all NOX-diluent continuous emission monitoring
systems, including those measuring an average NOX emission rate of 0.200 lb/mmBtu or less.
Flow monitors shall not be biased low as determined by the test procedure in section 7.6 of this
appendix. The bias specification applies to all flow monitors including those measuring an
average gas velocity of 10.0 fps or less.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 3.3.7(a)
40 CFR Appendix-A-to-Part-75 3.3.7(b) (enhanced display)page 25 of 59
4. Data Acquisition and Handling Systems
5. Calibration Gas
5.1 Reference Gases
5.1.1 Standard Reference Materials (SRM)
The cycle time for pollutant concentration monitors, oxygen monitors used to determine percent
moisture, and any other monitoring component of a continuous emission monitoring system that is
required to perform a cycle time test shall not exceed 15 minutes.
(a)Automated data acquisition and handling systems shall read and record the entire range of pollutant
concentrations and volumetric flow from zero through full-scale and provide a continuous,
permanent record of all measurements and required information in an electronic format. These
systems also shall have the capability of interpreting and converting the individual output signals
from an SO2 pollutant concentration monitor, a flow monitor, a CO2 monitor, an O2 monitor, a NOX
pollutant concentration monitor, a NOX-diluent CEMS, and a moisture monitoring system to produce
a continuous readout of pollutant emission rates or pollutant mass emissions (as applicable) in the
appropriate units (e.g.,lb/hr, lb/mmBtu, tons/hr).
(b)Data acquisition and handling systems shall also compute and record: Monitor calibration error; any
bias adjustments to SO2, NOX, flow rate, or NOX emission rate data; and all missing data procedure
statistics specified in subpart D of this part.
(c)For an excepted monitoring system under appendix D or E of this part, data acquisition and handling
systems shall:
(1)Read and record the full range of fuel flowrate through the upper range value;
(2)Calculate and record intermediate values necessary to obtain emissions, such as mass fuel
flowrate and heat input rate;
(3)Calculate and record emissions in the appropriate units (e.g., lb/hr of SO2, lb/mmBtu of NOX);
(4)Predict and record NOX emission rate using the heat input rate and the NOX/heat input
correlation developed under appendix E of this part;
(5)Calculate and record all missing data substitution values specified in appendix D or E of this
part; and
(6)Provide a continuous, permanent record of all measurements and required information in an
electronic format.
For the purposes of part 75, calibration gases include the following:
These calibration gases may be obtained from the National Institute of Standards and
Technology (NIST) at the following address: Quince Orchard and Cloppers Road, Gaithersburg,
MD 20899-0001.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 4.(a)
40 CFR Appendix-A-to-Part-75 4.(c)(6) (enhanced display)page 26 of 59
5.1.2 SRM-Equivalent Compressed Gas Primary Reference Material (PRM)
5.1.3 NIST Traceable Reference Materials
5.1.4 EPA Protocol Gases
5.1.5 Research Gas Mixtures
5.1.6 Zero Air Material
Contact the Gas Metrology Team, Analytical Chemistry Division, Chemical Science and
Technology Laboratory of NIST, at the address in section 5.1.1, for a list of vendors and cylinder
gases.
Contact the Gas Metrology Team, Analytical Chemistry Division, Chemical Science and
Technology Laboratory of NIST, at the address in section 5.1.1, for a list of vendors and cylinder
gases that meet the definition for a NIST Traceable Reference Material (NTRM) provided in §
72.2.
(a)An EPA Protocol gas is a calibration gas mixture prepared and analyzed according to
Section 2 of the “EPA Traceability Protocol for Assay and Certification of Gaseous
Calibration Standards,” September 1997, as amended on August 25, 1999, EPA-600/R-97/
121 (incorporated by reference,see § 75.6) or such revised procedure as approved by the
Administrator.
(b)EPA Protocol gas concentrations must be certified by an EPA Protocol gas production site
to have an analytical uncertainty (95-percent confidence interval) to be not more than plus
or minus 2.0 percent (inclusive) of the certified concentration (tag value) of the gas
mixture. The uncertainty must be calculated using the statistical procedures (or equivalent
statistical techniques) that are listed in Section 2.1.8 of the “EPA Traceability Protocol for
Assay and Certification of Gaseous Calibration Standards,” September 1997, as amended
on August 25, 1999, EPA-600/R-97/121 (incorporated by reference,see § 75.6).
Concentrations of research gas mixtures, as defined in § 72.2 of this chapter, must be certified
by the National Institute of Standards and Technology to have an analytical uncertainty
(95-percent confidence interval) calculated using the statistical procedures (or equivalent
statistical techniques) that are listed in Section 2.1.8 of the “EPA Traceability Protocol for Assay
and Certification of Gaseous Calibration Standards,” September 1997, as amended on August
25, 1999, EPA-600/R-97/121 (incorporated by reference,see § 75.6) to be not more than plus or
minus 2.0 percent (inclusive) of the concentration specified on the cylinder label (i.e.,the tag
value) in order to be used as calibration gas under this part. Inquiries about the RGM program
should be directed to: National Institute of Standards and Technology, Analytical Chemistry
Division, Chemical Science and Technology Laboratory, B-324 Chemistry, Gaithersburg, MD
20899.
Zero air material is defined in § 72.2 of this chapter.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 5.1.4(a)
40 CFR Appendix-A-to-Part-75 5.1.4(b) (enhanced display)page 27 of 59
5.1.7 NIST/EPA-Approved Certified Reference Materials
5.1.8 Gas Manufacturer's Intermediate Standards
5.2 Concentrations
5.2.1 Zero-level Concentration
5.2.2 Low-level Concentration
5.2.3 Mid-level Concentration
5.2.4 High-level Concentration
6. Certification Tests and Procedures
6.1 General Requirements
6.1.1 Pretest Preparation
Existing certified reference materials (CRMs) that are still within their certification period may
be used as calibration gas.
Gas manufacturer's intermediate standards is defined in § 72.2 of this chapter.
Four concentration levels are required as follows.
0.0 to 20.0 percent of span, including span for high-scale or both low- and high-scale for SO2,
NOX, CO2, and O2 monitors, as appropriate.
20.0 to 30.0 percent of span, including span for high-scale or both low- and high-scale for SO2,
NOX, CO2, and O2 monitors, as appropriate.
50.0 to 60.0 percent of span, including span for high-scale or both low- and high-scale for SO2,
NOX, CO2, and O2 monitors, as appropriate.
80.0 to 100.0 percent of span, including span for high-scale or both low-and high-scale for SO2,
NOX, CO2, and O2 monitors, as appropriate.
Install the components of the continuous emission monitoring system (i.e., pollutant
concentration monitors, CO2 or O2 monitor, and flow monitor) as specified in sections 1, 2, and
3 of this appendix, and prepare each system component and the combined system for
operation in accordance with the manufacturer's written instructions. Operate the unit(s) during
each period when measurements are made. Units may be tested on non-consecutive days. To
the extent practicable, test the DAHS software prior to testing the monitoring hardware.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 5.1.4(b)
40 CFR Appendix-A-to-Part-75 5.1.4(b) (enhanced display)page 28 of 59
6.1.2 Requirements for Air Emission Testing
(a)On and after March 27, 2012, all relative accuracy test audits (RATAs) of CEMS under this
part, and stack testing under § 75.19 and Appendix E to this part shall be conducted by an
Air Emission Testing Body (AETB) which has provided to the owner or operator of a unit
subject to this part the documentation required in paragraph (b)of this section,
demonstrating its conformance to ASTM D7036-04 (incorporated by reference,see §
75.6).
(b)The owner or operator shall obtain from the AETB a certification that as of the time of
testing the AETB is operating in conformance with ASTM D7036-04 (incorporated by
reference,see § 75.6). The AETB's certification may be limited in scope to the tests
identified under paragraph (a). The AETB's certification need not extend to other work it
may perform. This certification shall be provided in the form of either:
(1)A certificate of accreditation or interim accreditation for the relevant test methods
issued by a recognized, national accreditation body; or
(2)A letter of certification for the relevant test methods signed by a member of the
senior management staff of the AETB.
(c)The owner or operator shall obtain from the AETB the information required under §§
75.59(a)(15),(b)(6), and (d)(4), as applicable.
(d)While under no obligation to request the following information from an AETB, to review the
information provided by the AETB in response to such a request, or to take any other
action related to the response, the owner or operator may find it useful to request that
AETBs complying with paragraph (b)(2)of this section provide a copy of the following:
(1)The AETB's quality manual. For the purpose of application of 40 CFR part 2, subpart
B,AETB's concerned about the potential for public access to confidential business
information (CBI) may identify any information subject to such a claim in the copy
provided;
(2)The results of any internal audits performed by the AETB and any external audits of
the AETB during the 12 month period through the previous calendar quarter;
(3)Performance data (as defined in ASTM D7036-04 (incorporated by reference,see §
75.6)) collected by the AETB, including corrective actions implemented, during the 12
month period through the previous calendar quarter; and
(4)Training records for all on-site technical personnel, including any Qualified
Individuals, for the 12 month period through the previous calendar quarter.
(e)All relative accuracy testing performed pursuant to § 75.74(c)(2)(ii), section 6.5 of
appendix A to this part or section 2.3.1 of appendix B to this part, and stack testing under
§ 75.19 and Appendix E to this part shall be overseen and supervised on site by at least
one Qualified Individual, as defined in § 72.2 of this chapter with respect to the methods
employed in the test project. If the source owner or operator, or a State, local, or EPA
observer, discovers while the test team is still on site, that at least one QI did not oversee
and supervise the entire test (as qualified by this paragraph (e)), only those portions of the
test that were overseen and supervised by at least one QI as described above may be
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.1.2(a)
40 CFR Appendix-A-to-Part-75 6.1.2(e) (enhanced display)page 29 of 59
6.2 Linearity Check (General Procedures)
used under this part. However, allowance is made for normal activities of a QI who is
overseeing and supervising a test,e.g.,bathroom breaks, meal breaks, and emergencies
that may arise during a test.
(f)Except as provided in paragraph (e), no RATA performed pursuant to § 75.74(c)(2)(ii),
section 6.5 of appendix A to this part or section 2.3.1 of appendix B to this part, and no
stack test under § 75.19 or Appendix E to this part (or portion of such a RATA or stack
test) conducted by an AETB (as defined in § 72.2) shall be invalidated under this part as a
result of the failure of the AETB to conform to ASTM D7036-04 (incorporated by reference,
see § 75.6). Validation of such tests is determined based on the other part 75 testing
requirements. EPA recommends that proper observation of tests and review of test results
continue, regardless of whether an AETB fully conforms to ASTM D7036-04.
(g)An owner or operator who has requested information from an AETB under paragraph (d) of
this part who believes that the information provided by the AETB was either incomplete or
inaccurate may request the Administrator's assistance in remedying the alleged
deficiencies. Upon such a request, if the Administrator concurs that the information
submitted to a source subject to part 75 by an AETB under this section is either
incomplete or inaccurate, the Administrator will provide the AETB a description of the
deficiencies to be remedied. The Administrator's determination of completeness and
accuracy of information will be solely based on the provisions of ASTM D7036-04
(incorporated by reference,see § 75.6) and this part. The Administrator may post the
name of the offending AETB on Agency Web sites (including the CAMD Web site
http://www.epa.gov/airmarkets/emissions/aetb.html) if within 30 days of the Administrator
having provided the AETB a description of the deficiencies to be remedied, the AETB does
not satisfactorily respond to the source and notify the Administrator of the response by
submitting the notification to [e-mail], unless otherwise provided by the
Administrator. The AETB need not submit the information it provides to the owner or
operator to the Administrator, unless specifically requested by the Administrator. If after
the AETB's name is posted, the Administrator, in consultation with the source, determines
that the AETB's response is sufficient, the AETB's name will be removed from the EPA Web
sites.
Check the linearity of each SO2, NOX, CO2, and O2 monitor while the unit, or group of units for a
common stack, is combusting fuel at conditions of typical stack temperature and pressure; it is not
necessary for the unit to be generating electricity during this test. Notwithstanding these
requirements, if the SO2 or NOX span value for a particular monitor range is ≤30 ppm, that range is
exempted from the linearity check requirements of this part, for initial certification, recertification,
and for on-going quality-assurance. For units with two measurement ranges (high and low) for a
particular parameter, perform a linearity check on both the low scale (except for SO2 or NOX span
values ≤30 ppm) and the high scale. Note that for a NOX-diluent monitoring system with two NOX
measurement ranges, if the low NOX scale has a span value ≤30 ppm and is exempt from linearity
checks, this does not exempt either the diluent monitor or the high NOX scale (if the span is >30
ppm) from linearity check requirements. For on-going quality assurance of the CEMS, perform
linearity checks, using the procedures in this section, on the range(s) and at the frequency specified
in section 2.2.1 of appendix B to this part. Challenge each monitor with calibration gas, as defined in
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.1.2(f)
40 CFR Appendix-A-to-Part-75 6.1.2(g) (enhanced display)page 30 of 59
6.3 7-Day Calibration Error Test
6.3.1 Gas Monitor 7-Day Calibration Error Test
section 5.1 of this appendix, at the low-, mid-, and high-range concentrations specified in section 5.2
of this appendix. Introduce the calibration gas at the gas injection port, as specified in section 2.2.1
of this appendix. Operate each monitor at its normal operating temperature and conditions. For
extractive and dilution type monitors, pass the calibration gas through all filters, scrubbers,
conditioners, and other monitor components used during normal sampling and through as much of
the sampling probe as is practical. For in-situ type monitors, perform calibration checking all active
electronic and optical components, including the transmitter, receiver, and analyzer. Challenge the
monitor three times with each reference gas (see example data sheet in Figure 1). Do not use the
same gas twice in succession. To the extent practicable, the duration of each linearity test, from the
hour of the first injection to the hour of the last injection, shall not exceed 24 unit operating hours.
Record the monitor response from the data acquisition and handling system. For each
concentration, use the average of the responses to determine the error in linearity using Equation A-4
in this appendix. Linearity checks are acceptable for monitor or monitoring system certification,
recertification, or quality assurance if none of the test results exceed the applicable performance
specifications in section 3.2 of this appendix. The status of emission data from a CEMS prior to and
during a linearity test period shall be determined as follows:
(a)For the initial certification of a CEMS, data from the monitoring system are considered invalid
until all certification tests, including the linearity test, have been successfully completed, unless
the conditional data validation procedures in § 75.20(b)(3)are used. When the procedures in §
75.20(b)(3)are followed, the words “initial certification” apply instead of “recertification,” and
complete all of the initial certification tests by the applicable deadline in § 75.4, rather than
within the time periods specified in § 75.20(b)(3)(iv)for the individual tests.
(b)For the routine quality assurance linearity checks required by section 2.2.1 of appendix B to this
part, use the data validation procedures in section 2.2.3 of appendix B to this part.
(c)When a linearity test is required as a diagnostic test or for recertification, use the data
validation procedures in § 75.20(b)(3).
(d)For linearity tests of non-redundant backup monitoring systems, use the data validation
procedures in § 75.20(d)(2)(iii).
(e)For linearity tests performed during a grace period and after the expiration of a grace period,
use the data validation procedures in sections 2.2.3 and 2.2.4, respectively, of appendix B to
this part.
(f)For all other linearity checks, use the data validation procedures in section 2.2.3 of appendix B
to this part.
The following monitors and ranges are exempted from the 7-day calibration error test
requirements of this part: the SO2, NOX, CO2 and O2 monitors installed on peaking units (as
defined in § 72.2 of this chapter); and any SO2 or NOX measurement range with a span value of
50 ppm or less. In all other cases, measure the calibration error of each SO2 monitor, each NOX
monitor, and each CO2 or O2 monitor while the unit is combusting fuel (but not necessarily
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generating electricity) once each day for 7 consecutive operating days according to the
following procedures. (In the event that unit outages occur after the commencement of the
test, the 7 consecutive unit operating days need not be 7 consecutive calendar days). Units
using dual span monitors must perform the calibration error test on both high- and low-scales
of the pollutant concentration monitor. The calibration error test procedures in this section and
in section 6.3.2 of this appendix shall also be used to perform the daily assessments and
additional calibration error tests required under sections 2.1.1 and 2.1.3 of appendix B to this
part. Do not make manual or automatic adjustments to the monitor settings until after taking
measurements at both zero and high concentration levels for that day during the 7-day test. If
automatic adjustments are made following both injections, conduct the calibration error test
such that the magnitude of the adjustments can be determined and recorded. Record and
report test results for each day using the unadjusted concentration measured in the calibration
error test prior to making any manual or automatic adjustments (i.e.,resetting the calibration).
The calibration error tests should be approximately 24 hours apart, (unless the 7-day test is
performed over nonconsecutive days). Perform calibration error tests at both the zero-level
concentration and high-level concentration, as specified in section 5.2 of this appendix.
Alternatively, a mid-level concentration gas (50.0 to 60.0 percent of the span value) may be
used in lieu of the high-level gas, provided that the mid-level gas is more representative of the
actual stack gas concentrations. A calibration gas blend may be used as both a zero-level gas
and an upscale (mid- or high-level) gas, where appropriate. In addition, repeat the procedure for
SO2 and NOX pollutant concentration monitors using the low-scale for units equipped with
emission controls or other units with dual span monitors. Use only calibration gas, as specified
in section 5.1 of this appendix. Introduce the calibration gas at the gas injection port, as
specified in section 2.2.1 of this appendix. Operate each monitor in its normal sampling mode.
For extractive and dilution type monitors, pass the calibration gas through all filters, scrubbers,
conditioners, and other monitor components used during normal sampling and through as
much of the sampling probe as is practical. For in-situ type monitors, perform calibration,
checking all active electronic and optical components, including the transmitter, receiver, and
analyzer. Challenge the pollutant concentration monitors and CO2 or O2 monitors once with
each calibration gas. Record the monitor response from the data acquisition and handling
system. Using Equation A-5 of this appendix, determine the calibration error at each
concentration once each day (at approximately 24-hour intervals) for 7 consecutive days
according to the procedures given in this section. The results of a 7-day calibration error test
are acceptable for monitor or monitoring system certification, recertification or diagnostic
testing if none of these daily calibration error test results exceed the applicable performance
specifications in section 3.1 of this appendix. The status of emission data from a gas monitor
prior to and during a 7-day calibration error test period shall be determined as follows:
(a)For initial certification, data from the monitor are considered invalid until all certification
