[Code of Federal Regulations]
[Title 40, Volume 14]
[Revised as of July 1, 2003]
From the U.S. Government Printing Office via GPO Access
[CITE: 40CFR75.53]

[Page 282-287]
 
                   TITLE 40--PROTECTION OF ENVIRONMENT
 
         CHAPTER I--ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)
 
PART 75--CONTINUOUS EMISSION MONITORING--Table of Contents
 
                  Subpart F--Recordkeeping Requirements
 
Sec. 75.53  Monitoring plan.

    (a) General provisions.--(1) The owner or operator shall meet the 
requirements of paragraphs (a), (b), (e), and (f) of this section.
    (2) The owner or operator of an affected unit shall prepare and 
maintain a monitoring plan. Except as provided in paragraphs (d) or (f) 
of this section (as applicable), a monitoring plan shall contain 
sufficient information on the continuous emission or opacity monitoring 
systems, excepted methodology under Sec. 75.19, or excepted monitoring 
systems under appendix D or E to this part and the use of data derived 
from these systems to demonstrate that all unit SO2 
emissions, NOX emissions, CO2 emissions, and 
opacity are monitored and reported.
    (b) Whenever the owner or operator makes a replacement, 
modification, or change in the certified CEMS, continuous opacity 
monitoring system, excepted methodology under Sec. 75.19, excepted 
monitoring system under appendix D or E to this part, or alternative 
monitoring system under subpart E of this part, including a change in 
the automated data acquisition and handling system or in the flue gas 
handling system, that affects information reported in the monitoring 
plan (e.g., a change to a serial number for a component of a monitoring 
system), then the owner or operator shall update the monitoring plan, by 
the applicable deadline specified in Sec. 75.62 or elsewhere in this 
part.
    (c)-(d) [Reserved]
    (e) Contents of the monitoring plan. Each monitoring plan shall 
contain the information in paragraph (e)(1) of this section in 
electronic format and the information in paragraph (e)(2) of this 
section in hardcopy format. Electronic storage of all monitoring plan 
information, including the hardcopy portions, is permissible provided 
that a paper copy of the information can be furnished upon request for 
audit purposes.
    (1) Electronic. (i) ORISPL numbers developed by the Department of 
Energy and used in the National Allowance Data Base (or equivalent 
facility ID number assigned by EPA, if the facility does not have an 
ORSPL number), for all affected units involved in the monitoring plan, 
with the following information for each unit:
    (A) Short name;
    (B) Classification of the unit as one of the following: Phase I 
(including substitution or compensating units), Phase II, new, or 
nonaffected;
    (C) Type of boiler (or boilers for a group of units using a common 
stack);
    (D) Type of fuel(s) fired by boiler, fuel type start and end dates, 
primary/secondary/emergency/startup fuel indicator, and, if more than 
one fuel, the fuel classification of the boiler;
    (E) Type(s) of emission controls for SO2, NOX, 
and particulates installed or to be installed, including specifications 
of whether such controls are pre-combustion, post-combustion, or 
integral to the combustion process; control equipment code, installation 
date, and optimization date; control equipment retirement date (if 
applicable); primary/secondary controls indicator; and

