Title 40—Protection of Environment--Volume 1
PART 75—CONTINUOUS EMISSION MONITORING
§ 75.53   Monitoring plan.
(a) General provisions. (1) The provisions of paragraphs (e) and (f) of this section shall be met through December 31, 2008. The owner or operator shall meet the requirements of paragraphs (a), (b), (e), and (f) of this section through December 31, 2008, except as otherwise provided in paragraph (g) of this section. On and after January 1, 2009, the owner or operator shall meet the requirements of paragraphs (a), (b), (g), and (h) of this section only. In addition, the provisions in paragraphs (g) and (h) of this section that support a regulatory option provided in another section of this part must be followed if the regulatory option is used prior to January 1, 2009.
(2) The owner or operator of an affected unit shall prepare and maintain a monitoring plan. Except as provided in paragraphs (f) or (h) of this section (as applicable), a monitoring plan shall contain sufficient information on the continuous emission or opacity monitoring systems, excepted methodology under § 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 SO 2 emissions, NO X emissions, CO 2 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 § 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 § 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 SO 2 , NO X , 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 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 system component (including each monitor and its identifiable components, such as analyzer and/or probe) in the CEMS ( e.g., SO 2 pollutant concentration monitor, flow monitor, moisture monitor; NO X 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 § 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 low mass emissions excepted methodology in § 75.19(c) is not required to report such formulas.
(vii) Inside cross-sectional area (ft 2 ) 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 NO X 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 SO 2 , NO X , CO 2 , O 2 , 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 § 75.19, the applicable SO 2 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.
(xiv) For each unit with a flow monitor installed on a rectangular stack or duct, if a wall effects adjustment factor (WAF) is determined and applied to the hourly flow rate data:
(A) Stack or duct width at the test location, ft;
(B) Stack or duct depth at the test location, ft;
(C) Wall effects adjustment factor (WAF), to the nearest 0.0001;
(D) Method of determining the WAF;
(E) WAF Effective date and hour;
(F) WAF no longer effective date and hour (if applicable);
(G) WAF determination date;
(H) Number of WAF test runs;
(I) Number of Method 1 traverse points in the WAF test;
(J) Number of test ports in the WAF test; and
(K) Number of Method 1 traverse points in the reference flow RATA.
(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 NO X emission rate, and span; and apportionment strategies under §§ 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 SO 2 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 NO X 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 SO 2 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 NO X 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 peaking unit or gas-fired unit, as defined in § 72.2 of this chapter, and NO X correlation test information, including:
(A) Test date;
(B) Test number;
(C) Operating level;
(D) Segment ID of the NO X correlation curve;
(E) NO X monitoring system identification;
(F) Low and high heat input rate values and corresponding NO X 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 § 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 NO X emission test; and
(B) Unit operating parameters related to NO X 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 § 75.14, the designated representative shall include in the hardcopy monitoring plan the information specified under § 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 § 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 § 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 NO X mass emissions for years one, two, and three;
(E) Annual measured, estimated or projected SO 2 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 § 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 §§ 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 §§ 75.19(a) and 75.19(b).
(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 § 72.2 of this part, and an indication of whether the data are actual or projected data.
(g) Contents of the monitoring plan. The requirements of paragraphs (g) and (h) of this section shall be met on and after January 1, 2009. Notwithstanding this requirement, the provisions of paragraphs (g) and (h) of this section may be implemented prior to January 1, 2009, as follows. In 2008, the owner or operator may opt to record and report the monitoring plan information in paragraphs (g) and (h) of this section, in lieu of recording and reporting the information in paragraphs (e) and (f) of this section. Each monitoring plan shall contain the information in paragraph (g)(1) of this section in electronic format and the information in paragraph (g)(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) The facility ORISPL number 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 ORISPL number). Also provide the following information for each unit and (as applicable) for each common stack and/or pipe, and each multiple stack and/or pipe involved in the monitoring plan:
(A) A representation of the exhaust configuration for the units in the monitoring plan. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) of the configuration. Provide the ID number of each unit and assign a unique ID number to each common stack, common pipe multiple stack and/or multiple pipe associated with the unit(s) represented in the monitoring plan. For common and multiple stacks and/or pipes, provide the activation date and deactivation date (if applicable) of each stack and/or pipe;
(B) Identification of the monitoring system location(s) (e.g., at the unit-level, on the common stack, at each multiple stack, etc.). Provide an indicator (“flag”) if the monitoring location is at a bypass stack or in the ductwork (breeching);
(C) The stack exit height (ft) above ground level and ground level elevation above sea level, and the inside cross-sectional area (ft 2 ) at the flue exit and at the flow monitoring location (for units with flow monitors, only). Also use appropriate codes to indicate the material(s) of construction and the shape(s) of the stack or duct cross-section(s) at the flue exit and (if applicable) at the flow monitor location. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) for the information in this paragraph (g)(1)(i)(C);
(D) The type(s) of fuel(s) fired by each unit. Indicate the start and (if applicable) end date of combustion for each type of fuel, and whether the fuel is the primary, secondary, emergency, or startup fuel;
(E) The type(s) of emission controls that are used to reduce SO 2 , NO X , and particulate emissions from each unit. Also provide the installation date, optimization date, and retirement date (if applicable) of the emission controls, and indicate whether the controls are an original installation;
(F) Maximum hourly heat input capacity of each unit. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) for this parameter; and
(G) A non-load based unit indicator (if applicable) for units that do not produce electrical or thermal output.