tests, including the 7-day calibration error test, have been successfully completed, unless
the conditional data validation procedures in § 75.20(b)(3)are used. When the procedures
in § 75.20(b)(3)are followed, the words “initial certification” apply instead of
“recertification,” and complete all of the initial certification tests by the applicable deadline
in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv)for the
individual tests.
(b)When a 7-day calibration error test is required as a diagnostic test or for recertification,
use the data validation procedures in § 75.20(b)(3).
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.3.1(a)
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6.3.2 Flow Monitor 7-day Calibration Error Test
6.4 Cycle Time Test
Flow monitors installed on peaking units (as defined in § 72.2 of this chapter) are exempted
from the 7-day calibration error test requirements of this part. In all other cases, perform the
7-day calibration error test of a flow monitor, when required for certification, recertification or
diagnostic testing, according to the following procedures. Introduce the reference signal
corresponding to the values specified in section 2.2.2.1 of this appendix to the probe tip (or
equivalent), or to the transducer. During the 7-day certification test period, conduct the
calibration error test while the unit is operating once each unit operating day (as close to
24-hour intervals as practicable). In the event that unit outages occur after the commencement
of the test, the 7 consecutive operating days need not be 7 consecutive calendar days. Record
the flow monitor responses by means of the data acquisition and handling system. Calculate
the calibration error using Equation A-6 of this appendix. Do not perform any corrective
maintenance, repair, or replacement upon the flow monitor during the 7-day test period other
than that required in the quality assurance/quality control plan required by appendix B to this
part. Do not make adjustments between the zero and high reference level measurements on
any day during the 7-day test. If the flow monitor operates within the calibration error
performance specification (i.e., less than or equal to 3.0 percent error each day and requiring no
corrective maintenance, repair, or replacement during the 7-day test period), the flow monitor
passes the calibration error test. Record all maintenance activities and the magnitude of any
adjustments. Record output readings from the data acquisition and handling system before and
after all adjustments. Record and report all calibration error test results using the unadjusted
flow rate measured in the calibration error test prior to resetting the calibration. Record all
adjustments made during the 7-day period at the time the adjustment is made, and report them
in the certification or recertification application. The status of emissions data from a flow
monitor prior to and during a 7-day calibration error test period shall be determined as follows:
(a)For initial certification, data from the monitor are considered invalid until all certification
tests, including the 7-day calibration error test, have been successfully completed, unless
the conditional data validation procedures in § 75.20(b)(3) are used. When the procedures
in § 75.20(b)(3)are followed, the words “initial certification” apply instead of
“recertification,” and complete all of the initial certification tests by the applicable deadline
in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv)for the
individual tests.
(b)When a 7-day calibration error test is required as a diagnostic test or for recertification,
use the data validation procedures in § 75.20(b)(3).
6.3.3 For gas or flow monitors installed on peaking units, the exemption from performing the 7-day
calibration error test applies as long as the unit continues to meet the definition of a peaking
unit in § 72.2 of this chapter. However, if at the end of a particular calendar year or ozone
season, it is determined that peaking unit status has been lost, the owner or operator shall
perform a diagnostic 7-day calibration error test of each monitor installed on the unit, by no
later than December 31 of the following calendar year.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.3.2(a)
40 CFR Appendix-A-to-Part-75 6.3.3 (enhanced display)page 33 of 59
Perform cycle time tests for each pollutant concentration monitor and continuous emission
monitoring system while the unit is operating, according to the following procedures. Use a zero-
level and a high-level calibration gas (as defined in section 5.2 of this appendix) alternately. To
determine the downscale cycle time, measure the concentration of the flue gas emissions until the
response stabilizes. Record the stable emissions value. Inject a zero-level concentration calibration
gas into the probe tip (or injection port leading to the calibration cell, for in situ systems with no
probe). Record the time of the zero gas injection, using the data acquisition and handling system
(DAHS). Next, allow the monitor to measure the concentration of the zero gas until the response
stabilizes. Record the stable ending calibration gas reading. Determine the downscale cycle time as
the time it takes for 95.0 percent of the step change to be achieved between the stable stack
emissions value and the stable ending zero gas reading. Then repeat the procedure, starting with
stable stack emissions and injecting the high-level gas, to determine the upscale cycle time, which is
the time it takes for 95.0 percent of the step change to be achieved between the stable stack
emissions value and the stable ending high-level gas reading. Use the following criteria to assess
when a stable reading of stack emissions or calibration gas concentration has been attained. A
stable value is equivalent to a reading with a change of less than 2.0 percent of the span value for 2
minutes, or a reading with a change of less than 6.0 percent from the measured average
concentration over 6 minutes. Alternatively, the reading is considered stable if it changes by no more
than 0.5 ppm or 0.2% CO2 or O2 (as applicable) for two minutes. (Owners or operators of systems
which do not record data in 1-minute or 3-minute intervals may petition the Administrator under §
75.66 for alternative stabilization criteria). For monitors or monitoring systems that perform a series
of operations (such as purge, sample, and analyze), time the injections of the calibration gases so
they will produce the longest possible cycle time. Refer to Figures 6a and 6b in this appendix for
example calculations of upscale and downscale cycle times. Report the slower of the two cycle
times (upscale or downscale) as the cycle time for the analyzer. Prior to January 1, 2009 for the
NOX-diluent continuous emission monitoring system test, either record and report the longer cycle
time of the two component analyzers as the system cycle time or record the cycle time for each
component analyzer separately (as applicable). On and after January 1, 2009, record the cycle time
for each component analyzer separately. For time-shared systems, perform the cycle time tests at
each probe locations that will be polled within the same 15-minute period during monitoring system
operations. To determine the cycle time for time-shared systems, at each monitoring location, report
the sum of the cycle time observed at that monitoring location plus the sum of the time required for
all purge cycles (as determined by the continuous emission monitoring system manufacturer) at
each of the probe locations of the time-shared systems. For monitors with dual ranges, report the
test results for each range separately. Cycle time test results are acceptable for monitor or
monitoring system certification, recertification or diagnostic testing if none of the cycle times
exceed 15 minutes. The status of emissions data from a monitor prior to and during a cycle time
test period shall be determined as follows:
(a)For initial certification, data from the monitor are considered invalid until all certification tests,
including the cycle time test, have been successfully completed, unless the conditional data
validation procedures in § 75.20(b)(3)are used. When the procedures in § 75.20(b)(3)are
followed, the words “initial certification” apply instead of “recertification,” and complete all of
the initial certification tests by the applicable deadline in § 75.4, rather than within the time
periods specified in § 75.20(b)(3)(iv)for the individual tests.
(b)When a cycle time test is required as a diagnostic test or for recertification, use the data
validation procedures in § 75.20(b)(3).
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.4(a)
40 CFR Appendix-A-to-Part-75 6.4(b) (enhanced display)page 34 of 59
6.5 Relative Accuracy and Bias Tests (General Procedures)
Perform the required relative accuracy test audits (RATAs) as follows for each CO2 emissions
concentration monitor (including O2 monitors used to determine CO2 emissions concentration), each
SO2 pollutant concentration monitor, each NOX concentration monitoring system used to determine
NOX mass emissions, each flow monitor, each NOX-diluent CEMS, each O2 or CO2 diluent monitor
used to calculate heat input, and each moisture monitoring system. For NOX concentration
monitoring systems used to determine NOX mass emissions, as defined in § 75.71(a)(2), use the
same general RATA procedures as for SO2 pollutant concentration monitors; however, use the
reference methods for NOX concentration specified in section 6.5.10 of this appendix:
(a)Except as otherwise provided in this paragraph or in § 75.21(a)(5), perform each RATA while the
unit (or units, if more than one unit exhausts into the flue) is combusting the fuel that is a
normal primary or backup fuel for that unit (for some units, more than one type of fuel may be
considered normal,e.g., a unit that combusts gas or oil on a seasonal basis). For units that co-
fire fuels as the predominant mode of operation, perform the RATAs while co-firing. For Hg
monitoring systems, perform the RATAs while the unit is combusting coal. When relative
accuracy test audits are performed on CEMS installed on bypass stacks/ducts, use the fuel
normally combusted by the unit (or units, if more than one unit exhausts into the flue) when
emissions exhaust through the bypass stack/ducts.
(b)Perform each RATA at the load (or operating) level(s) specified in section 6.5.1 or 6.5.2 of this
appendix or in section 2.3.1.3 of appendix B to this part, as applicable.
(c)For monitoring systems with dual ranges, perform the relative accuracy test on the range
normally used for measuring emissions. For units with add-on SO2 or NOX controls that operate
continuously rather than seasonally, or for units that need a dual range to record high
concentration “spikes” during startup conditions, the low range is considered normal. However,
for some dual span units (e.g.,for units that use fuel switching or for which the emission
controls are operated seasonally), provided that both monitor ranges are connected to a
common probe and sample interface, either of the two measurement ranges may be
considered normal; in such cases, perform the RATA on the range that is in use at the time of
the scheduled test. If the low and high measurement ranges are connected to separate sample
probes and interfaces, RATA testing on both ranges is required.
(d)Record monitor or monitoring system output from the data acquisition and handling system.
(e)Complete each single-load relative accuracy test audit within a period of 168 consecutive unit
operating hours, as defined in § 72.2 of this chapter (or, for CEMS installed on common stacks
or bypass stacks, 168 consecutive stack operating hours, as defined in § 72.2 of this chapter).
For 2-level and 3-level flow monitor RATAs, complete all of the RATAs at all levels, to the extent
practicable, within a period of 168 consecutive unit (or stack) operating hours; however, if this
is not possible, up to 720 consecutive unit (or stack) operating hours may be taken to complete
a multiple-load flow RATA.
(f)The status of emission data from the CEMS prior to and during the RATA test period shall be
determined as follows:
(1)For the initial certification of a CEMS, data from the monitoring system are considered
invalid until all certification tests, including the RATA, have been successfully completed,
unless the conditional data validation procedures in § 75.20(b)(3)are used. When the
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40 CFR Appendix-A-to-Part-75 6.5(f)(1) (enhanced display)page 35 of 59
6.5.1 Gas Monitoring System RATAs (Special Considerations)
6.5.2 Flow Monitor RATAs (Special Considerations)
procedures in § 75.20(b)(3)are followed, the words “initial certification” apply instead of
“recertification,” and complete all of the initial certification tests by the applicable deadline
in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv)for the
individual tests.
(2)For the routine quality assurance RATAs required by section 2.3.1 of appendix B to this
part, use the data validation procedures in section 2.3.2 of appendix B to this part.
(3)For recertification RATAs, use the data validation procedures in § 75.20(b)(3).
(4)For quality assurance RATAs of non-redundant backup monitoring systems, use the data
validation procedures in §§ 75.20(d)(2)(v)and (vi).
(5)For RATAs performed during and after the expiration of a grace period, use the data
validation procedures in sections 2.3.2 and 2.3.3, respectively, of appendix B to this part.
(6)For all other RATAs, use the data validation procedures in section 2.3.2 of appendix B to
this part.
(g)For each SO2 or CO2 emissions concentration monitor, each flow monitor, each CO2 or O2
diluent monitor used to determine heat input, each NOX concentration monitoring system used
to determine NOX mass emissions, as defined in § 75.71(a)(2), each moisture monitoring
system, and each NOX-diluent CEMS, calculate the relative accuracy, in accordance with section
7.3 or 7.4 of this appendix, as applicable. In addition (except for CO2, O2, or moisture monitors),
test for bias and determine the appropriate bias adjustment factor, in accordance with sections
7.6.4 and 7.6.5 of this appendix, using the data from the relative accuracy test audits.
(a)Perform the required relative accuracy test audits for each SO2 or CO2 emissions concentration
monitor, each CO2 or O2 diluent monitor used to determine heat input, each NOX-diluent CEMS,
and each NOX concentration monitoring system used to determine NOX mass emissions, as
defined in § 75.71(a)(2), at the normal load level or normal operating level for the unit (or
combined units, if common stack), as defined in section 6.5.2.1 of this appendix. If two load
levels or operating levels have been designated as normal, the RATAs may be done at either
load (or operating) level.
(b)For the initial certification of a gas monitoring system and for recertifications in which, in
addition to a RATA, one or more other tests are required (i.e.,a linearity test, cycle time test, or
7-day calibration error test), EPA recommends that the RATA not be commenced until the other
required tests of the CEMS have been passed.
(a)Except as otherwise provided in paragraph (b)or (e)of this section, perform relative accuracy
test audits for the initial certification of each flow monitor at three different exhaust gas
velocities (low, mid, and high), corresponding to three different load levels or operating levels
within the range of operation, as defined in section 6.5.2.1 of this appendix. For a common
stack/duct, the three different exhaust gas velocities may be obtained from frequently used
unit/load or operating level combinations for the units exhausting to the common stack. Select
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
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40 CFR Appendix-A-to-Part-75 6.5(a) (enhanced display)page 36 of 59
6.5.2.1 Range of Operation and Normal Load (or Operating) Level(s)
the three exhaust gas velocities such that the audit points at adjacent load or operating levels
(i.e., low and mid or mid and high), in megawatts (or in thousands of lb/hr of steam production
or in ft/sec, as applicable), are separated by no less than 25.0 percent of the range of operation,
as defined in section 6.5.2.1 of this appendix.
(b)For flow monitors on bypass stacks/ducts and peaking units, the flow monitor relative accuracy
test audits for initial certification and recertification shall be single-load tests, performed at the
normal load, as defined in section 6.5.2.1(d) of this appendix.
(c)Flow monitor recertification RATAs shall be done at three load level(s) (or three operating
levels), unless otherwise specified in paragraph (b)or (e)of this section or unless otherwise
specified or approved by the Administrator.
(d)The semiannual and annual quality assurance flow monitor RATAs required under appendix B to
this part shall be done at the load level(s) (or operating levels) specified in section 2.3.1.3 of
appendix B to this part.
(e)For flow monitors installed on units that do not produce electrical or thermal output, the flow
RATAs for initial certification or recertification may be done at fewer than three operating levels,
if:
(1)The owner or operator provides a technical justification in the hardcopy portion of the
monitoring plan for the unit required under § 75.53(e)(2), demonstrating that the unit
operates at only one level or two levels during normal operation (excluding unit startup
and shutdown). Appropriate documentation and data must be provided to support the
claim of single-level or two-level operation; and
(2)The justification provided in paragraph (e)(1)of this section is deemed to be acceptable by
the permitting authority.
(a)The owner or operator shall determine the upper and lower boundaries of the “range of
operation” as follows for each unit (or combination of units, for common stack configurations):
(1)For affected units that produce electrical output (in megawatts) or thermal output (in klb/
hr of steam production or mmBtu/hr), the lower boundary of the range of operation of a
unit shall be the minimum safe, stable loads for any of the units discharging through the
stack. Alternatively, for a group of frequently-operated units that serve a common stack,
the sum of the minimum safe, stable loads for the individual units may be used as the
lower boundary of the range of operation. The upper boundary of the range of operation of
a unit shall be the maximum sustainable load. The “maximum sustainable load” is the
higher of either: the nameplate or rated capacity of the unit, less any physical or regulatory
limitations or other deratings; or the highest sustainable load, based on at least four
quarters of representative historical operating data. For common stacks, the maximum
sustainable load is the sum of all of the maximum sustainable loads of the individual units
discharging through the stack, unless this load is unattainable in practice, in which case
use the highest sustainable combined load for the units that discharge through the stack.
Based on at least four quarters of representative historical operating data. The load values
for the unit(s) shall be expressed either in units of megawatts of thousands of lb/hr of
steam load or mmBtu/hr of thermal output; or
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(b)
40 CFR Appendix-A-to-Part-75 6.5(a)(1) (enhanced display)page 37 of 59
(2)For affected units that do not produce electrical or thermal output, the lower boundary of
the range of operation shall be the minimum expected flue gas velocity (in ft/sec) during
normal, stable operation of the unit. The upper boundary of the range of operation shall be
the maximum potential flue gas velocity (in ft/sec) as defined in section 2.1.4.1 of this
appendix. The minimum expected and maximum potential velocities may be derived from
the results of reference method testing or by using Equation A-3a or A-3b (as applicable)
in section 2.1.4.1 of this appendix. If Equation A-3a or A-3b is used to determine the
minimum expected velocity, replace the word “maximum” with the word “minimum” in the
definitions of “MPV,” “Hf,” “% O2d,” and “% H2O,” and replace the word “minimum” with the
word “maximum” in the definition of “CO2d.” Alternatively, 0.0 ft/sec may be used as the
lower boundary of the range of operation.
(b)The operating levels for relative accuracy test audits shall, except for peaking units, be defined
as follows: the “low” operating level shall be the first 30.0 percent of the range of operation; the
“mid” operating level shall be the middle portion (>30.0 percent, but ≤60.0 percent) of the range
of operation; and the “high” operating level shall be the upper end (>60.0 percent) of the range
of operation. For example, if the upper and lower boundaries of the range of operation are 100
and 1100 megawatts, respectively, then the low, mid, and high operating levels would be 100 to
400 megawatts, 400 to 700 megawatts, and 700 to 1100 megawatts, respectively.
(c)Units that do not produce electrical or thermal output are exempted from the requirements of
this paragraph, (c). The owner or operator shall identify, for each affected unit or common stack
(except for peaking units and units using the low mass emissions (LME) excepted
methodology under § 75.19), the “normal” load level or levels (low, mid or high), based on the
operating history of the unit(s). To identify the normal load level(s), the owner or operator shall,
at a minimum, determine the relative number of operating hours at each of the three load levels,