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an indicator for whether the controls are an original installation;
    (F) Maximum hourly heat input capacity;
    (G) Date of first commercial operation;
    (H) Unit retirement date (if applicable);
    (I) Maximum hourly gross load (in MW, rounded to the nearest MW, or 
steam load in 1000 lb/hr, rounded to the nearest 100 lb/hr);
    (J) Identification of all units using a common stack;
    (K) Activation date for the stack/pipe;
    (L) Retirement date of the stack/pipe (if applicable); and
    (M) Indicator of whether the stack is a bypass stack.
    (ii) For each unit and parameter required to be monitored, 
identification of monitoring methodology information, consisting of 
monitoring methodology, type of fuel associated with the methodology, 
primary/secondary methodology indicator, missing data approach for the 
methodology, methodology start date, and methodology end date (if 
applicable).
    (iii) The following information:
    (A) Program(s) for which the EDR is submitted;
    (B) Unit classification;
    (C) Reporting frequency;
    (D) Program participation date;
    (E) State regulation code (if applicable); and
    (F) State or local regulatory agency code.
    (iv) Identification and description of each monitoring component 
(including each monitor and its identifiable components, such as 
analyzer and/or probe) in the CEMS (e.g., SO2 pollutant 
concentration monitor, flow monitor, moisture monitor; NOX 
pollutant concentration monitor and diluent gas monitor), the continuous 
opacity monitoring system, or the excepted monitoring system (e.g., fuel 
flowmeter, data acquisition and handling system), including:
    (A) Manufacturer, model number and serial number;
    (B) Component/system identification code assigned by the utility to 
each identifiable monitoring component (such as the analyzer and/or 
probe). Each code shall use a three-digit format, unique to each 
monitoring component and unique to each monitoring system;
    (C) Designation of the component type and method of sample 
acquisition or operation, (e.g., in situ pollutant concentration monitor 
or thermal flow monitor);
    (D) Designation of the system as a primary, redundant backup, non-
redundant backup, data backup, or reference method backup system, as 
provided in Sec. 75.10(e);
    (E) First and last dates the system reported data;
    (F) Status of the monitoring component; and
    (G) Parameter monitored.
    (v) Identification and description of all major hardware and 
software components of the automated data acquisition and handling 
system, including:
    (A) Hardware components that perform emission calculations or store 
data for quarterly reporting purposes (provide the manufacturer and 
model number); and
    (B) Software components (provide the identification of the provider 
and model/version number).
    (vi) Explicit formulas for each measured emission parameter, using 
component/system identification codes for the primary system used to 
measure the parameter that links CEMS or excepted monitoring system 
observations with reported concentrations, mass emissions, or emission 
rates, according to the conversions listed in appendix D or E to this 
part. Formulas for backup monitoring systems are required only if 
different formulas for the same parameter are used for the primary and 
backup monitoring systems (e.g., if the primary system measures 
pollutant concentration on a different moisture basis from the backup 
system). The formulas must contain all constants and factors required to 
derive mass emissions or emission rates from component/system code 
observations and an indication of whether the formula is being added, 
corrected, deleted, or is unchanged. Each emissions formula is 
identified with a unique three digit code. The owner or operator of a 
low mass emissions unit for which the owner or operator is using the 
optional

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low mass emissions excepted methodology in Sec. 75.19(c) is not required 
to report such formulas.
    (vii) Inside cross-sectional area (ft2) at flue exit (for 
all units) and at flow monitoring location (for units with flow 
monitors, only).
    (viii) Stack exit height (ft) above ground level and ground level 
elevation above sea level.
    (ix) Monitoring location identification, facility identification 
code as assigned by the Administrator for use under the Acid Rain 
Program or this part, and the following information, as reported to the 
Energy Information Administration (EIA): facility identification number, 
flue identification number, boiler identification number, ARP/Subpart H 
facility ID number or ORISPL number (as applicable), reporting year, and 
767 reporting indicator (or equivalent).
    (x) For each parameter monitored: scale, maximum potential 
concentration (and method of calculation), maximum expected 
concentration (if applicable) (and method of calculation), maximum 
potential flow rate (and method of calculation), maximum potential 
NOX emission rate, span value, full-scale range, daily 
calibration units of measure, span effective date/hour, span 
inactivation date/hour, indication of whether dual spans are required, 
default high range value, flow rate span, and flow rate span value and 
full scale value (in scfh) for each unit or stack using SO2, 
NOX, CO2, O2, or flow component 
monitors.
    (xi) If the monitoring system or excepted methodology provides for 
the use of a constant, assumed, or default value for a parameter under 
specific circumstances, then include the following information for each 
such value for each parameter:
    (A) Identification of the parameter;
    (B) Default, maximum, minimum, or constant value, and units of 
measure for the value;
    (C) Purpose of the value;
    (D) Indicator of use during controlled/uncontrolled hours;
    (E) Type of fuel;
    (F) Source of the value;
    (G) Value effective date and hour;
    (H) Date and hour value is no longer effective (if applicable); and
    (I) For units using the excepted methodology under Sec. 75.19, the 
applicable SO2 emission factor.
    (xii) Uless otherwise specified in section 6.5.2.1 of appendix A to 
this part, for each unit of common stack on which hardware CEMS are 
installed:
    (A) The upper and lower boundaries of the range of operation (as 
defined in section 6.5.2.1 of appendix A to this part), expressed in 
megawatts, or thousands of lb/hr of steam, or ft/sec (as applicable);
    (B) The load or operating level(s) designated as normal in section 
6.5.2.1 of appendix A to this part, expressed in megawatts, or thousands 
of lb/hr of steam, or ft/sec (as applicable);
    (C) The two load or operating levels (i.e., low, mid, or high) 
identified in section 6.5.2.1 of appendix A to this part as the most 
frequently used;
    (D) The date of the data analysis used to determine the normal load 
(or operating) level(s) and the two most frequently-used load (or 
operating) levels; and
    (E) Activation and deactivation dates, when the normal load or 
operating level(s) or two most frequently-used load or operating levels 
change and are updated.
    (xiii) For each unit for which the optional fuel flow-to-load test 
in section 2.1.7 of appendix D to this part is used:
    (A) The upper and lower boundaries of the range of operation (as 
defined in section 6.5.2.1 of appendix A to this part), expressed in 
megawatts or thousands of lb/hr of steam;
    (B) The load level designated as normal, pursuant to section 6.5.2.1 
of appendix A to this part, expressed in megawatts or thousands of lb/hr 
of steam; and
    (C) The date of the load analysis used to determine the normal load 
level.
    (2) Hardcopy. (i) Information, including (as applicable): 
identification of the test strategy; protocol for the relative accuracy 
test audit; other relevant test information; calibration gas levels 
(percent of span) for the calibration error test and linearity check; 
calculations for determining maximum potential concentration, maximum 
expected concentration (if applicable), maximum potential flow rate, 
maximum potential NOX emission rate, and span;