(ii) For each monitored parameter (e.g., SO 2 , NO X , flow, etc.) at each monitoring location, specify the monitoring methodology and the missing data approach for the parameter. If the unmonitored bypass stack approach is used for a particular parameter, indicate this by means of an appropriate code. Provide the activation date/hour, and deactivation date/hour (if applicable) for each monitoring methodology and each missing data approach.
(iii) For each required continuous emission monitoring system, each fuel flowmeter system, and each continuous opacity monitoring system, identify and describe the major monitoring components in the monitoring system ( e.g., gas analyzer, flow monitor, opacity monitor, moisture sensor, fuel flowmeter, DAHS software, etc.). Other important components in the system ( e.g., sample probe, PLC, data logger, etc.) may also be represented in the monitoring plan, if necessary. Provide the following specific information about each component and monitoring system:
(A) For each required monitoring system:
( 1 ) Assign a unique, 3-character alphanumeric identification code to the system;
( 2 ) Indicate the parameter monitored by the system;
( 3 ) Designate the system as a primary, redundant backup, non-redundant backup, data backup, or reference method backup system, as provided in § 75.10(e); and
( 4 ) Indicate the system activation date/hour and deactivation date/hour (as applicable).
(B) For each component of each monitoring system represented in the monitoring plan:
( 1 ) Assign a unique, 3-character alphanumeric identification code to the component;
( 2 ) Indicate the manufacturer, model and serial number;
( 3 ) Designate the component type;
( 4 ) For dual-span applications, indicate whether the analyzer component ID represents a high measurement scale, a low scale, or a dual range;
( 5 ) For gas analyzers, indicate the moisture basis of measurement;
( 6 ) Indicate the method of sample acquisition or operation, (e.g., extractive pollutant concentration monitor or thermal flow monitor); and
( 7 ) Indicate the component activation date/hour and deactivation date/hour (as applicable).
(iv) Explicit formulas, using the component and system identification codes for the primary monitoring system, and containing all constants and factors required to derive the required mass emissions, emission rates, heat input rates, etc. from the hourly data recorded by the monitoring systems. Formulas using the system and component ID codes 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). Provide the equation number or other appropriate code for each emissions formula (e.g., use code F-1 if Equation F-1 in appendix F to this part is used to calculate SO 2 mass emissions). Also identify each emissions formula with a unique three character alphanumeric code. The formula effective start date/hour and inactivation date/hour (as applicable) shall be included for each formula. The owner or operator of a unit for which the optional low mass emissions excepted methodology in § 75.19 is being used is not required to report such formulas.
(v) For each parameter monitored with CEMS, provide the following information:
(A) Measurement scale (high or low);
(B) Maximum potential value (and method of calculation). If NO X emission rate in lb/mmBtu is monitored, calculate and provide the maximum potential NO X emission rate in addition to the maximum potential NO X concentration;
(C) Maximum expected value (if applicable) and method of calculation;
(D) Span value(s) and full-scale measurement range(s);
(E) Daily calibration units of measure;
(F) Effective date/hour, and (if applicable) inactivation date/hour of each span value. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) for the measurement scale and dual span information in paragraphs (g)(1)(v)(A), (g)(1)(v)(G), and (g)(1)(v)(H) of this section;
(G) An indication of whether dual spans are required. If two span values are required, then, on and after April 27, 2011, indicate whether an autoranging analyzer is used to represent the two measurement scales; and
(H) The default high range value (if applicable) and the maximum allowable low-range value for this option.
(vi) 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, i.e., during controlled hours, uncontrolled hours, or all operating hours;
(E) Type of fuel;
(F) Source of the value;
(G) Value effective date and hour;
(H) Date and hour that the value is no longer effective (if applicable);
(I) For units using the excepted methodology under § 75.19, the applicable SO 2 emission factor; and
(J) On and after April 27, 2011, group identification code.
(vii) Unless otherwise specified in section 6.5.2.1 of appendix A to this part, for each unit or common stack on which hardware CEMS are installed:
(A) Maximum hourly gross load (in MW, rounded to the nearest MW, or steam load in 1000 lb/hr ( i.e. , klb/hr), rounded to the nearest klb/hr, or thermal output in mmBtu/hr, rounded to the nearest mmBtu/hr), for units that produce electrical or thermal output;
(B) 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, thousands of lb/hr of steam, mmBtu/hr of thermal output, or ft/sec (as applicable);
(C) Except for peaking units, identify the most frequently and second most frequently used load (or operating) levels ( i.e. , low, mid, or high) in accordance with section 6.5.2.1 of appendix A to this part, expressed in megawatts, thousands of lb/hr of steam, mmBtu/hr of thermal output, or ft/sec (as applicable);
(D) Except for peaking units, an indicator of whether the second most frequently used load (or operating) level is designated as normal in section 6.5.2.1 of appendix A to this part;
(E) 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 (as applicable); and
(F) Activation and deactivation dates and hours, when the maximum hourly gross load, boundaries of the range of operation, normal load (or operating) level(s) or two most frequently-used load (or operating) levels change and are updated.
(viii) For each unit for which CEMS are not installed:
(A) Maximum hourly gross load (in MW, rounded to the nearest MW, or steam load in klb/hr, rounded to the nearest klb/hr, or steam load in mmBtu/hr, rounded to the nearest mmBtu/hr);
(B) 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, mmBtu/hr of thermal output, or thousands of lb/hr of steam;
(C) Except for peaking units and units using the low mass emissions excepted methodology under § 75.19, identify the load level designated as normal, pursuant to section 6.5.2.1 of appendix A to this part, expressed in megawatts, mmBtu/hr of thermal output, or thousands of lb/hr of steam;
(D) The date of the load analysis used to determine the normal load level (as applicable); and
(E) Activation and deactivation dates and hours, when the maximum hourly gross load, boundaries of the range of operation, or normal load level change and are updated.