low, mid and high over the past four representative operating quarters. The owner or operator
shall determine, to the nearest 0.1 percent, the percentage of the time that each load level (low,
mid, high) has been used during that time period. A summary of the data used for this
determination and the calculated results shall be kept on-site in a format suitable for
inspection. For new units or newly-affected units, the data analysis in this paragraph may be
based on fewer than four quarters of data if fewer than four representative quarters of
historical load data are available. Or, if no historical load data are available, the owner or
operator may designate the normal load based on the expected or projected manner of
operating the unit. However, in either case, once four quarters of representative data become
available, the historical load analysis shall be repeated.
(d)Determination of normal load (or operating level)
(1)Based on the analysis of the historical load data described in paragraph (c)of this section,
the owner or operator shall, for units that produce electrical or thermal output, designate
the most frequently used load level as the normal load level for the unit (or combination of
units, for common stacks). The owner or operator may also designate the second most
frequently used load level as an additional normal load level for the unit or stack. For
peaking units and LME units, normal load designations are unnecessary; the entire
operating load range shall be considered normal. If the manner of operation of the unit
changes significantly, such that the designated normal load(s) or the two most frequently
used load levels change, the owner or operator shall repeat the historical load analysis and
shall redesignate the normal load(s) and the two most frequently used load levels, as
appropriate. A minimum of two representative quarters of historical load data are required
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(a)(2)
40 CFR Appendix-A-to-Part-75 6.5(d)(1) (enhanced display)page 38 of 59
6.5.2.2 Multi-Load (or Multi-Level) Flow RATA Results
For each multi-load (or multi-level) flow RATA, calculate the flow monitor relative accuracy at each operating level. If
a flow monitor relative accuracy test is failed or aborted due to a problem with the monitor on any level of a 2-level
(or 3-level) relative accuracy test audit, the RATA must be repeated at that load (or operating) level. However, the
entire 2-level (or 3-level) relative accuracy test audit does not have to be repeated unless the flow monitor
polynomial coefficients or K-factor(s) are changed, in which case a 3-level RATA is required (or, a 2-level RATA, for
units demonstrated to operate at only two levels, under section 6.5.2(e) of this appendix).
6.5.3 [Reserved]
6.5.4 Calculations
Using the data from the relative accuracy test audits, calculate relative accuracy and bias in accordance with the
procedures and equations specified in section 7 of this appendix.
6.5.5 Reference Method Measurement Location
Select a location for reference method measurements that is (1) accessible; (2) in the same proximity as the
monitor or monitoring system location; and (3) meets the requirements of Performance Specification 2 in appendix
B of part 60 of this chapter for SO2 and NOX continuous emission monitoring systems, Performance Specification 3
in appendix B of part 60 of this chapter for CO2 or O2 monitors, or method 1 (or 1A) in appendix A of part 60 of this
chapter for volumetric flow, except as otherwise indicated in this section or as approved by the Administrator.
6.5.6 Reference Method Traverse Point Selection
Select traverse points that ensure acquisition of representative samples of pollutant and diluent concentrations,
moisture content, temperature, and flue gas flow rate over the flue cross section. To achieve this, the reference
method traverse points shall meet the requirements of section 8.1.3 of Performance Specification 2 (“PS No. 2”) in
to document that a change in the manner of unit operation has occurred. Update the
electronic monitoring plan whenever the normal load level(s) and the two most frequently-
used load levels are redesignated.
(2)For units that do not produce electrical or thermal output, the normal operating level(s)
shall be determined using sound engineering judgment, based on knowledge of the unit
and operating experience with the industrial process.
(e)The owner or operator shall report the upper and lower boundaries of the range of operation for
each unit (or combination of units, for common stacks), in units of megawatts or thousands of
lb/hr or mmBtu/hr of steam production or ft/sec (as applicable), in the electronic monitoring
plan required under § 75.53. Except for peaking units and LME units, the owner or operator
shall indicate, in the electronic monitoring plan, the load level (or levels) designated as normal
under this section and shall also indicate the two most frequently used load levels.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(d)(2)
40 CFR Appendix-A-to-Part-75 6.5(e) (enhanced display)page 39 of 59
appendix B to part 60 of this chapter (for SO2, NOX, and moisture monitoring system RATAs), Performance
Specification 3 in appendix B to part 60 of this chapter (for O2 and CO2 monitor RATAs), Method 1 (or 1A) (for
volumetric flow rate monitor RATAs), Method 3 (for molecular weight), and Method 4 (for moisture determination) in
appendix A to part 60 of this chapter. The following alternative reference method traverse point locations are
permitted for moisture and gas monitor RATAs:
6.5.6.1 Stratification Test
(a)For moisture determinations where the moisture data are used only to determine stack gas
molecular weight, a single reference method point, located at least 1.0 meter from the stack
wall, may be used. For moisture monitoring system RATAs and for gas monitor RATAs in which
moisture data are used to correct pollutant or diluent concentrations from a dry basis to a wet
basis (or vice-versa), single-point moisture sampling may only be used if the 12-point
stratification test described in section 6.5.6.1 of this appendix is performed prior to the RATA
for at least one pollutant or diluent gas, and if the test is passed according to the acceptance
criteria in section 6.5.6.3(b) of this appendix.
(b)For gas monitoring system RATAs, the owner or operator may use any of the following options:
(1)At any location (including locations where stratification is expected), use a minimum of six
traverse points along a diameter, in the direction of any expected stratification. The points
shall be located in accordance with Method 1 in appendix A to part 60 of this chapter.
(2)At locations where section 8.1.3 of PS No. 2 allows the use of a short reference method
measurement line (with three points located at 0.4, 1.2, and 2.0 meters from the stack
wall), the owner or operator may use an alternative 3-point measurement line, locating the
three points at 4.4, 14.6, and 29.6 percent of the way across the stack, in accordance with
Method 1 in appendix A to part 60 of this chapter.
(3)At locations where stratification is likely to occur (e.g., following a wet scrubber or when
dissimilar gas streams are combined), the short measurement line from section 8.1.3 of
PS No. 2 (or the alternative line described in paragraph (b)(2)of this section) may be used
in lieu of the prescribed “long” measurement line in section 8.1.3 of PS No. 2, provided
that the 12-point stratification test described in section 6.5.6.1 of this appendix is
performed and passed one time at the location (according to the acceptance criteria of
section 6.5.6.3(a) of this appendix) and provided that either the 12-point stratification test
or the alternative (abbreviated) stratification test in section 6.5.6.2 of this appendix is
performed and passed prior to each subsequent RATA at the location (according to the
acceptance criteria of section 6.5.6.3(a) of this appendix).
(4)A single reference method measurement point, located no less than 1.0 meter from the
stack wall and situated along one of the measurement lines used for the stratification test,
may be used at any sampling location if the 12-point stratification test described in
section 6.5.6.1 of this appendix is performed and passed prior to each RATA at the
location (according to the acceptance criteria of section 6.5.6.3(b) of this appendix).
(5)If Method 7E is used as the reference method for the RATA of a NOX CEMS installed on a
combustion turbine, the reference method measurements may be made at the sampling
points specified in section 6.1.2 of Method 20 in appendix A to part 60 of this chapter.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(a)
40 CFR Appendix-A-to-Part-75 6.5(b)(5) (enhanced display)page 40 of 59
6.5.6.2 Alternative (Abbreviated) Stratification Test
(a)With the unit(s) operating under steady-state conditions at the normal load level (or normal
operating level), as defined in section 6.5.2.1 of this appendix, use a traversing gas sampling
probe to measure the pollutant (SO2 or NOX) and diluent (CO2 or O2) concentrations at a
minimum of twelve (12) points, located according to Method 1 in appendix A to part 60 of this
chapter.
(b)Use Methods 6C, 7E, and 3A in appendix A to part 60 of this chapter to make the
measurements. Data from the reference method analyzers must be quality-assured by
performing analyzer calibration error and system bias checks before the series of
measurements and by conducting system bias and calibration drift checks after the
measurements, in accordance with the procedures of Methods 6C, 7E, and 3A.
(c)Measure for a minimum of 2 minutes at each traverse point. To the extent practicable, complete
the traverse within a 2-hour period.
(d)If the load has remained constant (±3.0 percent) during the traverse and if the reference
method analyzers have passed all of the required quality assurance checks, proceed with the
data analysis.
(e)Calculate the average NOX, SO2, and CO2 (or O2) concentrations at each of the individual
traverse points. Then, calculate the arithmetic average NOX, SO2, and CO2 (or O2)
concentrations for all traverse points.
(a)With the unit(s) operating under steady-state conditions at normal load level (or normal
operating level), as defined in section 6.5.2.1 of this appendix, use a traversing gas sampling
probe to measure the pollutant (SO2 or NOX) and diluent (CO2 or O2) concentrations at three
points. The points shall be located according to the specifications for the long measurement
line in section 8.1.3 of PS No. 2 (i.e., locate the points 16.7 percent, 50.0 percent, and 83.3
percent of the way across the stack). Alternatively, the concentration measurements may be
made at six traverse points along a diameter. The six points shall be located in accordance with
Method 1 in appendix A to part 60 of this chapter.
(b)Use Methods 6C, 7E, and 3A in appendix A to part 60 of this chapter to make the
measurements. Data from the reference method analyzers must be quality-assured by
performing analyzer calibration error and system bias checks before the series of
measurements and by conducting system bias and calibration drift checks after the
measurements, in accordance with the procedures of Methods 6C, 7E, and 3A.
(c)Measure for a minimum of 2 minutes at each traverse point. To the extent practicable, complete
the traverse within a 1-hour period.
(d)If the load has remained constant (±3.0 percent) during the traverse and if the reference
method analyzers have passed all of the required quality assurance checks, proceed with the
data analysis.
(e)Calculate the average NOX, SO2, and CO2 (or O2) concentrations at each of the individual
traverse points. Then, calculate the arithmetic average NOX, SO2, and CO2 (or O2)
concentrations for all traverse points.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(a)
40 CFR Appendix-A-to-Part-75 6.5(e) (enhanced display)page 41 of 59
6.5.6.3 Stratification Test Results and Acceptance Criteria
6.5.7 Sampling Strategy
(a)For each pollutant or diluent gas, the short reference method measurement line described in
section 8.1.3 of PS No. 2 may be used in lieu of the long measurement line prescribed in
section 8.1.3 of PS No. 2 if the results of a stratification test, conducted in accordance with
section 6.5.6.1 or 6.5.6.2 of this appendix (as appropriate; see section 6.5.6(b)(3) of this
appendix), show that the concentration at each individual traverse point differs by no more than
±10.0 percent from the arithmetic average concentration for all traverse points. The results are
also acceptable if the concentration at each individual traverse point differs by no more than
±5ppm or ±0.5 percent CO2 (or O2) from the arithmetic average concentration for all traverse
points.
(b)For each pollutant or diluent gas, a single reference method measurement point, located at
least 1.0 meter from the stack wall and situated along one of the measurement lines used for
the stratification test, may be used for that pollutant or diluent gas if the results of a
stratification test, conducted in accordance with section 6.5.6.1 of this appendix, show that the
concentration at each individual traverse point differs by no more than ±5.0 percent from the
arithmetic average concentration for all traverse points. The results are also acceptable if the
concentration at each individual traverse point differs by no more than ±3 ppm or ±0.3 percent
CO2 (or O2) from the arithmetic average concentration for all traverse points.
(c)The owner or operator shall keep the results of all stratification tests on-site, in a format
suitable for inspection, as part of the supplementary RATA records required under §
75.59(a)(7).
(a)Conduct the reference method tests allowed in section 6.5.10 of this appendix so they will yield
results representative of the pollutant concentration, emission rate, moisture, temperature, and
flue gas flow rate from the unit and can be correlated with the pollutant concentration monitor,
CO2 or O2 monitor, flow monitor, and SO2 or NOX CEMS measurements. The minimum
acceptable time for a gas monitoring system RATA run or for a moisture monitoring system
RATA run is 21 minutes. For each run of a gas monitoring system RATA, all necessary pollutant
concentration measurements, diluent concentration measurements, and moisture
measurements (if applicable) must, to the extent practicable, be made within a 60-minute
period. For NOX-diluent monitoring system RATAs, the pollutant and diluent concentration
measurements must be made simultaneously. For flow monitor RATAs, the minimum time per
run shall be 5 minutes. Flow rate reference method measurements allowed in section 6.5.10 of
this appendix may be made either sequentially from port-to-port or simultaneously at two or
more sample ports. The velocity measurement probe may be moved from traverse point to
traverse point either manually or automatically. If, during a flow RATA, significant pulsations in
the reference method readings are observed, be sure to allow enough measurement time at
each traverse point to obtain an accurate average reading when a manual readout method is
used (e.g.,a “sight-weighted” average from a manometer). Also, allow sufficient measurement
time to ensure that stable temperature readings are obtained at each traverse point, particularly
at the first measurement point at each sample port, when a probe is moved sequentially from
port-to-port. A minimum of one set of auxiliary measurements for stack gas molecular weight
determination (i.e.,diluent gas data and moisture data) is required for every clock hour of a flow
RATA or for every three test runs (whichever is less restrictive). Alternatively, moisture
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(a)
40 CFR Appendix-A-to-Part-75 6.5(a) (enhanced display)page 42 of 59
6.5.8 Correlation of Reference Method and Continuous Emission Monitoring System
Confirm that the monitor or monitoring system and reference method test results are on consistent moisture,
pressure, temperature, and diluent concentration basis (e.g., since the flow monitor measures flow rate on a wet
basis, method 2 test results must also be on a wet basis). Compare flow-monitor and reference method results on a
scfh basis. Also, consider the response times of the pollutant concentration monitor, the continuous emission
monitoring system, and the flow monitoring system to ensure comparison of simultaneous measurements.
For each relative accuracy test audit run, compare the measurements obtained from the monitor or continuous
emission monitoring system (in ppm, percent CO2, lb/mmBtu, or other units) against the corresponding reference
method values. Tabulate the paired data in a table such as the one shown in Figure 2.
6.5.9 Number of Reference Method Tests
Perform a minimum of nine sets of paired monitor (or monitoring system) and reference method test data for every
required (i.e., certification, recertification, diagnostic, semiannual, or annual) relative accuracy test audit. For 2-level
and 3-level relative accuracy test audits of flow monitors, perform a minimum of nine sets at each of the operating
levels.
Note:The tester may choose to perform more than nine sets of reference method tests. If this
option is chosen, the tester may reject a maximum of three sets of the test results, as long as the
measurements for molecular weight determination may be performed before and after a series
of flow RATA runs at a particular load level (low, mid, or high), provided that the time interval
between the two moisture measurements does not exceed three hours. If this option is
selected, the results of the two moisture determinations shall be averaged arithmetically and
applied to all RATA runs in the series. Successive flow RATA runs may be performed without
waiting in between runs. If an O2 diluent monitor is used as a CO2 continuous emission
monitoring system, perform a CO2 system RATA (i.e.,measure CO2, rather than O2, with the
applicable reference method allowed in section 6.5.10 of this appendix). For moisture
monitoring systems, an appropriate coefficient, “K” factor or other suitable mathematical
algorithm may be developed prior to the RATA, to adjust the monitoring system readings with
respect to the applicable reference method allowed in section 6.5.10 of this appendix. If such a
coefficient, K-factor or algorithm is developed, it shall be applied to the CEMS readings during
the RATA and (if the RATA is passed), to the subsequent CEMS data, by means of the
automated data acquisition and handling system. The owner or operator shall keep records of
the current coefficient, K factor or algorithm, as specified in § 75.59(a)(5)(vii). Whenever the
coefficient, K factor or algorithm is changed, a RATA of the moisture monitoring system is
required.
(b)To properly correlate individual SO2 or NOX CEMS data (in lb/mmBtu) and volumetric flow rate
data with the applicable reference method data, annotate the beginning and end of each
reference method test run (including the exact time of day) on the individual chart recorder(s)
or other permanent recording device(s).
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(b)
40 CFR Appendix-A-to-Part-75 6.5(b) (enhanced display)page 43 of 59
total number of test results used to determine the relative accuracy or bias is greater than or equal
to nine. Report all data, including the rejected CEMS data and corresponding reference method
test results.
6.5.10 Reference Methods
The following methods are from appendix A to part 60 of this chapter, and are the reference methods for
performing relative accuracy test audits under this part: Method 1 or 1A in appendix A-1 to part 60 of this chapter
for siting; Method 2 in appendix A-1 to part 60 of this chapter or its allowable alternatives in appendices A-1 and A-2
to part 60 of this chapter (except for Methods 2B and 2E in appendix A-1 to part 60 of this chapter) for stack gas
velocity and volumetric flow rate; Methods 3, 3A or 3B in appendix A-2 to part 60 of this chapter for O2 and CO2;
Method 4 in appendix A-3 to part 60 of this chapter for moisture; Methods 6, 6A or 6C in appendix A-4 to part 60 of
this chapter for SO2; and Methods 7, 7A, 7C, 7D or 7E in appendix A-4 to part 60 of this chapter for NOX, excluding
the exceptions to Method 7E identified in § 75.22(a)(5). When using Method 7E for measuring NOX concentration,
total NOX, including both NO and NO2, must be measured. When using EPA Protocol gas with Methods 3A, 6C, and
7E, the gas must be from an EPA Protocol gas production site that is participating in the EPA Protocol Gas
Verification Program, pursuant to § 75.21(g)(6). An EPA Protocol gas cylinder certified by or ordered from a non-
participating production site no later than May 27, 2011 may be used for the purposes of this part until the earlier of
the cylinder's expiration date or the date on which the cylinder gas pressure reaches 150 psig; however, in no case
shall the cylinder be recertified by a non-participating EPA Protocol gas production site to extend its useful life and
be used by a source subject to this part. In the event that an EPA Protocol gas production site is removed from the
list of PGVP participants on the same date as or after the date on which a particular cylinder is certified or ordered,
that gas cylinder may continue to be used for the purposes of this part until the earlier of the cylinder's expiration
date or the date on which the cylinder gas pressure reaches 150 psig; however, in no case shall the cylinder be
recertified by a non-participating EPA Protocol gas production site to extend its useful life and be used by a source
subject to this part.
7. Calculations