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and apportionment strategies under Secs. 75.10 through 75.18.
    (ii) Description of site locations for each monitoring component in 
the continuous emission or opacity monitoring systems, including 
schematic diagrams and engineering drawings specified in paragraphs 
(e)(2)(iv) and (e)(2)(v) of this section and any other documentation 
that demonstrates each monitor location meets the appropriate siting 
criteria.
    (iii) A data flow diagram denoting the complete information handling 
path from output signals of CEMS components to final reports.
    (iv) For units monitored by a continuous emission or opacity 
monitoring system, a schematic diagram identifying entire gas handling 
system from boiler to stack for all affected units, using identification 
numbers for units, monitor components, and stacks corresponding to the 
identification numbers provided in paragraphs (e)(1)(i), (e)(1)(iv), 
(e)(1)(vi), and (e)(1)(ix) of this section. The schematic diagram must 
depict stack height and the height of any monitor locations. 
Comprehensive and/or separate schematic diagrams shall be used to 
describe groups of units using a common stack.
    (v) For units monitored by a continuous emission or opacity 
monitoring system, stack and duct engineering diagrams showing the 
dimensions and location of fans, turning vanes, air preheaters, monitor 
components, probes, reference method sampling ports, and other equipment 
that affects the monitoring system location, performance, or quality 
control checks.
    (f) Contents of monitoring plan for specific situations. The 
following additional information shall be included in the monitoring 
plan for the specific situations described:
    (1) For each gas-fired unit or oil-fired unit for which the owner or 
operator uses the optional protocol in appendix D to this part for 
estimating heat input and/or SO2 mass emissions, or for each 
gas-fired or oil-fired peaking unit for which the owner/operator uses 
the optional protocol in appendix E to this part for estimating 
NOX emission rate (using a fuel flowmeter), the designated 
representative shall include the following additional information in the 
monitoring plan:
    (i) Electronic.
    (A) Parameter monitored;
    (B) Type of fuel measured, maximum fuel flow rate, units of measure, 
and basis of maximum fuel flow rate (i.e., upper range value or unit 
maximum) for each fuel flowmeter;
    (C) Test method used to check the accuracy of each fuel flowmeter;
    (D) Submission status of the data;
    (E) Monitoring system identification code; and
    (F) The method used to demonstrate that the unit qualifies for 
monthly GCV sampling or for daily or annual fuel sampling for sulfur 
content, as applicable.
    (ii) Hardcopy. (A) A schematic diagram identifying the relationship 
between the unit, all fuel supply lines, the fuel flowmeter(s), and the 
stack(s). The schematic diagram must depict the installation location of 
each fuel flowmeter and the fuel sampling location(s). Comprehensive 
and/or separate schematic diagrams shall be used to describe groups of 
units using a common pipe;
    (B) For units using the optional default SO2 emission 
rate for ``pipeline natural gas'' or ``natural gas'' in appendix D to 
this part, the information on the sulfur content of the gaseous fuel 
used to demonstrate compliance with either section 2.3.1.4 or 2.3.2.4 of 
appendix D to this part;
    (C) For units using the 720 hour test under 2.3.6 of Appendix D of 
this part to determine the required sulfur sampling requirements, report 
the procedures and results of the test; and
    (D) For units using the 720 hour test under 2.3.5 of Appendix D of 
this part to determine the appropriate fuel GCV sampling frequency, 
report the procedures used and the results of the test;
    (2) For each gas-fired peaking unit and oil-fired peaking unit for 
which the owner or operator uses the optional procedures in appendix E 
to this part for estimating NOX emission rate, the designated 
representative shall include in the monitoring plan:
    (i) Electronic. Unit operating and capacity factor information 
demonstrating that the unit qualifies as a