(ix) For each unit with a flow monitor installed on a rectangular stack or duct, if a wall effects adjustment factor (WAF) is determined and applied to the hourly flow rate data:
(A) Stack or duct width at the test location, ft;
(B) Stack or duct depth at the test location, ft;
(C) Wall effects adjustment factor (WAF), to the nearest 0.0001;
(D) Method of determining the WAF;
(E) WAF Effective date and hour;
(F) WAF no longer effective date and hour (if applicable);
(G) WAF determination date;
(H) Number of WAF test runs;
(I) Number of Method 1 traverse points in the WAF test;
(J) Number of test ports in the WAF test; and
(K) Number of Method 1 traverse points in the reference flow RATA.
(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 NO X emission rate, and span; and apportionment strategies under §§ 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, monitoring systems and components, and stacks corresponding to the identification numbers provided in paragraphs (g)(1)(i) and (g)(1)(iii) 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.
(h) 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 SO 2 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 NO X emission rate (using a fuel flowmeter), the designated representative shall include the following additional information for each fuel flowmeter system 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) Monitoring system identification code;
(E) 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; and
(F) Activation date/hour and (if applicable) inactivation date/hour for the fuel flowmeter system;
(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 SO 2 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 NO X 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 peaking unit, as defined in § 72.2 of this chapter for the current calendar year or ozone season, including: capacity factor data for three calendar years (or ozone seasons) as specified in the definition of peaking unit in § 72.2 of this chapter; the method of qualification used; and an indication of whether the data are actual or projected data. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) for the peaking unit qualification information in this paragraph (h)(2)(i).
(ii) Hardcopy. (A) A protocol containing methods used to perform the baseline or periodic NO X emission test; and
(B) Unit operating parameters related to NO X 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 § 75.14, the designated representative shall include in the hardcopy monitoring plan the information specified under § 75.14(b), (c), or (d), demonstrating that the unit qualifies for the exemption.
(4) For each unit using the low mass emissions excepted methodology under § 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 § 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 and/or ozone season measured, estimated or projected NO X mass emissions for years one, two, and three;
(E) Annual measured, estimated or projected SO 2 mass emissions (if applicable) 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 § 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 § 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 § 75.19(a) and 75.19(b).
(5) For qualification as a gas-fired unit, as defined in § 72.2 of this part, the designated representative shall include in the monitoring plan, in electronic format, the following: current calendar year, fuel usage data for three calendar years (or ozone seasons) as specified in the definition of gas-fired in § 72.2 of this chapter, the method of qualification used, and an indication of whether the data are actual or projected data. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) for the gas-fired unit qualification information in this paragraph (h)(5).
(6) For each monitoring location with a stack flow monitor that is exempt from performing 3-load flow RATAs (peaking units, bypass stacks, or by petition) the designated representative shall include in the monitoring plan an indicator of exemption from 3-load flow RATA using the appropriate exemption code.
§§ 75.54-75.56   [Reserved]
§ 75.57   General recordkeeping provisions.
The owner or operator shall meet all of the applicable recordkeeping requirements of this section.
(a) Recordkeeping requirements for affected sources. The owner or operator of any affected source subject to the requirements of this part shall maintain for each affected unit a file of all measurements, data, reports, and other information required by this part at the source in a form suitable for inspection for at least three (3) years from the date of each record. Unless otherwise provided, throughout this subpart the phrase “for each affected unit” also applies to each group of affected or nonaffected units utilizing a common stack and common monitoring systems, pursuant to §§ 75.16 through 75.18, or utilizing a common pipe header and common fuel flowmeter, pursuant to section 2.1.2 of appendix D to this part. The file shall contain the following information:
(1) The data and information required in paragraphs (b) through (h) of this section, beginning with the earlier of the date of provisional certification or the deadline in § 75.4(a), (b), or (c);
(2) The supporting data and information used to calculate values required in paragraphs (b) through (g) of this section, excluding the subhourly data points used to compute hourly averages under § 75.10(d), beginning with the earlier of the date of provisional certification or the deadline in § 75.4(a), (b), or (c);
(3) The data and information required in § 75.58 for specific situations, beginning with the earlier of the date of provisional certification or the deadline in § 75.4(a), (b), or (c);
(4) The certification test data and information required in § 75.59 for tests required under § 75.20, beginning with the date of the first certification test performed, the quality assurance and quality control data and information required in § 75.59 for tests, and the quality assurance/quality control plan required under § 75.21 and appendix B to this part, beginning with the date of provisional certification;
(5) The current monitoring plan as specified in § 75.53, beginning with the initial submission required by § 75.62;
(6) The quality control plan as described in section 1 of appendix B to this part, beginning with the date of provisional certification; and
(7) The information required by sections 6.1.2(b) and (c) of appendix A to this part.
(b) Operating parameter record provisions. The owner or operator shall record for each hour the following information on unit operating time, heat input rate, and load, separately for each affected unit and also for each group of units utilizing a common stack and a common monitoring system or utilizing a common pipe header and common fuel flowmeter:
(1) Date and hour;
(2) Unit operating time (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator));
(3) Hourly gross unit load (rounded to nearest MWge) (or steam load in 1000 lb/hr at stated temperature and pressure, rounded to the nearest 1000 lb/hr, or mmBtu/hr of thermal output, rounded to the nearest mmBtu/hr, if elected in the monitoring plan);
(4) Operating load range corresponding to hourly gross load of 1 to 10, except for units using a common stack or common pipe header, which may use up to 20 load ranges for stack or fuel flow, as specified in the monitoring plan;
(5) Hourly heat input rate (mmBtu/hr, rounded to the nearest tenth);
(6) Identification code for formula used for heat input, as provided in § 75.53; and
(7) For CEMS units only, F-factor for heat input calculation and indication of whether the diluent cap was used for heat input calculations for the hour.