7.1 Linearity Check
Analyze the linearity data for pollutant concentration and CO2 or O2 monitors as follows. Calculate the percentage
error in linearity based upon the reference value at the low-level, mid-level, and high-level concentrations specified in
section 6.2 of this appendix. Perform this calculation once during the certification test. Use the following equation
to calculate the error in linearity for each reference value.
(Eq. A-4)
where,
LE = Percentage Linearity error, based upon the reference value.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(b)
40 CFR Appendix-A-to-Part-75 6.5(b) (enhanced display)page 44 of 59
R = Reference value of Low-, mid-, or high-level calibration gas introduced into the monitoring system.
A = Average of the monitoring system responses.
7.2 Calibration Error
7.2.1 Pollutant Concentration and Diluent Monitors
For each reference value, calculate the percentage calibration error based upon instrument span for daily calibration
error tests using the following equation:
(Eq. A-5)
where,
CE = Calibration error as a percentage of the span of the instrument.
R = Reference value of zero or upscale (high-level or mid-level, as applicable) calibration gas introduced into the
monitoring system.
A = Actual monitoring system response to the calibration gas.
S = Span of the instrument, as specified in section 2 of this appendix.
7.2.2 Flow Monitor Calibration Error
For each reference value, calculate the percentage calibration error based upon span using the following equation:
where:
CE = Calibration error as a percentage of span.
R = Low or high level reference value specified in section 2.2.2.1 of this appendix.
A = Actual flow monitor response to the reference value.
S = Flow monitor calibration span value as determined under section 2.1.4.2 of this appendix.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(b)
40 CFR Appendix-A-to-Part-75 6.5(b) (enhanced display)page 45 of 59
7.3 Relative Accuracy for SO2 and CO2 Emissions Concentration Monitors, O2 Monitors,
NOX Concentration Monitoring Systems, and Flow Monitors
Analyze the relative accuracy test audit data from the reference method tests for SO2 and CO2 emissions
concentration monitors, CO2 or O2 monitors used for heat input rate determination, NOX concentration monitoring
systems used to determine NOX mass emissions under subpart H of this part, and flow monitors using the
following procedures. Summarize the results on a data sheet. An example is shown in Figure 2. Calculate the mean
of the monitor or monitoring system measurement values. Calculate the mean of the reference method values.
Using data from the automated data acquisition and handling system, calculate the arithmetic differences between
the reference method and monitor measurement data sets. Then calculate the arithmetic mean of the difference,
the standard deviation, the confidence coefficient, and the monitor or monitoring system relative accuracy using the
following procedures and equations.
7.3.1 Arithmetic Mean
Calculate the arithmetic mean of the differences of a data set as follows:
7.3.2 Standard Deviation
Calculate the standard deviation, Sd, of a data set as follows:
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(b)
40 CFR Appendix-A-to-Part-75 6.5(b) (enhanced display)page 46 of 59
(Eq. A-8)
7.3.3 Confidence Coefficient
Calculate the confidence coefficient (one-tailed), cc, of a data set as follows.
(eq. A-9)
where,
t0.025 = t value (see table 7-1).
TABLE 7-1—T-VALUES
n-1 t0.025 n-1 t0.025 n-1 t0.025
1 12.706 12 2.179 23 2.069
2 4.303 13 2.160 24 2.064
3 3.182 14 2.145 25 2.060
4 2.776 15 2.131 26 2.056
5 2.571 16 2.120 27 2.052
6 2.447 17 2.110 28 2.048
7 2.365 18 2.101 29 2.045
8 2.306 19 2.093 30 2.042
9 2.262 20 2.086 40 2.021
10 2.228 21 2.080 60 2.000
11 2.201 22 2.074 >60 1.960
7.3.4 Relative Accuracy
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(b)
40 CFR Appendix-A-to-Part-75 6.5(b) (enhanced display)page 47 of 59
Calculate the relative accuracy of a data set using the following equation.
(Eq. A-10)
where,
RM = Arithmetic mean of the reference method values.
|d̄| = The absolute value of the mean difference between the reference method values and the corresponding
continuous emission monitoring system values.
|cc| = The absolute value of the confidence coefficient.
7.4 Relative Accuracy for NOX-diluent Continuous Emission Monitoring Systems
Analyze the relative accuracy test audit data from the reference method tests for NOX-diluent continuous emissions
monitoring system as follows.
7.4.1 Data Preparation
If CNOx, the NOX concentration, is in ppm, multiply it by 1.194 × 10−7 (lb/dscf)/ppm to convert it to units of lb/dscf. If
CNOx is in mg/dscm, multiply it by 6.24 × 10−8 (lb/dscf)/(mg/dscm) to convert it to lb/dscf. Then, use the diluent (O2
or CO2) reference method results for the run and the appropriate F or Fc factor from table 1 in appendix F of this
part to convert CNOx from lb/dscf to lb/mmBtu units. Use the equations and procedure in section 3 of appendix F to
this part, as appropriate.
7.4.2 NOX Emission Rate
For each test run in a data set, calculate the average NOX emission rate (in lb/mmBtu), by means of the data
acquisition and handling system, during the time period of the test run. Tabulate the results as shown in example
Figure 4.
7.4.3 Relative Accuracy
Use the equations and procedures in section 7.3 above to calculate the relative accuracy for the NOX continuous
emission monitoring system. In using equation A-7, “d” is, for each run, the difference between the NOX emission
rate values (in lb/mmBtu) obtained from the reference method data and the NOX continuous emission monitoring
system.
7.5 Relative Accuracy for Combined SO2/Flow [Reserved]
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 6.5(b)
40 CFR Appendix-A-to-Part-75 6.5(b) (enhanced display)page 48 of 59
7.6 Bias Test and Adjustment Factor
Test the following relative accuracy test audit data sets for bias: SO2 pollutant concentration monitors; flow
monitors; NOX concentration monitoring systems used to determine NOX mass emissions, as defined in 75.71(a)(2);
and NOX-diluent CEMS using the procedures outlined in sections 7.6.1 through 7.6.5 of this appendix. For multiple-
load flow RATAs, perform a bias test at each load level designated as normal under section 6.5.2.1 of this appendix.
7.6.1 Arithmetic Mean
Calculate the arithmetic mean of the differences of the data set using Equation A-7 of this appendix. To calculate
bias for an SO2 or NOX pollutant concentration monitor, “di” is, for each paired data point, the difference between the
SO2 or NOX concentration value (in ppm) obtained from the reference method and the monitor. To calculate bias for
a flow monitor, “di” is, for each paired data point, the difference between the flow rate values (in scfh) obtained from
the reference method and the monitor. To calculate bias for a NOX-diluent continuous emission monitoring system,
“di” is, for each paired data point, the difference between the NOX emission rate values (in lb/mmBtu) obtained from
the reference method and the monitoring system.
7.6.2 Standard Deviation
Calculate the standard deviation, Sd, of the data set using equation A-8.
7.6.3 Confidence Coefficient
Calculate the confidence coefficient, cc, of the data set using equation A-9.
7.6.4 Bias Test
If, for the relative accuracy test audit data set being tested, the mean difference, d̄, is less than or equal to the
absolute value of the confidence coefficient, | cc |, the monitor or monitoring system has passed the bias test. If the
mean difference, d̄, is greater than the absolute value of the confidence coefficient, √ cc √, the monitor or monitoring
system has failed to meet the bias test requirement.
7.6.5 Bias Adjustment
Where:
CEMiMonitor = Data (measurement) provided by the monitor at time i.
CEMiAdjusted = Data value, adjusted for bias, at time i.
(a)If the monitor or monitoring system fails to meet the bias test requirement, adjust the
value obtained from the monitor using the following equation:
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 7.6.5(a)
40 CFR Appendix-A-to-Part-75 7.6.5(a) (enhanced display)page 49 of 59
BAF = Bias adjustment factor, defined by:
Where:
BAF = Bias adjustment factor, calculated to the nearest thousandth.
d̄= Arithmetic mean of the difference obtained during the failed bias test using Equation A-7.
CEMavg = Mean of the data values provided by the monitor during the failed bias test.
(b)For single-load RATAs of SO2 pollutant concentration monitors, NOX concentration
monitoring systems, and NOX-diluent monitoring systems, and for the single-load flow
RATAs required or allowed under section 6.5.2 of this appendix and sections 2.3.1.3(b)
and 2.3.1.3(c) of appendix B to this part, the appropriate BAF is determined directly from
the RATA results at normal load, using Equation A-12. Notwithstanding, when a NOX
concentration CEMS or an SO2 CEMS or a NOX-diluent CEMS installed on a low-emitting
affected unit (i.e.,average SO2 or NOX concentration during the RATA ≤250 ppm or
average NOX emission rate ≤0.200 lb/mmBtu) meets the normal 10.0 percent relative
accuracy specification (as calculated using Equation A-10) or the alternate relative
accuracy specification in section 3.3 of this appendix for low-emitters, but fails the bias
test, the BAF may either be determined using Equation A-12, or a default BAF of 1.111 may
be used.
(c)For 2-load or 3-load flow RATAs, when only one load level (low, mid or high) has been
designated as normal under section 6.5.2.1 of this appendix and the bias test is passed at
the normal load level, apply a BAF of 1.000 to the subsequent flow rate data. If the bias
test is failed at the normal load level, use Equation A-12 to calculate the normal load BAF
and then perform an additional bias test at the second most frequently-used load level, as
determined under section 6.5.2.1 of this appendix. If the bias test is passed at this second
load level, apply the normal load BAF to the subsequent flow rate data. If the bias test is
failed at this second load level, use Equation A-12 to calculate the BAF at the second load
level and apply the higher of the two BAFs (either from the normal load level or from the
second load level) to the subsequent flow rate data.
(d)For 2-load or 3-load flow RATAs, when two load levels have been designated as normal
under section 6.5.2.1 of this appendix and the bias test is passed at both normal load
levels, apply a BAF of 1.000 to the subsequent flow rate data. If the bias test is failed at
one of the normal load levels but not at the other, use Equation A-12 to calculate the BAF
for the normal load level at which the bias test was failed and apply that BAF to the
subsequent flow rate data. If the bias test is failed at both designated normal load levels,
use Equation A-12 to calculate the BAF at each normal load level and apply the higher of
the two BAFs to the subsequent flow rate data.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 7.6.5(b)
40 CFR Appendix-A-to-Part-75 7.6.5(d) (enhanced display)page 50 of 59
7.7 Reference Flow-to-Load Ratio or Gross Heat Rate
Where:
Rref = Reference value of the flow-to-load ratio, from the most recent normal-load flow RATA, scfh/megawatts, scfh/
1000 lb/hr of steam, or scfh/(mmBtu/hr of steam output).
Qref = Average stack gas volumetric flow rate measured by the reference method during the normal-load RATA, scfh.
Lavg = Average unit load during the normal-load flow RATA, megawatts, 1000 lb/hr of steam, or mmBtu/hr of thermal
output.
(e)Each time a RATA is passed and the appropriate bias adjustment factor has been
determined, apply the BAF prospectively to all monitoring system data, beginning with the
first clock hour following the hour in which the RATA was completed. For a 2-load flow
RATA, the “hour in which the RATA was completed” refers to the hour in which the testing
at both loads was completed; for a 3-load RATA, it refers to the hour in which the testing at
all three loads was completed.
(f)Use the bias-adjusted values in computing substitution values in the missing data
procedure, as specified in subpart D of this part, and in reporting the concentration of SO2,
the flow rate, the average NOX emission rate, the unit heat input, and the calculated mass
emissions of SO2 and CO2 during the quarter and calendar year, as specified in subpart G
of this part. In addition, when using a NOX concentration monitoring system and a flow
monitor to calculate NOX mass emissions under subpart H of this part, use bias-adjusted
values for NOX concentration and flow rate in the mass emission calculations and use
bias-adjusted NOX concentrations to compute the appropriate substitution values for NOX
concentration in the missing data routines under subpart D of this part.
(g)For units that do not produce electrical or thermal output, the provisions of paragraphs (a)
through (f)of this section apply, except that the terms, “single-load”, “2-load”, “3-load”, and
“load level” shall be replaced, respectively, with the terms, “single-level”, “2-level”, “3-level”,
and “operating level”.
(a)Except as provided in section 7.8 of this appendix, the owner or operator shall determine Rref,
the reference value of the ratio of flow rate to unit load, each time that a passing flow RATA is
performed at a load level designated as normal in section 6.5.2.1 of this appendix. The owner
or operator shall report the current value of Rref in the electronic quarterly report required under
§ 75.64 and shall also report the completion date of the associated RATA. If two load levels
have been designated as normal under section 6.5.2.1 of this appendix, the owner or operator
shall determine a separate Rref value for each of the normal load levels. The reference flow-to-
load ratio shall be calculated as follows:
(b)In Equation A-13, for a common stack, determine Lavg by summing, for each RATA run, the
operating loads of all units discharging through the common stack, and then taking the
arithmetic average of the summed loads. For a unit that discharges its emissions through
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 7.6.5(e)
40 CFR Appendix-A-to-Part-75 7.7(b) (enhanced display)page 51 of 59
Where:
(GHR)ref = Reference value of the gross heat rate at the time of the most recent normal-load flow RATA, Btu/kwh,
Btu/lb steam load, or Btu heat input/mmBtu steam output.
(Heat Input)avg = Average hourly heat input during the normal-load flow RATA, as determined using the applicable
equation in appendix F to this part, mmBtu/hr. For multiple stack configurations, if the reference GHR value is
determined separately for each stack, use the hourly heat input measured at each stack. If the reference GHR is
determined at the unit level, sum the hourly heat inputs measured at the individual stacks.
Lavg = Average unit load during the normal-load flow RATA, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal
output.
7.8 Flow-to-Load Test Exemptions
multiple stacks, either determine a single value of Qref for the unit or a separate value of Qref for
each stack. In the former case, calculate Qref by summing, for each RATA run, the volumetric
flow rates through the individual stacks and then taking the arithmetic average of the summed
RATA run flow rates. In the latter case, calculate the value of Qref for each stack by taking the
arithmetic average, for all RATA runs, of the flow rates through the stack. For a unit with a
multiple stack discharge configuration consisting of a main stack and a bypass stack (e.g., a
unit with a wet SO2 scrubber), determine Qref separately for each stack at the time of the
normal load flow RATA. Round off the value of Rref to two decimal places.
(c)In addition to determining Rref or as an alternative to determining Rref, a reference value of the
gross heat rate (GHR) may be determined. In order to use this option, quality-assured diluent
gas (CO2 or O2) must be available for each hour of the most recent normal-load flow RATA. The
reference value of the GHR shall be determined as follows:
(d)In the calculation of (Heat Input)avg, use Qref, the average volumetric flow rate measured by the
reference method during the RATA, and use the average diluent gas concentration measured
during the flow RATA (i.e., the arithmetic average of the diluent gas concentrations for all clock
hours in which a RATA run was performed).
(a)For complex stack configuations (e.g., when the effluent from a unit is divided and discharges
through multiple stacks in such a manner that the flow rate in the individual stacks cannot be
correlated with unit load), the owner or operator may petition the Administrator under § 75.66
for an exemption from the requirements of section 7.7 of this appendix and section 2.2.5 fo
appendix B to this part. The petition must include sufficient information and data to
demonstrate that a flow-to-load or gross heat rate evaluation is infeasible for the complex stack
configuration.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 7.7(c)
40 CFR Appendix-A-to-Part-75 7.8(a) (enhanced display)page 52 of 59
FIGURE 1 TO APPENDIX A—LINEARITY ERROR DETERMINATION
Day Date and
time
Reference
value
Monitor
value Difference Percent of reference
value
Low-level:
Mid-level:
High-
level:
(b)Units that do not produce electrical output (in megawatts) or thermal output (in klb of steam
per hour) are exempted from the flow-to-load ratio test requirements of section 7.7 of this
appendix and section 2.2.5 of appendix B to this part.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 7.8(b)
40 CFR Appendix-A-to-Part-75 7.8(b) (enhanced display)page 53 of 59
FIGURE 2 TO APPENDIX A—RELATIVE ACCURACY DETERMINATION (POLLUTANT CONCENTRATION MONITORS)
Run No.Date and time SO2 (ppmc)Date and time CO2 (Pollutant) (ppmc)
RMa Mb Diff RMa Mb Diff
1
2
3
4
5
6
7
8
9
10
11
12
Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative Accuracy (Eq. A-10).
a RM means “reference method data.”
b M means “monitor data.”
c Make sure the RM and M data are on a consistent basis, either wet or dry.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 7.8(b)
40 CFR Appendix-A-to-Part-75 7.8(b) (enhanced display)page 54 of 59
FIGURE 3 TO APPENDIX A—RELATIVE ACCURACY DETERMINATION (FLOW MONITORS)
Run No.Date and time Flow rate (Low) (scf/hr)*Date and time Flow rate (Normal) (scf/hr)*Date and time Flow rate (High) (scf/hr)*
RM M Diff RM M Diff RM M Diff
1
2
3
4
5
6
7
8
9
10
11
12
Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative Accuracy (Eq. A-10).
* Make sure the RM and M data are on a consistent basis, either wet or dry.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 7.8(b)
40 CFR Appendix-A-to-Part-75 7.8(b) (enhanced display)page 55 of 59
FIGURE 4 TO APPENDIX A—RELATIVE ACCURACY DETERMINATION (NOX/DILUENT
COMBINED SYSTEM)
Run No.Date and time Reference method data NOX system (lb/
mmBtu)
NOX ( )a O2/CO2%RM M Difference
1
2
3
4
5
6
7
8
9
10
11
12
Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9).
Relative Accuracy (Eq. A-10).
a Specify units: ppm, lb/dscf, mg/dscm.
Figure 5—Cycle Time
Date of test
Component/system ID#:
Analyzer type
Serial Number
High level gas concentration: ______ ppm/% (circle one)
Zero level gas concentration: ______ ppm/% (circle one)
Analyzer span setting: ______ ppm/% (circle one)
Upscale:
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 7.8(b)
40 CFR Appendix-A-to-Part-75 7.8(b) (enhanced display)page 56 of 59
Stable starting monitor value: ______ ppm/% (circle one)
Stable ending monitor reading: ______ ppm/% (circle one)
Elapsed time: ______ seconds
Downscale:
Stable starting monitor value: ______ ppm/% (circle one)
Stable ending monitor value: ______ ppm/% (circle one)
Elapsed time: ______ seconds
Component cycle time= ______ seconds
System cycle time= ______ seconds
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 7.8(b)
40 CFR Appendix-A-to-Part-75 7.8(b) (enhanced display)page 57 of 59
A.To determine the upscale cycle time (Figure 6a), measure the flue gas emissions until the response
stabilizes. Record the stabilized value (see section 6.4 of this appendix for the stability criteria).
B.Inject a high-level calibration gas into the port leading to the calibration cell or thimble (Point B). Allow the
analyzer to stabilize. Record the stabilized value.
C.Determine the step change. The step change is equal to the difference between the final stable calibration
gas value (Point D) and the stabilized stack emissions value (Point A).
D.Take 95% of the step change value and add the result to the stabilized stack emissions value (Point A).
Determine the time at which 95% of the step change occurred (Point C).
E.Calculate the upscale cycle time by subtracting the time at which the calibration gas was injected (Point
B) from the time at which 95% of the step change occurred (Point C). In this example, upscale cycle time
= (11−5) = 6 minutes.
F.To determine the downscale cycle time (Figure 6b) repeat the procedures above, except that a zero gas is
injected when the flue gas emissions have stabilized, and 95% of the step change in concentration is
subtracted from the stabilized stack emissions value.
G.Compare the upscale and downscale cycle time values. The longer of these two times is the cycle time for
the analyzer.
Editorial Note:For FEDERAL REGISTER citations affecting part 75, Appendix A, see the List of CFR Sections
Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 A.
40 CFR Appendix-A-to-Part-75 G. (enhanced display)page 58 of 59
Appendix A to Part 75, Title 40 (up to date as of 3/27/2025)
Specifications and Test Procedures 40 CFR Appendix-A-to-Part-75 G.
40 CFR Appendix-A-to-Part-75 G. (enhanced display)page 59 of 59