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peaking unit or gas-fired unit, as defined in Sec. 72.2 of this chapter, 
and NOX correlation test information, including:
    (A) Test date;
    (B) Test number;
    (C) Operating level;
    (D) Segment ID of the NOX correlation curve;
    (E) NOX monitoring system identification;
    (F) Low and high heat input rate values and corresponding 
NOX emission rates;
    (G) Type of fuel; and
    (H) To document the unit qualifies as a peaking unit, current 
calendar year or ozone season, capacity factor data as specified in the 
definition of peaking unit in Sec. 72.2 of this chapter, and an 
indication of whether the data are actual or projected data.
    (ii) Hardcopy. (A) A protocol containing methods used to perform the 
baseline or periodic NOX emission test; and
    (B) Unit operating parameters related to NOX formation by 
the unit.
    (3) For each gas-fired unit and diesel-fired unit or unit with a wet 
flue gas pollution control system for which the designated 
representative claims an opacity monitoring exemption under Sec. 75.14, 
the designated representative shall include in the hardcopy monitoring 
plan the information specified under Sec. 75.14(b), (c), or (d), 
demonstrating that the unit qualifies for the exemption.
    (4) For each monitoring system recertification, maintenance, or 
other event, the designated representative shall include the following 
additional information in electronic format in the monitoring plan:
    (i) Component/system identification code;
    (ii) Event code or code for required test;
    (iii) Event begin date and hour;
    (iv) Conditionally valid data period begin date and hour (if 
applicable);
    (v) Date and hour that last test is successfully completed; and
    (vi) Indicator of whether conditionally valid data were reported at 
the end of the quarter.
    (5) For each unit using the low mass emission excepted methodology 
under Sec. 75.19 the designated representative shall include the 
following additional information in the monitoring plan that accompanies 
the initial certification application:
    (i) Electronic. For each low mass emissions unit, report the results 
of the analysis performed to qualify as a low mass emissions unit under 
Sec. 75.19(c). This report will include either the previous three years 
actual or projected emissions. The following items should be included:
    (A) Current calendar year of application;
    (B) Type of qualification;
    (C) Years one, two, and three;
    (D) Annual or ozone season measured, estimated or projected 
NOX mass emissions for years one, two, and three;
    (E) Annual measured, estimated or projected SO2 mass 
emissions for years one, two, and three; and
    (F) Annual or ozone season operating hours for years one, two, and 
three.
    (ii) Hardcopy. (A) A schematic diagram identifying the relationship 
between the unit, all fuel supply lines and tanks, any fuel 
flowmeter(s), and the stack(s). Comprehensive and/or separate schematic 
diagrams shall be used to describe groups of units using a common pipe;
    (B) For units which use the long term fuel flow methodology under 
Sec. 75.19(c)(3), the designated representative must provide a diagram 
of the fuel flow to each affected unit or group of units and describe in 
detail the procedures used to determine the long term fuel flow for a 
unit or group of units for each fuel combusted by the unit or group of 
units;
    (C) A statement that the unit burns only gaseous fuel(s) and/or fuel 
oil and a list of the fuels that are burned or a statement that the unit 
is projected to burn only gaseous fuel(s) and/or fuel oil and a list of 
the fuels that are projected to be burned;
    (D) A statement that the unit meets the applicability requirements 
in Secs. 75.19(a) and (b); and
    (E) Any unit historical actual, estimated and projected emissions 
data and calculated emissions data demonstrating that the affected unit 
qualifies as a low mass emissions unit under Secs. 75.19(a) and 
75.19(b).

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    (6) For each gas-fired unit the designated representative shall 
include in the monitoring plan, in electronic format, the following: 
current calendar year, fuel usage data as specified in the definition of 
gas-fired in Sec. 72.2 of this part, and an indication of whether the 
data are actual or projected data.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26532, 26568, May 17, 
1995; 61 FR 59161, Nov. 20, 1996; 64 FR 28605, May 26, 1999; 67 FR 
40440, June 12, 2002]