(c) SO 2 emission record provisions. The owner or operator shall record for each hour the information required by this paragraph for each affected unit or group of units using a common stack and common monitoring systems, except as provided under § 75.11(e) or for a gas-fired or oil-fired unit for which the owner or operator is using the optional protocol in appendix D to this part or for a low mass emissions unit for which the owner or operator is using the optional low mass emissions methodology in § 75.19(c) for estimating SO 2 mass emissions:
(1) For SO 2 concentration during unit operation, as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in § 75.53;
(ii) Date and hour;
(iii) Hourly average SO 2 concentration (ppm, rounded to the nearest tenth);
(iv) Hourly average SO 2 concentration (ppm, rounded to the nearest tenth), adjusted for bias if bias adjustment factor is required, as provided in § 75.24(d);
(v) Percent monitor data availability (recorded to the nearest tenth of a percent), calculated pursuant to § 75.32; and
(vi) Method of determination for hourly average SO 2 concentration using Codes 1-55 in Table 4a of this section.
(2) For flow rate during unit operation, as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in § 75.53;
(ii) Date and hour;
(iii) Hourly average volumetric flow rate (in scfh, rounded to the nearest thousand);
(iv) Hourly average volumetric flow rate (in scfh, rounded to the nearest thousand), adjusted for bias if bias adjustment factor required, as provided in § 75.24(d);
(v) Percent monitor data availability (recorded to the nearest tenth of a percent) for the flow monitor, calculated pursuant to § 75.32; and
(vi) Method of determination for hourly average flow rate using Codes 1-55 in Table 4a of this section.
(3) For flue gas moisture content during unit operation (where SO 2 concentration is measured on a dry basis), as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in § 75.53;
(ii) Date and hour;
(iii) Hourly average moisture content of flue gas (percent, rounded to the nearest tenth). If the continuous moisture monitoring system consists of wet- and dry-basis oxygen analyzers, also record both the wet- and dry-basis oxygen hourly averages (in percent O 2 , rounded to the nearest tenth);
(iv) Percent monitor data availability (recorded to the nearest tenth of a percent) for the moisture monitoring system, calculated pursuant to § 75.32; and
(v) Method of determination for hourly average moisture percentage, using Codes 1-55 in Table 4a of this section.
(4) For SO 2 mass emission rate during unit operation, as measured and reported from the certified primary monitoring system(s), certified redundant or non-redundant back-up monitoring system(s), or other approved method(s) of emissions determination:
(i) Date and hour;
(ii) Hourly SO 2 mass emission rate (lb/hr, rounded to the nearest tenth);
(iii) Hourly SO 2 mass emission rate (lb/hr, rounded to the nearest tenth), adjusted for bias if bias adjustment factor required, as provided in § 75.24(d); and
(iv) Identification code for emissions formula used to derive hourly SO 2 mass emission rate from SO 2 concentration and flow and (if applicable) moisture data in paragraphs (c)(1), (c)(2), and (c)(3) of this section, as provided in § 75.53.
Table 4a—Codes for Method of Emissions and Flow Determination
(d) NO X emission record provisions. The owner or operator shall record the applicable information required by this paragraph for each affected unit for each hour or partial hour during which the unit operates, except for a gas-fired peaking unit or oil-fired peaking unit for which the owner or operator is using the optional protocol in appendix E to this part or a low mass emissions unit for which the owner or operator is using the optional low mass emissions excepted methodology in § 75.19(c) for estimating NO X emission rate. For each NO X emission rate (in lb/mmBtu) measured by a NO X -diluent monitoring system, or, if applicable, for each NO X concentration (in ppm) measured by a NO X concentration monitoring system used to calculate NO X mass emissions under § 75.71(a)(2), record the following data as measured and reported from the certified primary monitor, certified back-up monitor, or other approved method of emissions determination:
(1) Component-system identification code, as provided in § 75.53 (including identification code for the moisture monitoring system, if applicable);
(2) Date and hour;
(3) Hourly average NO X concentration (ppm, rounded to the nearest tenth) and hourly average NO X concentration (ppm, rounded to the nearest tenth) adjusted for bias if bias adjustment factor required, as provided in § 75.24(d);
(4) Hourly average diluent gas concentration (for NO X -diluent monitoring systems, only, in units of percent O 2 or percent CO 2 , rounded to the nearest tenth);
(5) If applicable, the hourly average moisture content of the stack gas (percent H 2 O, rounded to the nearest tenth). If the continuous moisture monitoring system consists of wet- and dry-basis oxygen analyzers, also record both the hourly wet- and dry-basis oxygen readings (in percent O 2 , rounded to the nearest tenth);
(6) Hourly average NO X emission rate (for NO X -diluent monitoring systems only, in units of lb/mmBtu, rounded to the nearest thousandth);
(7) Hourly average NO X emission rate (for NO X -diluent monitoring systems only, in units of lb/mmBtu, rounded to the nearest thousandth), adjusted for bias if bias adjustment factor is required, as provided in § 75.24(d). The requirement to report hourly NO X emission rates to the nearest thousandth shall not affect NO X compliance determinations under part 76 of this chapter; compliance with each applicable emission limit under part 76 shall be determined to the nearest hundredth pound per million Btu;
(8) Percent monitoring system data availability (recorded to the nearest tenth of a percent), for the NO X -diluent or NO X concentration monitoring system, and, if applicable, for the moisture monitoring system, calculated pursuant to § 75.32;
(9) Method of determination for hourly average NO X emission rate or NO X concentration and (if applicable) for the hourly average moisture percentage, using Codes 1-55 in Table 4a of this section; and
(10) Identification codes for emissions formulas used to derive hourly average NO X emission rate and total NO X mass emissions, as provided in § 75.53, and (if applicable) the F-factor used to convert NO X concentrations into emission rates.