Site Specific Test Plan
Intermountain Power Service Corporation
850 West Brush Wellman Road
Delta, UT 84624-9546

Source to be Tested: HRSG Stacks 3 & 4 Proposed Test Dates: June 18 & 19, 2025 Project No. AST-2025-2058

Prepared By Alliance Technical Group, LLC 3683 W 2270 S, Suite E West Valley City, UT 84120
Site Specific Test Plan
Test Program Summary
AST-2025-2058 Mitsubishi – Delta, UT Page i
Regulatory Information
Permit No.
Regulatory Citation
DAQE-AN103270030-22
40 CFR 75, Appendices A & B
40 CFR 60 4B
Source Information
Source Name Target Parameters HRSG Stacks 3 & 4 O2, NOx, CO
Contact Information
Test Location Test Company
Intermountain Power Service Corporation
850 West Brush Wellman Road
Delta, UT 84624-9546
Facility Contact
Trevor Johnson
[e-mail]
[phone]
Environmental / RATA Coordinator
Mike Ultey PE JD
[phone]
Alliance Technical Group, LLC
3683 W 2270 S, Suite E
West Valley City, UT 84120
Project Manager
Charles Horton
[e-mail]
[phone]
Field Team Leader
Ryan Lyons
[e-mail]
[phone]
(subject to change)
QA/QC Manager
Kathleen Shonk
[e-mail]
[phone]
Test Plan/Report Coordinator
Delaine Spangler
[e-mail]