(e) CO 2 emission record provisions. Except for a low mass emissions unit for which the owner or operator is using the optional low mass emissions excepted methodology in § 75.19(c) for estimating CO 2 mass emissions, the owner or operator shall record or calculate CO 2 emissions for each affected unit using one of the following methods specified in this section:
(1) If the owner or operator chooses to use a CO 2 CEMS (including an O 2 monitor and flow monitor, as specified in appendix F to this part), then the owner or operator shall record for each hour or partial hour during which the unit operates the following information for CO 2 mass emissions, as measured and reported from the certified primary monitor, certified back-up monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in § 75.53 (including identification code for the moisture monitoring system, if applicable);
(ii) Date and hour;
(iii) Hourly average CO 2 concentration (in percent, rounded to the nearest tenth);
(iv) Hourly average volumetric flow rate (scfh, rounded to the nearest thousand scfh);
(v) Hourly average moisture content of flue gas (percent, rounded to the nearest tenth), where CO 2 concentration is measured on a dry basis. If the continuous moisture monitoring system consists of wet- and dry-basis oxygen analyzers, also record both the hourly wet- and dry-basis oxygen readings (in percent O 2 , rounded to the nearest tenth);
(vi) Hourly average CO 2 mass emission rate (tons/hr, rounded to the nearest tenth);
(vii) Percent monitor data availability for both the CO 2 monitoring system and, if applicable, the moisture monitoring system (recorded to the nearest tenth of a percent), calculated pursuant to § 75.32;
(viii) Method of determination for hourly average CO 2 mass emission rate and hourly average CO 2 concentration, and, if applicable, for the hourly average moisture percentage, using Codes 1-55 in Table 4a of this section;
(ix) Identification code for emissions formula used to derive hourly average CO 2 mass emission rate, as provided in § 75.53; and
(x) Indication of whether the diluent cap was used for CO 2 calculation for the hour.
(2) As an alternative to paragraph (e)(1) of this section, the owner or operator may use the procedures in § 75.13 and in appendix G to this part, and shall record daily the following information for CO 2 mass emissions:
(i) Date;
(ii) Daily combustion-formed CO 2 mass emissions (tons/day, rounded to the nearest tenth);
(iii) For coal-fired units, flag indicating whether optional procedure to adjust combustion-formed CO 2 mass emissions for carbon retained in flyash has been used and, if so, the adjustment;
(iv) For a unit with a wet flue gas desulfurization system or other controls generating CO 2 , daily sorbent-related CO 2 mass emissions (tons/day, rounded to the nearest tenth); and
(v) For a unit with a wet flue gas desulfurization system or other controls generating CO 2 , total daily CO 2 mass emissions (tons/day, rounded to the nearest tenth) as the sum of combustion-formed emissions and sorbent-related emissions.
(f) Opacity records. The owner or operator shall record opacity data as specified by the State or local air pollution control agency. If the State or local air pollution control agency does not specify recordkeeping requirements for opacity, then record the information required by paragraphs (f) (1) through (5) of this section for each affected unit, except as provided in §§ 75.14(b), (c), and (d). The owner or operator shall also keep records of all incidents of opacity monitor downtime during unit operation, including reason(s) for the monitor outage(s) and any corrective action(s) taken for opacity, as measured and reported by the continuous opacity monitoring system:
(1) Component/system identification code;
(2) Date, hour, and minute;
(3) Average opacity of emissions for each six minute averaging period (in percent opacity);
(4) If the average opacity of emissions exceeds the applicable standard, then a code indicating such an exceedance has occurred; and
(5) Percent monitor data availability (recorded to the nearest tenth of a percent), calculated according to the requirements of the procedure recommended for State Implementation Plans in appendix M to part 51 of this chapter.
(g) Diluent record provisions. The owner or operator of a unit using a flow monitor and an O 2 diluent monitor to determine heat input, in accordance with Equation F-17 or F-18 of appendix F to this part, or a unit that accounts for heat input using a flow monitor and a CO 2 diluent monitor (which is used only for heat input determination and is not used as a CO 2 pollutant concentration monitor) shall keep the following records for the O 2 or CO 2 diluent monitor:
(1) Component-system identification code, as provided in § 75.53;
(2) Date and hour;
(3) Hourly average diluent gas (O 2 or CO 2 ) concentration (in percent, rounded to the nearest tenth);
(4) Percent monitor data availability for the diluent monitor (recorded to the nearest tenth of a percent), calculated pursuant to § 75.32; and
(5) Method of determination code for diluent gas (O 2 or CO 2 ) concentration data using Codes 1-55, in Table 4a of this section.
(h) Missing data records. The owner or operator shall record the causes of any missing data periods and the actions taken by the owner or operator to correct such causes.
§ 75.58   General recordkeeping provisions for specific situations.
The owner or operator shall meet all of the applicable recordkeeping requirements of this section.
(a) [Reserved]
(b) Specific parametric data record provisions for calculating substitute emissions data for units with add-on emission controls. In accordance with § 75.34, the owner or operator of an affected unit with add-on emission controls shall either record the applicable information in paragraph (b)(3) of this section for each hour of missing SO 2 concentration data or NO X emission rate (in addition to other information), or shall record the information in paragraph (b)(1) of this section for SO 2 or paragraph (b)(2) of this section for NO X through an automated data acquisition and handling system, as appropriate to the type of add-on emission controls:
(1) For units with add-on SO 2 emission controls using the optional parametric monitoring procedures in appendix C to this part, for each hour of missing SO 2 concentration or volumetric flow data:
(i) The information required in § 75.57(c) for SO 2 concentration and volumetric flow, if either one of these monitors is still operating;
(ii) Date and hour;
(iii) Number of operating scrubber modules;
(iv) Total feedrate of slurry to each operating scrubber module (gal/min);
(v) Pressure differential across each operating scrubber module (inches of water column);
(vi) For a unit with a wet flue gas desulfurization system, an in-line measure of absorber pH for each operating scrubber module;
(vii) For a unit with a dry flue gas desulfurization system, the inlet and outlet temperatures across each operating scrubber module;
(viii) For a unit with a wet flue gas desulfurization system, the percent solids in slurry for each scrubber module;
(ix) For a unit with a dry flue gas desulfurization system, the slurry feed rate (gal/min) to the atomizer nozzle;
(x) For a unit with SO 2 add-on emission controls other than wet or dry limestone, corresponding parameters approved by the Administrator;
(xi) Method of determination of SO 2 concentration and volumetric flow using Codes 1-55 in Table 4a of § 75.57; and
(xii) Inlet and outlet SO 2 concentration values, recorded by an SO 2 continuous emission monitoring system, and the removal efficiency of the add-on emission controls.
(2) For units with add-on NO X emission controls using the optional parametric monitoring procedures in appendix C to this part, for each hour of missing NO X emission rate data:
(i) Date and hour;
(ii) Inlet air flow rate (scfh, rounded to the nearest thousand);
(iii) Excess O 2 concentration of flue gas at stack outlet (percent, rounded to the nearest tenth of a percent);
(iv) Carbon monoxide concentration of flue gas at stack outlet (ppm, rounded to the nearest tenth);
(v) Temperature of flue gas at furnace exit or economizer outlet duct (°F);
(vi) Other parameters specific to NO X emission controls (e.g., average hourly reagent feedrate);
(vii) Method of determination of NO X emission rate using Codes 1-55 in Table 4a of § 75.57; and
(viii) Inlet and outlet NO X emission rate values recorded by a NO X continuous emission monitoring system and the removal efficiency of the add-on emission controls.
(3) Except as otherwise provided in § 75.34(d), for units with add-on SO 2 or NO X emission controls following the provisions of §§ 75.34(a)(1), (a)(2), (a)(3) or (a)(5), the owner or operator shall record:
(i) Parametric data which demonstrate, for each hour of missing SO 2 or NO X emission data, the proper operation of the add-on emission controls, as described in the quality assurance/quality control program for the unit. The parametric data shall be maintained on site and shall be submitted, upon request, to the Administrator, EPA Regional office, State, or local agency;
(ii) A flag indicating, for each hour of missing SO 2 or NO X emission data, either that the add-on emission controls are operating properly, as evidenced by all parameters being within the ranges specified in the quality assurance/quality control program, or that the add-on emission controls are not operating properly.
(c) Specific SO 2 emission record provisions for gas-fired or oil-fired units using optional protocol in appendix D to this part. In lieu of recording the information in § 75.57(c), the owner or operator shall record the applicable information in this paragraph for each affected gas-fired or oil-fired unit for which the owner or operator is using the optional protocol in appendix D to this part for estimating SO 2 mass emissions:
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average volumetric flow rate of oil, while the unit combusts oil, with the units in which oil flow is recorded (gal/hr, scf/hr, m 3 /hr, or bbl/hr, rounded to the nearest tenth) (flag value if derived from missing data procedures);
(iii) Sulfur content of oil sample used to determine SO 2 mass emission rate (rounded to nearest hundredth for diesel fuel or to the nearest tenth of a percent for other fuel oil) (flag value if derived from missing data procedures);
(iv) [Reserved];
(v) Mass flow rate of oil combusted each hour and method of determination (lb/hr, rounded to the nearest tenth) (flag value if derived from missing data procedures);
(vi) SO 2 mass emission rate from oil (lb/hr, rounded to the nearest tenth);
(vii) For units using volumetric oil flowmeters, density of oil with the units in which oil density is recorded and method of determination (flag value if derived from missing data procedures);
(viii) Gross calorific value of oil used to determine heat input and method of determination (Btu/lb) (flag value if derived from missing data procedures);
(ix) Hourly heat input rate from oil, according to procedures in appendix D to this part (mmBtu/hr, to the nearest tenth);
(x) Fuel usage time for combustion of oil during the hour (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator)) (flag to indicate multiple/single fuel types combusted);
(xi) Monitoring system identification code;
(xii) Operating load range corresponding to gross unit load (01-20);
(xiii) Type of oil combusted; and
(xiv) Heat input formula ID and SO 2 Formula ID (required beginning January 1, 2009).
(2) For gas-fired units or oil-fired units using the optional protocol in appendix D to this part for daily manual oil sampling, when the unit is combusting oil, the highest sulfur content recorded from the most recent 30 daily oil samples (rounded to the nearest tenth of a percent).
(3) For gas-fired units or oil-fired units using the optional protocol in appendix D to this part, when either an assumed oil sulfur content or density value is used, or when as-delivered oil sampling is performed:
(i) Record the measured sulfur content, gross calorific value, and, if applicable, density from each fuel sample; and
(ii) Record and report the assumed sulfur content, gross calorific value, and, if applicable, density used to calculate SO 2 mass emission rate or heat input rate.