Site Specific Test Plan
Table of Contents

AST-2025-2058 Mitsubishi – Delta, UT Page ii
TABLE OF CONTENTS 1.0 Introduction ................................................................................................................................................. 1-1
1.1 Facility Descriptions ................................................................................................................................... 1-1
1.2 CEMS Descriptions ..................................................................................................................................... 1-1
1.3 Project Team ............................................................................................................................................... 1-1
1.4 Safety Requirements ................................................................................................................................... 1-2
2.0 Summary of Test Program .......................................................................................................................... 2-1
2.1 General Description ..................................................................................................................................... 2-1
2.2 Process/Control System Parameters to be Monitored and Recorded .......................................................... 2-1
2.3 Proposed Test Schedule............................................................................................................................... 2-1
2.4 Test Report .................................................................................................................................................. 2-3
3.0 Testing Methodology .................................................................................................................................. 3-1
3.1 U.S. EPA Reference Test Method 3A – Oxygen/Carbon Dioxide .............................................................. 3-1
3.2 U.S. EPA Reference Test Method 7E – Nitrogen Oxides ........................................................................... 3-1
3.3 U.S. EPA Reference Test Method 10 – Carbon Monoxide ......................................................................... 3-2
3.4 U.S. EPA Reference Test Method 19 – Mass Emission Factors ................................................................. 3-2
3.5 Quality Assurance/Quality Control – U.S. EPA Reference Test Methods 3A, 7E and 10 .......................... 3-2
4.0 Quality Assurance Program ......................................................................................................................... 4-1
4.1 Equipment ................................................................................................................................................... 4-1
4.2 Field Sampling ............................................................................................................................................ 4-2
LIST OF TABLES Table 1-1: Test Matrix ............................................................................................................................................... 1-1
Table 1-2: Project Team ........................................................................................................................................... 1-1
Table 2-1: Program Outline and Tentative Test Schedule ........................................................................................ 2-2
Table 2-3: Relative Accuracy Requirements and Limits .......................................................................................... 2-2
Table 3-1: Source Testing Methodology .................................................................................................................. 3-1
LIST OF APPENDICES
Appendix A Method 1 Data
Appendix B Example Field Data Sheets

Site Specific Test Plan
Introduction
AST-2025-2058 Mitsubishi – Delta, UT Page 1-1
1.0 Introduction
Alliance Technical Group, LLC (Alliance) was retained by Mitsubishi to conduct CEMS installations at the
Intermountain Power Service Corporation facility in Delta, Utah. Portions of the facility are subject to provisions
of the Utah Department of Environmental Quality Division of Air Quality (UDAQ) Permit Number
AN103270030-22, 40 CFR 60 4B, and 40 CFR 75, Appendices A & B. Testing will be conducted as outlined in
Table 1-1 below.
Table 1-1: Test Matrix
CEMS Parameters
HRSG Stacks 3 & 4 Oxygen (O2), Nitrogen Oxides (NOx), Carbon
Monoxide (CO)
This site-specific test plan (SSTP) has been prepared to address the notification and testing requirements of the
UDAQ permit and the NESHAP.
1.1 Facility Descriptions
Intermountain Power Project Corporation (IPSC) owns and operates the IPP Renewed Project Located at 850 West
Brush Wellman Road in Delta, Utah. The interest of this test protocol are the two combined cycle combustion
turbines, Unit 3SGA and Unit 4SGA.
The stacks are circular and measure 23.2 feet (ft) (278 inches) in diameter at the 4, 6” test ports which are
approximately 174 ft above grade level with an exit elevation of approximately 186 ft above grade level. The test
ports are located approximately 91.5 ft (1098 inches) [3.9 dia] downstream and approximately 12 ft (144 inches)
[0.5 dia] upstream from the nearest disturbances.
1.2 CEMS Descriptions
Unit 3
Pollutant Pollutant Pollutant Pollutant
Parameter: NOx NH3, NOx CO – High CO – Low
Make: 42iQ 42iQ 48iQ 48iQ
Serial No.: 12127713452 12127713453 12208416648 12208416650
Span:
0 – 10 ppm
0 – 150 ppm
0 – 20 ppm 0 – 4000 ppm 0 – 10 ppm
Unit 4
Pollutant Pollutant Pollutant Pollutant
Parameter: NOx NH3, NOx CO – High CO – Low
Make: 42iQ 42iQ 48iQ 48iQ
Serial No.: 12127713454 12127713455 12208416649 12208416651
Span:
0 – 10 ppm 0 – 150 ppm 0 – 20 ppm 0 – 4000 ppm 0 – 10 ppm
1.3 Project Team
Personnel planned to be involved in this project are identified in the following table.
Table 1-2: Project Team
Site Specific Test Plan
Introduction
AST-2025-2058 Mitsubishi – Delta, UT Page 1-2
Mitsubishi Personnel Alan Phillips
Regulatory Agency UDAQ
Alliance Personnel Ryan Lyons
other field personnel assigned at time of testing event
1.4 Safety Requirements
Testing personnel will undergo site-specific safety training for all applicable areas upon arrival at the site. Alliance
personnel will have current OSHA or MSHA safety training and be equipped with hard hats, safety glasses with side
shields, steel-toed safety shoes, hearing protection, fire resistant clothing, and fall protection (including shock
corded lanyards and full-body harnesses). Alliance personnel will conduct themselves in a manner consistent with
Client and Alliance’s safety policies.
A Job Safety Analysis (JSA) will be completed daily by the Alliance Field Team Leader.
Site Specific Test Plan
Summary of Test Programs
AST-2025-2058 Mitsubishi – Delta, UT Page 2-1
2.0 Summary of Test Program
To satisfy the requirements of the UDAQ permit and the NESHAP, the facility will conduct a performance test
program to determine the compliance status of the HRSG Stacks 3 & 4.
2.1 General Description
All testing will be performed in accordance with specifications stipulated in U.S. EPA Reference Test Methods 3A,
7E, 10, and 19. Table 2-1 presents an outline and tentative schedule for the emissions testing program. The
following is a summary of the test objectives.
•Testing will be performed to demonstrate compliance with the UDAQ permit 40 CFR 75 Appendices A &
B.
•Emissions testing will be conducted on the exhaust of HRSG Stacks 3 & 4.
•Performance testing will be conducted at the maximum normal operation load for each source.
•Each of the 9 – 12 test runs will be approximately 21 minutes in duration.
2.2 Process/Control System Parameters to be Monitored and Recorded
Plant personnel will collect operational and parametric data at least once every 15 minutes during the testing. The
following list identifies the measurements, observations and records that will be collected during the testing
program:
•CEMS
2.3 Proposed Test Schedule
Table 2-1 presents an outline and tentative schedule for the emissions testing program.
Site Specific Test Plan
Summary of Test Programs
AST-2025-2058 Mitsubishi – Delta, UT Page 2-2
Table 2-1: Program Outline and Tentative Test Schedule
Testing Location Parameter US EPA Method No. of Runs Run Duration Est. Onsite Time
DAY 1 – June 17, 2025
Equipment Setup & Pretest QA/QC Checks 4 hr
DAY 2 – June 18, 2025
HRSG Stack 3
O2/CO2 3A
9-12 21 min 8 hr NOx 7E
CO 10
EF 19
DAY 3 – June 19, 2025
HRSG Stack 4
O2/CO2 3A
9-12 21 min 8 hr NOx 7E
CO 10
EF 19
DAY 4 – June 20, 2025
Contingency Day (if needed)
Table 2-3: Relative Accuracy Requirements and Limits
Source CEMS Required Relative
Accuracy
Applicable Standard /
Limit Citation
HRSG
Stacks
3 & 4
O2 ≤10 % (RM) or < 1% mean
difference -- Part 75, Appendix A
NOx ≤7.5 % (RM) or
± 0.015 lb/MMBtu -- Part 75, Appendix A
CO ≤10% RA or 5% of emission
standard, or ± 5 ppm 2.0 ppmvd @ 15% O2 Part 60 4B
Site Specific Test Plan
Summary of Test Programs
AST-2025-2058 Mitsubishi – Delta, UT Page 2-3
2.4 Test Report
The final test report must be submitted within 60 days of the completion of the performance test and will include the
following information.
•Introduction – Brief discussion of project scope of work and activities.
•Results and Discussion – A summary of test results and process/control system operational data with
comparison to regulatory requirements or vendor guarantees along with a description of process conditions
and/or testing deviations that may have affected the testing results.
•Methodology – A description of the sampling and analytical methodologies.
•Sample Calculations – Example calculations for each target parameter.
•Field Data – Copies of actual handwritten or electronic field data sheets.
•Quality Control Data – Copies of all instrument calibration data and/or calibration gas certificates.
•Process Operating/Control System Data – Process operating and control system data (as provided by
Mitsubishi) to support the test results.
Site Specific Test Plan
Testing Methodology
AST-2025-2058 Mitsubishi – Delta, UT Page 3-1
3.0 Testing Methodology
This section provides a description of the sampling and analytical procedures for each test method that will be
employed during the test program. All equipment, procedures and quality assurance measures necessary for the
completion of the test program meet or exceed the specifications of each relevant test method. The emission testing
program will be conducted in accordance with the test methods listed in Table 3-1.
Table 3-1: Source Testing Methodology
Parameter U.S. EPA Reference Test Methods Notes/Remarks
Oxygen/Carbon Dioxide 3A Instrumental Analysis
Nitrogen Oxides 7E Instrumental Analysis
Carbon Monoxide 10 Instrumental Analysis
Mass Emission Factors 19 Fuel Factors/Heat Inputs
All stack diameters, depths, widths, upstream and downstream disturbance distances and nipple lengths will be
measured on site with an EPA Method 1 verification measurement provided by the Field Team Leader. These
measurements will be included in the test report.
3.1 U.S. EPA Reference Test Method 3A – Oxygen/Carbon Dioxide
The oxygen (O2) and carbon dioxide (CO2) testing will be conducted in accordance with U.S. EPA Reference Test
Method 3A. Data will be collected online and reported in one-minute averages. The sampling system will consist
of a stainless steel probe, Teflon sample line(s), gas conditioning system and the identified gas analyzer. The gas
conditioning system will be a non-contact condenser used to remove moisture from the stack gas. If an unheated
Teflon sample line is used, then a portable non-contact condenser will be placed in the system directly after the
probe. Otherwise, a heated Teflon sample line will be used. The quality control measures are described in Section
3.5.
The relative accuracy of the O2 CEMS will be determined based on procedures found in 40 CFR 75, Appendices A
& B.
3.2 U.S. EPA Reference Test Method 7E – Nitrogen Oxides
The nitrogen oxides (NOx) testing will be conducted in accordance with U.S. EPA Reference Test Method 7E. Data
will be collected online and reported in one-minute averages. The sampling system will consist of a stainless steel
probe, Teflon sample line(s), gas conditioning system and the identified gas analyzer. The gas conditioning system
will be a non-contact condenser used to remove moisture from the stack gas. If an unheated Teflon sample line is
used, then a portable non-contact condenser will be placed in the system directly after the probe. Otherwise, a
heated Teflon sample line will be used. The quality control measures are described in Section 3.5.
The relative accuracy of the NOx CEMS will be determined based on procedures found in 40 CFR 75, Appendices
A & B.

Site Specific Test Plan
Testing Methodology

AST-2025-2058 Mitsubishi – Delta, UT Page 3-2
3.3 U.S. EPA Reference Test Method 10 – Carbon Monoxide
The carbon monoxide (CO) testing will be conducted in accordance with U.S. EPA Reference Test Method 10.
Data will be collected online and reported in one-minute averages. The sampling system will consist of a stainless
steel probe, Teflon sample line(s), gas conditioning system, and the identified gas analyzer. The gas conditioning
system will be a non-contact condenser used to remove moisture from the gas. If an unheated Teflon sample line is
used, then a portable non-contact condenser will be placed in the system directly after the probe. Otherwise, a
heated Teflon sample line will be used. The quality control measures are described in Section 3.5.

The relative accuracy of the CO CEMS will be determined based on procedures found in 40 CFR 60 Part 4B and 40
CFR 75, Appendices A & B.
3.4 U.S. EPA Reference Test Method 19 – Mass Emission Factors
The pollutant concentrations will be converted to mass emission factors (lb/MMBtu) using procedures outlined in
U.S. EPA Reference Test Method 19. The published dry O2, wet O2 or CO2 based fuel factor (F-Factor) of 8,710
dscf/MMBtu for natural gas will be used in the calculations.
3.5 Quality Assurance/Quality Control – U.S. EPA Reference Test Methods 3A, 7E and 10
Cylinder calibration gases will meet EPA Protocol 1 (+/- 2%) standards. Copies of all calibration gas certificates
will be included in the Quality Assurance/Quality Control Appendix of the report.