(4) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour.
(ii) Hourly heat input rate from gaseous fuel, according to procedures in appendix F to this part (mmBtu/hr, rounded to the nearest tenth).
(iii) Sulfur content or SO 2 emission rate, in one of the following formats, in accordance with the appropriate procedure from appendix D to this part:
(A) Sulfur content of gas sample and method of determination (rounded to the nearest 0.1 grains/100 scf) (flag value if derived from missing data procedures); or
(B) Default SO 2 emission rate of 0.0006 lb/mmBtu for pipeline natural gas, or calculated SO 2 emission rate for natural gas from section 2.3.2.1.1 of appendix D to this part.
(iv) Hourly flow rate of gaseous fuel, while the unit combusts gas (100 scfh) and source of data code for gas flow rate.
(v) Gross calorific value of gaseous fuel used to determine heat input rate (Btu/100 scf) (flag value if derived from missing data procedures).
(vi) SO 2 mass emission rate due to the combustion of gaseous fuels (lb/hr).
(vii) Fuel usage time for combustion of gaseous fuel during the hour (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator)) (flag to indicate multiple/single fuel types combusted).
(viii) Monitoring system identification code.
(ix) Operating load range corresponding to gross unit load (01-20).
(x) Type of gas combusted; and
(xi) Heat input formula ID and SO 2 Formula ID (required beginning January 1, 2009).
(5) For each oil sample or sample of diesel fuel:
(i) Date of sampling;
(ii) Sulfur content (percent, rounded to either the nearest hundredth, or nearest ten-thousandth for diesel fuels and to the nearest tenth for other fuel oil);
(iii) Gross calorific value (Btu/lb); and
(iv) Density or specific gravity, if required to convert volume to mass.
(6) For each sample of gaseous fuel for sulfur content:
(i) Date of sampling; and
(ii) Sulfur content (grains/100 scf, rounded to the nearest tenth).
(7) For each sample of gaseous fuel for gross calorific value:
(i) Date of sampling; and
(ii) Gross calorific value (Btu/100 scf).
(8) For each oil sample or sample of gaseous fuel:
(i) Type of oil or gas; and
(ii) Type of sulfur sampling (using codes in tables D-4 and D-5 of appendix D to this part) and value used in calculations, and type of GCV or density sampling (using codes in tables D-4 and D-5 of appendix D to this part).
(d) Specific NO X emission record provisions for gas-fired peaking units or oil-fired peaking units using optional protocol in appendix E to this part. In lieu of recording the information in § 75.57(d), the owner or operator shall record the applicable information in this paragraph for each affected gas-fired peaking unit or oil-fired peaking unit for which the owner or operator is using the optional protocol in appendix E to this part for estimating NO X emission rate. The owner or operator shall meet the requirements of this section, except that the requirements under paragraphs (d)(1)(vii) and (d)(2)(vii) of this section shall become applicable on the date on which the owner or operator is required to monitor, record, and report NO X mass emissions under an applicable State or federal NO X mass emission reduction program, if the provisions of subpart H of this part are adopted as requirements under such a program.
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average mass flow rate of oil while the unit combusts oil with the units in which oil flow is recorded (lb/hr);
(iii) Gross calorific value of oil used to determine heat input (Btu/lb);
(iv) Hourly average NO X emission rate from combustion of oil (lb/mmBtu, rounded to the nearest hundredth);
(v) Heat input rate of oil (mmBtu/hr, rounded to the nearest tenth);
(vi) Fuel usage time for combustion of oil during the hour (rounded up to the nearest fraction of an hour, in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator);
(vii) NO X mass emissions, calculated in accordance with section 8.1 of appendix F to this part;
(viii) NO X monitoring system identification code;
(ix) Fuel flow monitoring system identification code;
(x) Segment identification of the correlation curve; and
(xi) Heat input rate formula ID (required beginning January 1, 2009).
(2) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour;
(ii) Hourly average fuel flow rate of gaseous fuel, while the unit combusts gas (100 scfh);
(iii) Gross calorific value of gaseous fuel used to determine heat input (Btu/100 scf) (flag value if derived from missing data procedures);
(iv) Hourly average NO X emission rate from combustion of gaseous fuel (lb/mmBtu, rounded to nearest hundredth);
(v) Heat input rate from gaseous fuel, while the unit combusts gas (mmBtu/hr, rounded to the nearest tenth);
(vi) Fuel usage time for combustion of gaseous fuel during the hour (rounded up to the nearest fraction of an hour, in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator);
(vii) NO X mass emissions, calculated in accordance with section 8.1 of appendix F to this part;
(viii) NO X monitoring system identification code;
(ix) Fuel flow monitoring system identification code;
(x) Segment identification of the correlation curve; and
(xi) Heat input rate formula ID (required beginning January 1, 2009).
(3) For each hour when the unit combusts multiple fuels:
(i) Date and hour;
(ii) Hourly average heat input rate from all fuels (mmBtu/hr, rounded to the nearest tenth); and
(iii) Hourly average NO X emission rate for the unit for all fuels (lb/mmBtu, rounded to the nearest hundredth).
(4) For each hour when the unit combusts any fuel(s):
(i) For stationary gas turbines and diesel or dual-fuel reciprocating engines, hourly averages of operating parameters under section 2.3 of appendix E to this part (flag if value is outside of manufacturer's recommended range); and
(ii) For boilers, hourly average boiler O 2 reading (percent, rounded to the nearest tenth) (flag if value exceeds by more than 2 percentage points the O 2 level recorded at the same heat input during the previous NO X emission rate test); and
(iii) On and after April 27, 2011, operating condition codes for the following:
(A) Unit operated on emergency fuel;
(B) Correlation curve for the fuel mixture has expired;
(C) Operating parameter is outside of normal limits;
(D) Uncontrolled hour;
(E) Operation above highest tested heat input rate point on the curve;
(F) Operating parameter data missing or invalid;
(G) Designated operational and control equipment parameters within normal limits; and
(H) Operation below lowest tested heat input rate point on the curve.