Low Level gas will be introduced directly to the analyzer. After adjusting the analyzer to the Low-Level gas
concentration and once the analyzer reading is stable, the analyzer value will be recorded. This process will be
repeated for the High-Level gas. For the Calibration Error Test, Low, Mid, and High-Level calibration gases will be
sequentially introduced directly to the analyzer. The Calibration Error for each gas must be within 2.0 percent of the
Calibration Span or 0.5 ppmv/% absolute difference.

High or Mid-Level gas (whichever is closer to the stack gas concentration) will be introduced at the probe and the
time required for the analyzer reading to reach 95 percent or 0.5 ppm/% (whichever was less restrictive) of the gas
concentration will be recorded. The analyzer reading will be observed until it reaches a stable value, and this value
will be recorded. Next, Low-Level gas will be introduced at the probe and the time required for the analyzer reading
to decrease to a value within 5.0 percent or 0.5 ppm/% (whichever was less restrictive) will be recorded. If the Low-
Level gas is zero gas, the acceptable response must be 5.0 percent of the upscale gas concentration or 0.5 ppm/%
(whichever was less restrictive). The analyzer reading will be observed until it reaches a stable value, and this value
will be recorded. The measurement system response time and initial system bias will be determined from these data.
The System Bias for each gas must be within 5.0 percent of the Calibration Span or 0.5 ppmv/% absolute difference.

High or Mid-Level gas (whichever is closer to the stack gas concentration) will be introduced at the probe. After the
analyzer response is stable, the value will be recorded. Next, Low-Level gas will be introduced at the probe, and the
analyzer value will be recorded once it reaches a stable response. The System Bias for each gas must be within 5.0
percent of the Calibration Span or 0.5 ppmv/% absolute difference or the data is invalidated, and the Calibration
Error Test and System Bias must be repeated.

The Drift between pre- and post-run System Bias must be within 3 percent of the Calibration Span or 0.5 ppmv/%
absolute difference or the Calibration Error Test and System Bias must be repeated.

Site Specific Test Plan
Testing Methodology

AST-2025-2058 Mitsubishi – Delta, UT Page 3-3
To determine the number of sampling points, a gas stratification check will be conducted prior to initiating testing.
The pollutant concentrations will be measured at twelve traverse points (as described in Method 1) or three points
(16.7, 50.0 and 83.3 percent of the measurement line). Each traverse point will be sampled for a minimum of twice
the system response time.

If the pollutant concentration at each traverse point do not differ more than 5% or 0.5 ppm/0.3% (whichever is less
restrictive) of the average pollutant concentration, then single point sampling will be conducted during the test runs.
If the pollutant concentration does not meet these specifications but differs less than 10% or 1.0 ppm/0.5% from the
average concentration, then three (3) point sampling will be conducted (stacks less than 7.8 feet in diameter - 16.7,
50.0 and 83.3 percent of the measurement line; stacks greater than 7.8 feet in diameter – 0.4, 1.0, and 2.0 meters
from the stack wall). If the pollutant concentration differs by more than 10% or 1.0 ppm/0.5% from the average
concentration, then sampling will be conducted at a minimum of twelve (12) traverse points. Copies of stratification
check data will be included in the Quality Assurance/Quality Control Appendix of the report.

An NO2 – NO converter check will be performed on the analyzer prior to initiating testing or at the completion of
testing. An approximately 50 ppm nitrogen dioxide cylinder gas will be introduced directly to the NOx analyzer and
the instrument response will be recorded in an electronic data sheet. The instrument response must be within +/- 10
percent of the cylinder concentration.

A Data Acquisition System with battery backup will be used to record the instrument response in one (1) minute
averages. The data will be continuously stored as a *.CSV file in Excel format on the hard drive of a computer. At
the completion of testing, the data will also be saved to the Alliance server. All data will be reviewed by the Field
Team Leader before leaving the facility. Once arriving at Alliance’s office, all written and electronic data will be
relinquished to the report coordinator and then a final review will be performed by the Project Manager.

Site Specific Test Plan
Quality Assurance Program

AST-2025-2058 Mitsubishi – Delta, UT Page 4-1
4.0 Quality Assurance Program
Alliance follows the procedures outlined in the Quality Assurance/Quality Control Management Plan to ensure the
continuous production of useful and valid data throughout the course of this test program. The QC checks and
procedures described in this section represent an integral part of the overall sampling and analytical scheme.
Adherence to prescribed procedures is quite often the most applicable QC check.
4.1 Equipment
Field test equipment is assigned a unique, permanent identification number. Prior to mobilizing for the test
program, equipment is inspected before being packed to detect equipment problems prior to arriving on site. This
minimizes lost time on the job site due to equipment failure. Occasional equipment failure in the field is
unavoidable despite the most rigorous inspection and maintenance procedures. Therefore, replacements for critical
equipment or components are brought to the job site. Equipment returning from the field is inspected before it is
returned to storage. During the course of these inspections, items are cleaned, repaired, reconditioned and
recalibrated where necessary.

Calibrations are conducted in a manner, and at a frequency, which meets or exceeds U.S. EPA specifications. The
calibration procedures outlined in the U.S. EPA Methods, and those recommended within the Quality Assurance
Handbook for Air Pollution Measurement Systems: Volume III (EPA-600/R-94/038c, September 1994) are utilized.
When these methods are inapplicable, methods such as those prescribed by the American Society for Testing and
Materials (ASTM) or other nationally recognized agency may be used. Data obtained during calibrations is checked
for completeness and accuracy. Copies of calibration forms are included in the report.

The following sections elaborate on the calibration procedures followed by Alliance for these items of equipment.

• Dry Gas Meter and Orifice. A full meter calibration using critical orifices as the calibration standard is
conducted at least semi-annually, more frequently if required. The meter calibration procedure determines
the meter correction factor (Y) and the meter’s orifice pressure differential (ΔH@). Alliance uses approved
Alternative Method 009 as a post-test calibration check to ensure that the correction factor has not changed
more than 5% since the last full meter calibration. This check is performed after each test series.
• Pitot Tubes and Manometers. Type-S pitot tubes that meet the geometric criteria required by U.S. EPA
Reference Test Method 2 are assigned a coefficient of 0.84 unless a specific coefficient has been
determined from a wind tunnel calibration. If a specific coefficient from a wind tunnel calibration has been
obtained that coefficient will be used in lieu of 0.84. Standard pitot tubes that meet the geometric criteria
required by U.S. EPA Reference Test Method 2 are assigned a coefficient of 0.99. Any pitot tubes not
meeting the appropriate geometric criteria are discarded and replaced. Manometers are verified to be level
and zeroed prior to each test run and do not require further calibration.
• Temperature Measuring Devices. All thermocouple sensors mounted in Dry Gas Meter Consoles are
calibrated semi-annually with a NIST-traceable thermocouple calibrator (temperature simulator) and
verified during field use using a second NIST-traceable meter. NIST-traceable thermocouple calibrators
are calibrated annually by an outside laboratory.
• Nozzles. Nozzles are measured three (3) times prior to initiating sampling with a caliper. The maximum
difference between any two (2) dimensions is 0.004 in.
• Digital Calipers. Calipers are calibrated annually by Alliance by using gage blocks that are calibrated
annually by an outside laboratory.

Site Specific Test Plan
Quality Assurance Program

AST-2025-2058 Mitsubishi – Delta, UT Page 4-2
• Barometer. The barometric pressure is obtained from a nationally recognized agency or a calibrated
barometer. Calibrated barometers are checked prior to each field trip against a mercury barometer. The
barometer is acceptable if the values agree within ± 2 percent absolute. Barometers not meeting this
requirement are adjusted or taken out of service.
• Balances and Weights. Balances are calibrated annually by an outside laboratory. A functional check is
conducted on the balance each day it is used in the field using a calibration weight. Weights are re-certified
every two (2) years by an outside laboratory or internally. If conducted internally, they are weighed on a
NIST traceable balance. If the weight does not meet the expected criteria, they are replaced.
• Other Equipment. A mass flow controller calibration is conducted on each Environics system annually
following the procedures in the Manufacturer’s Operation manual. A methane/ethane penetration factor
check is conducted on the total hydrocarbon analyzers equipped with non-methane cutters every six (6)
months following the procedures in 40 CFR 60, Subpart JJJJ. Other equipment such as probes, umbilical
lines, cold boxes, etc. are routinely maintained and inspected to ensure that they are in good working order.
They are repaired or replaced as needed.
4.2 Field Sampling
Field sampling will be done in accordance with the Standard Operating Procedures (SOP) for the applicable test
method(s). General QC measures for the test program include:
• Cleaned glassware and sample train components will be sealed until assembly.
• Sample trains will be leak checked before and after each test run.
• Appropriate probe, filter and impinger temperatures will be maintained.
• The sampling port will be sealed to prevent air from leaking from the port.
• Dry gas meter, ΔP, ΔH, temperature and pump vacuum data will be recorded during each sample point.
• An isokinetic sampling rate of 90-110% will be maintained, as applicable.
• All raw data will be maintained in an organized manner.
• All raw data will be reviewed on a daily basis for completeness and acceptability.

Appendix A

Method 1 Data
Location
Source
Vertical
Circular
TBD in
TBD in
277.50 in
420.00 ft2
4
--
12.0 ft
0.5 (must be ≥ 0.5)
14.0 ft
0.6 (must be ≥ 2)
3
2 3 4 5 6 7 8 9 10 11 12
1 14.6 16.7 6.7 -- 4.4 -- 3.2 -- 2.6 -- 2.1 1 16.7 46.34
2 85.4 50.0 25.0 -- 14.6 -- 10.5 -- 8.2 -- 6.7 2 50.0 138.75
3 -- 83.3 75.0 -- 29.6 -- 19.4 -- 14.6 -- 11.8 3 83.3 231.16
4 -- -- 93.3 -- 70.4 -- 32.3 -- 22.6 -- 17.7 4 -- --
5 -- -- -- -- 85.4 -- 67.7 -- 34.2 -- 25.0 5 -- --
6 -- -- -- -- 95.6 -- 80.6 -- 65.8 -- 35.6 6 -- --
7 -- -- -- -- -- -- 89.5 -- 77.4 -- 64.4 7 -- --
8 -- -- -- -- -- -- 96.8 -- 85.4 -- 75.0 8 -- --
9 -- -- -- -- -- -- -- -- 91.8 -- 82.3 9 -- --
10 -- -- -- -- -- -- -- -- 97.4 -- 88.2 10 -- --
11 -- -- -- -- -- -- -- -- -- -- 93.3 11 -- --
12 -- -- -- -- -- -- -- -- -- -- 97.9 12 -- --
*Percent of stack diameter from inside wall to traverse point.
A = 12 ft.
B = 14 ft.
Depth of Duct = 277.5 in.
Cross Sectional Area of Duct:
Intermountain Power, Delta, UT
Unit 3 and Unit 4
Stack Parameters
Duct Orientation:
Duct Design:
Distance from Far Wall to Outside of Port:
Nipple Length:
Depth of Duct:
No. of Test Ports:
Number of Readings per Point:
Distance A:
Distance A Duct Diameters:
Distance B:
Distance B Duct Diameters:
Actual Number of Traverse Points:
CIRCULAR DUCT
LOCATION OF TRAVERSE POINTS
Traverse
Point
% of
Diameter
Distance
from inside
wall
Number of traverse points on a diameter
Stack Diagram
Cross Sectional Area
Upstream Disturbance
Downstream Disturbance
B
A
Appendix B
O2 Summary
Location:
Source:
Project No.:
Load Reference Method CEMS Average
O2 Concentration O2 Concentration Difference
Start End MW % dry % dry % dry
1 - -- -- -- -- --
2 - -- -- -- -- --
3 - -- -- -- -- --
4 - -- -- -- -- --
5 - -- -- -- -- --
6 - -- -- -- -- --
7 - -- -- -- -- --
8 - -- -- -- -- --
9 - -- -- -- -- --
10 - -- -- -- -- --
11 - -- -- -- -- --
12 - -- -- -- -- --
No
1.000
-
Performance Required RA ≤ 7.5 % (4 QTRS)
--
4QTRS
Confidence Coefficient, CC
where,
t0.975 = degrees of freedom value
n 0 = number of runs selected for calculating the RA
Sd = standard deviation of difference
CC = confidence coefficient
Relative Accuracy, RA
where,
d = average difference of Reference Method and CEMS
CC = confidence coefficient
RM = reference method, % dry
RA = relative accuracy, %
Average
Bias Adjustment Factor (BAF)
Test Result
RATA Frequency
-
-
-
Run
No.Date Time
Standard Deviation (Sd)
Confidence Coefficient (CC)
Bias Adjustment Required (BA)
Relative Accuracy (RA)
CC = t଴.ଽ଻ହ
n × 𝑆d
RA = d +𝐶𝐶
𝑅𝑀× 100

CO2 Summary
Location:
Source:
Project No.:
Load Reference Method CEMS Average
CO2 Concentration CO2 Concentration Difference
Start End MW % wet % wet % wet
1 - -- -- -- -- --
2 - -- -- -- -- --
3 - -- -- -- -- --
4 - -- -- -- -- --
5 - -- -- -- -- --
6 - -- -- -- -- --
7 - -- -- -- -- --
8 - -- -- -- -- --
9 - -- -- -- -- --
10 - -- -- -- -- --
11 - -- -- -- -- --
12 - -- -- -- -- --
No
1.000
-
Performance Required RA ≤ 7.5 % (4 QTRS)
--
4QTRS
Confidence Coefficient, CC
where,
t0.975 = degrees of freedom value
n 0 = number of runs selected for calculating the RA
Sd = standard deviation of difference
CC = confidence coefficient
Relative Accuracy, RA
where,
d = average difference of Reference Method and CEMS
CC = confidence coefficient
RM = reference method, % wet
RA = relative accuracy, %
RATA Frequency
-
-
-
Bias Adjustment Factor (BAF)
Standard Deviation (Sd)
Confidence Coefficient (CC)
Bias Adjustment Required (BA)
Average
Run
No.Date Time
Test Result
Relative Accuracy (RA)
CC = t଴.ଽ଻ହ
n × 𝑆d
RA = d +𝐶𝐶
𝑅𝑀× 100

NOx Summary
Location:
Source:
Project No.:
Load Reference Method CEMS Average
NOx Emission Factor NOx Emission Factor Difference
Start End MW lb/MMBtu (CO2d) lb/MMBtu (CO2d) lb/MMBtu (CO2d)
1 - -- -- -- -- --
2 - -- -- -- -- --
3 - -- -- -- -- --
4 - -- -- -- -- --
5 - -- -- -- -- --
6 - -- -- -- -- --
7 - -- -- -- -- --
8 - -- -- -- -- --
9 - -- -- -- -- --
10 - -- -- -- -- --
11 - -- -- -- -- --
12 - -- -- -- -- --
No
1.000
-
RA ≤ 7.5 % (4 QTRS)
--
4QTRS
Confidence Coefficient, CC
where,
t0.975 = degrees of freedom value
n 0 = number of runs selected for calculating the RA
Sd = standard deviation of difference
CC = confidence coefficient
Relative Accuracy, RA
where,
d = average difference of Reference Method and CEMS
CC = confidence coefficient
RM = reference method, lb/MMBtu (CO2d)
RA = relative accuracy, %
Bias Test Results, BA
where,
d = average difference of Reference Method and CEMS
CC = confidence coefficient
BA No = bias adjustment factor
Bias Adjustment Factor, BAF
where,
d = average difference of Reference Method and CEMS
CEMSavg = average of CEMS values
BAF 1.000 = bias adjustment factor
-
-
-
Average
TimeRun
No.Date
Relative Accuracy (RA)
Test Result
RATA Frequency
Bias Adjustment Factor (BAF)
Performance Required
Standard Deviation (Sd)
Confidence Coefficient (CC)
Bias Adjustment Required (BA)
CC = t଴.ଽ଻ହ
n × 𝑆d
RA = d +𝐶𝐶
𝑅𝑀× 100
BARequired if d > CC
BAF = d
CEMSୟ୴୥
 +  1
Appendix A
Example Calculations
Location:
Source:
Project No.:
Run/Method:
Nitrogen Oxides Emission Factor (EFNOx O2d), lb/MMBtu
where,
CNOx --= NOx concentration, ppmvd
K 1.194E-07 = constant, lb/dscf · ppm
Fd -- = fuel factor, dscf/MMBtu
CO2 --= O2 concentration, %
EFNOx O2d -- = lb/MMBtu

Run 1 - Method 7E
𝐸𝐹ேை௫ைଶௗ  = 𝐶ேை௫ × 𝐾 × 𝐹ௗ × 20.9
20.9 − 𝐶ைଶ
CO Summary
Location:
Source:
Project No.:
Reference Method CEMS Average
CO Emission Factor CO Emission Factor Difference
Start End lb/MMBtu (O2d) lb/MMBtu (O2d) lb/MMBtu (O2d)
1 -- --
2 -- --
3 -- --
4 -- --
5 -- --
6 -- --
7 -- --
8 -- --
9 -- --
10 -- --
11 -- --
12 -- --
-
RA ≤ 10%
PS 4A
Confidence Coefficient, CC
where,
t0.975 #N/A = degrees of freedom value
n 0 = number of runs selected for calculating the RA
Sd = standard deviation of difference
CC = confidence coefficient
Relative Accuracy, RA
where,
d = average difference of Reference Method and CEMS
CC = confidence coefficient
RM = reference method, lb/MMBtu (O2d)
RA = relative accuracy, %
Relative Accuracy (RA)
Performance Required - Mean Reference Method
Performance Specification Method

Run
No.Date Time
Average
Standard Deviation (Sd)
Applicable Source Standard (AS)
Confidence Coefficient (CC)
CC = t଴.ଽ଻ହ
n × 𝑆d
RA = d +𝐶𝐶
𝐴𝑆 𝑜𝑟 𝑅𝑀× 100
Appendix A
Example Calculations
Location:
Source:
Project No.:
Run/Method:
Carbon Monoxide Emission Factor (EFCOO2d), lb/MMBtu
where,
CCO -- = CO concentration, ppmvd
K 7.284E-08 = constant, lb/dscf · ppm
Fd -- = fuel factor, dscf/MMBtu
CO2 --= O2 concentration, %
EFCOO2d -- = lb/MMBtu

Run 1 - Method 10
𝐸𝐹஼ைைଶௗ  = 𝐶஼ை × 𝐾× 𝐹ௗ × 20.9
20.9 −𝐶ைଶ
Emissions Calculations
Location:
Source:
Project No.:
1 2 3 4 5 6 7 8 9 10 11 12
Date - - - - - - - - - - - -
Start Time -- -- -- -- -- -- -- -- -- -- -- --
Stop Time -- -- -- -- -- -- -- -- -- -- -- --
Calculated Data
O2 Concentration % dry CO2 -- -- -- -- -- -- -- -- -- -- -- --
O2 Concentration % wet CO2w -- -- -- -- -- -- -- -- -- -- -- --
NOx Concentration ppmvd CNOx -- -- -- -- -- -- -- -- -- -- -- --
CO Concentration ppmvd CCO -- -- -- -- -- -- -- -- -- -- -- --
Run Number
-
-
-
Run 1 Data
Location:
Source:
Project No.:
Date:
Time O2 CO2 NOx CO
Unit % dry % dry ppmvd ppmvd
Status Valid Valid Valid Valid
--
--
--
--
--
--
--
--
--
--
--
--
--
--
--
--
--
--
--
--
--
O2 CO2 NOx CO
Uncorrected Run Average (Cobs)- - - -
Cal Gas Concentration (CMA)-- -- -- --
Pretest System Zero Response
Posttest System Zero Response
Average Zero Response (Co)----
Pretest System Cal Response
Posttest System Cal Response
Average Cal Response (CM)- - - -
Corrected Run Average (Corr)----
Parameter

-
Diluent Pollutant
QA Data
Location:
Source:
Project No.:
O2 CO2 NOx CO
-- -- -- --
-- -- -- --
NA
000 000 000 NA
NA
NA
NA
NA
No No No No
No No
Cylinder Number ID
LOW NA NA NA NA
MID
HIGH
Cylinder Certified Values
LOW NA NA NA NA
MID
HIGH
LOW NA NA NA NA
MID
HIGH
LOW NA NA NA NA
MID
HIGH
Cylinder EPA Gas Type Code
LOW ZERO ZERO ZERO NA
MID NA
HIGH NA
P75 Report w/ NOX as Diluent Gas

P75 Grace Period Indicator
Make
Model
S/N
Operating Range
P75 Operating Level Code
P75 Monitoring System ID
P75 RATA Test Number
P75 RATA Test Reason
Parameter

P75 Reference Method
Cylinder Vendor ID (PGVPID)
Cylinder Expiration Date
P75 Report w/ Protocol Gas Data
Response Time Data
Location:
Source:
Project No.:
O2 CO2 NOx CO
Zero -- -- -- --
Low NA NA NA NA
Mid -- -- -- --
High -- -- -- --
Average -- -- -- --
Maximum --

Parameter
Response Times, seconds
Calibration Data
Location:
Source:
Project No.:
Date:
O2 CO2 NOx CO
Expected Average Concentration -- -- -- --
Span Should be between:
Low - - - -
High - - - -
Desired Span -- -- -- --
Low Range Gas Should be between
Low NA NA NA NA
High NA NA NA NA
Mid Range Gas Should be between
Low - - - -
High - - - -
High Range Gas Should be between
Low NA NA NA NA
High NA NA NA NA
Actual Concentration (% or ppm)
Zero 0.00 0.00 0.00 0.00
Low NA NA NA NA
Mid -- -- -- --
High -- -- -- --
Response Time (seconds)-- -- -- --
Upscale Calibration Gas (CMA)Mid Mid Mid Mid
Instrument Response (% or ppm)
Zero -- -- -- --
Low NA NA NA NA
Mid -- -- -- --
High -- -- -- --
Performance (% of Span or Calibration Gas)
Zero -- -- -- --
Low NA NA NA NA
Mid -- -- -- --
High -- -- -- --
Linearity (% of Span or Cal. Gas Conc.)
-- -- -- --
Status
Zero -- -- -- --
Low NA NA NA NA
Mid -- -- -- --
High -- -- -- --
Parameter

Runs 1-3 Bias/Drift Determinations
Location:
Source:
Project No.:
Date:
O2 CO2 NOx CO
Span Value - - - -
Initial Instrument Zero Cal Response - - - -
Initial Instrument Upscale Cal Response - - - -
Final Instrument Zero Cal Response - - - -
Final Instrument Upscale Cal Response - - - -
Pretest System Zero Response - - - -
Posttest System Zero Response - - - -
Pretest System Mid Response - - - -
Posttest System Mid Response - - - -
Bias or System Performance (%)
Pretest Zero -- -- -- --
Posttest Zero -- -- -- --
Pretest Span -- -- -- --
Posttest Span -- -- -- --
Drift (%)
Zero - - - -
Mid ----
Span Value - - - -
Initial Instrument Zero Cal Response - - - -
Initial Instrument Upscale Cal Response - - - -
Final Instrument Zero Cal Response - - - -
Final Instrument Upscale Cal Response - - - -
Pretest System Zero Response - - - -
Posttest System Zero Response - - - -
Pretest System Mid Response - - - -
Posttest System Mid Response - - - -
Bias (%)
Pretest Zero -- -- -- --
Posttest Zero -- -- -- --
Pretest Span -- -- -- --
Posttest Span -- -- -- --
Drift (%)
Zero - - - -
Mid ----
Span Value - - - -
Initial Instrument Zero Cal Response - - - -
Initial Instrument Upscale Cal Response - - - -
Final Instrument Zero Cal Response - - - -
Final Instrument Upscale Cal Response - - - -
Pretest System Zero Response - - - -
Posttest System Zero Response - - - -
Pretest System Mid Response - - - -
Posttest System Mid Response - - - -
Bias (%)
Pretest Zero -- -- -- --
Posttest Zero -- -- -- --
Pretest Span -- -- -- --
Posttest Span -- -- -- --
Drift (%)
Zero - - - -
Mid ----
Run 1
Run 2
Run 3

-
Parameter
EPA Method 205
Field Calibration of Dilution System
Location:
Source:
Project No.:
Date
EPA
O2
--
--
--
--
Cylinder Number ID
Zero NA
Mid --
High --
Cylinder Certified Values
Zero 0.0
Mid --
High --
Instrument Response (% or ppm)
Zero --
Mid --
High --
Calibration Gas Selection (% of Span)
Mid --
High --
Calibration Error Performance (% of Span)
Zero --
Mid --
High --
Linearity (% of Range)
--
(%) lpm (%) (%) (%) (%) (%) (%) (%)( ± 2 %)
10L/10L* 90.0 7.0 - - - -
10L/10L* 80.0 7.0 - - - -
10L/5L 80.0 5.0 - - - -
10L/5L 50.0 5.0 - - - -
10L/1L 20.0 4.0 - - - -
10L/1L 10.0 4.0 - - - -
(%)( ± 2 %)( ± 2 %)( ± 2 %)
- - - -
- - - -
- - - -
- - - -
- - - -
- - - -
Mid-Level Supply Gas Calibration Direct to Analyzer
Calibration Injection 1 Injection 2 Injection 3 Average
Gas Analyzer Analyzer Analyzer Analyzer
Concentration Concentration Concentration Concentration Concentration
(%) (%) (%) (%) (%) (%)( ± 2 %)
- - - -

Method Criteria
Average
Analyzer
Concentration
Injection 1
Error
Injection 2
Error
Injection 3
Error
Target Flow Rate
Target
Concentration
Actual
Concentration
Injection 1
Analyzer
Concentration
Injection 2
Analyzer
Concentration
Injection 3
Analyzer
Concentration
Parameter
Make
Model
S/N
Span
Difference
Average
Analyzer
Concentration
Analyzer Make:
Analyzer Model:
Analyzer SN:
Environics ID:
Component/Balance Gas:
Target Mass Flow
Controllers
Target
Dilution
O2/N2
Difference
Average
Error
Cylinder Gas ID (Dilution):
Cylinder Gas Concentration (Dilution), %:
Cylinder Gas ID (Mid-Level):
Cylinder Gas Concentration (Mid-Level), %:
Average
Error
*Not all AST Environics Units have 2-10L Mass Flow Controllers. For these units the 90% @ 7lpm and 80% @ 7lpm injections will not be conducted.

Intermountain Power Service Corporation
850 West Brush Wellman Road, Delta, Utah, 84624 / Telephone: [phone] / FAX: [phone] / Fed. I.D. #87-0388573

April 24, 2025

Mr. Bryce Bird
Director Utah Division of Air Quality
195 North 1950 West
P.O. Box 144820
Salt Lake City, Utah 84114-4820

Initial Certification Date Change Notification Intermountain Power Service Corporation (IPSC)
Title V Operating Permit #2700010006

Dear Director Bird:

As specified in 40 CFR 60.8(d), this letter is written to notify UDAQ that the previously notified initial
certification testing dates have changed for Unit 3SGA and Unit 4SGA. Please see Table 1 and Table 2 for
the current schedule.

Table 1 - Unit 3SGA
Initial 7 Day Calibration Error Test April 30, 2025 – May 7, 2025
Initial Cycle Time Test June 15, 2025
Initial Linearity Test June 15, 2025
Initial RATA June 15, 2025 – June 16, 2025

Table 2 - Unit 4SGA
Initial 7 Day Calibration Error Test May 7, 2025 – May 14, 2025
Initial Cycle Time Test June 17, 2025
Initial Linearity Test June 17, 2025
Initial RATA June 17, 2025 – June 18, 2025

Based on information and belief formed after reasonable inquiry, I certify that the statements and
information in the document are true, accurate, and complete.

Questions or comments may be directed to Mr. Mike Utley at [phone] or [e-mail].

Sincerely,

Dahl J. Dalton
President and Chief Operations Officer and Responsible Official

KS/MU:he

cc: Kevin Peng, LADWP Andrea Villarin, LADWP Mike Utley, IPSC
Tamer Ellyahky, LADWP Shudeish Mahadev, LADWP Trevor Johnson, IPSC
April 28, 2025
Mr. Craig Hillock Clean Air and Power Division United States Environmental Protection Agency
1200 Pennsylvania Avenue Northwest Mail Code 6204M Washington, D.C. 20460
Dear Mr. Hillock:
Subject: Notification of Actual Commence Commercial Operation Dates Intermountain Generating Station – Plant Code 6481
Pursuant to the requirements of 40 Code of Federal Regulations (CFR) Part 75.61 Section (a)(2)(i), the Los Angeles Department of Water and Power (LADWP), Operating Agent for the Intermountain Power Project (IPP), previously notified the United States Environmental Protection Agency’s Clean Air and Power Division (CAPD) of IPP’s plans to tentatively commence commercial operation of Intermountain Generating Station’s (IGS) Unit 3SGA and Unit 4SGA on June 6, 2025.
However, upon revisiting the definition of Commence Commercial Operation (CCO) per 40 CFR
Part 72.2, IPP determined that Unit 3SGA and Unit 4SGA first generated electricity upon synchronizing to the grid on March 13, 2025 and April 18, 2025, respectively.
LADWP requests CAPD’s assistance in updating the Clean Air Markets Division Business System’s Certificate of Representation for IGS to reflect the above CCO dates for Unit 3 SGA and Unit 4 SGA.
If you have questions, please call me at [phone], or Mr. Shudeish Mahadev, of my staff, at [phone].
Sincerely,
Andrea Villarin Manager of Air Quality Alternate Designated Representative
AV: c: Mr. Shudeish Mahadev