(5) For each fuel sample:
(i) Date of sampling;
(ii) Gross calorific value (Btu/lb for oil, Btu/100 scf for gaseous fuel); and
(iii) Density or specific gravity, if required to convert volume to mass.
(6) Flag to indicate multiple or single fuels combusted.
(e) Specific SO 2 emission record provisions during the combustion of gaseous fuel. (1) If SO 2 emissions are determined in accordance with the provisions in § 75.11(e)(2) during hours in which only gaseous fuel is combusted in a unit with an SO 2 CEMS, the owner or operator shall record the information in paragraph (c)(3) of this section in lieu of the information in §§ 75.57(c)(1), (c)(3), and (c)(4), for those hours.
(2) The provisions of this paragraph apply to a unit which, in accordance with the provisions of § 75.11(e)(3), uses an SO 2 CEMS to determine SO 2 emissions during hours in which only gaseous fuel is combusted in the unit. If the unit sometimes burns only gaseous fuel that is very low sulfur fuel (as defined in § 72.2 of this chapter) as a primary and/or backup fuel and at other times combusts higher sulfur fuels, such as coal or oil, as primary and/or backup fuel(s), then the owner or operator shall keep records on-site, in a form suitable for inspection, of the type(s) of fuel(s) burned during each period of missing SO 2 data and the number of hours that each type of fuel was combusted in the unit during each missing data period. This recordkeeping requirement does not apply to an affected unit that burns very low sulfur fuel exclusively, nor does it apply to a unit that burns such gaseous fuel(s) only during unit startup.
(f) Specific SO 2 , NO X , and CO 2 record provisions for gas-fired or oil-fired units using the optional low mass emissions excepted methodology in § 75.19. In lieu of recording the information in §§ 75.57(b) through (e), the owner or operator shall record the following information for each affected low mass emissions unit for which the owner or operator is using the optional low mass emissions excepted methodology in § 75.19(c):
(1) All low mass emission units shall report for each hour:
(i) Date and hour;
(ii) Unit operating time (units using the long term fuel flow methodology report operating time to be 1);
(iii) Fuel type (pipeline natural gas, natural gas, other gaseous fuel, residual oil, or diesel fuel). If more than one type of fuel is combusted in the hour, either:
(A) Indicate the fuel type which results in the highest emission factors for NO X (this option is in effect through December 31, 2008); or
(B) Indicate the fuel type resulting in the highest emission factor for each parameter (SO 2 , NO X emission rate, and CO 2 ) separately (this option is required on and after January 1, 2009);
(iv) Average hourly NO X emission rate (lb/mmBtu, rounded to the nearest thousandth);
(v) Hourly NO X mass emissions (lbs, rounded to the nearest tenth);
(vi) Hourly SO 2 mass emissions (lbs, rounded to the nearest tenth);
(vii) Hourly CO 2 mass emissions (tons, rounded to the nearest tenth);
(viii) Hourly calculated unit heat input in mmBtu;
(ix) Hourly unit output in gross load or steam load;
(x) The method of determining hourly heat input: unit maximum rated heat input, unit long term fuel flow or group long term fuel flow;
(xi) The method of determining NO X emission rate used for the hour: default based on fuel combusted, unit specific default based on testing or historical data, group default based on representative testing of identical units, unit specific based on testing of a unit with NO X controls operating, or missing data value;
(xii) Control status of the unit; and
(xiii) Base or peak load indicator (as applicable); and
(xiv) Multiple fuel flag.
(2) Low mass emission units using the optional long term fuel flow methodology to determine unit heat input shall report for each quarter:
(i) Type of fuel;
(ii) Beginning date and hour of long term fuel flow measurement period;
(iii) End date and hour of long term fuel flow period;
(iv) Quantity of fuel measured;
(v) Units of measure;
(vi) Fuel GCV value used to calculate heat input;
(vii) Units of GCV;
(viii) Method of determining fuel GCV used;
(ix) Method of determining fuel flow over period;
(x) Monitoring-system identification code;
(xi) Quarter and year;
(xii) Total heat input (mmBtu); and
(xiii) Operating hours in period.
§ 75.59   Certification, quality assurance, and quality control record provisions.
The owner or operator shall meet all of the applicable recordkeeping requirements of this section.
(a) Continuous emission or opacity monitoring systems. The owner or operator shall record the applicable information in this section for each certified monitor or certified monitoring system (including certified backup monitors) measuring and recording emissions or flow from an affected unit.
(1) For each SO 2 or NO X pollutant concentration monitor, flow monitor, CO 2 emissions concentration monitor (including O 2 monitors used to determine CO 2 emissions), or diluent gas monitor (including wet- and dry-basis O 2 monitors used to determine percent moisture), the owner or operator shall record the following for all daily and 7-day calibration error tests, and all off-line calibration demonstrations, including any follow-up tests after corrective action:
(i) Component-system identification code (on and after January 1, 2009, only the component identification code is required);
(ii) Instrument span and span scale;
(iii) On and after April 27, 2011, date, hour, and minute;
(iv) Reference value ( i.e. , calibration gas concentration or reference signal value, in ppm or other appropriate units);
(v) Observed value (monitor response during calibration, in ppm or other appropriate units);
(vi) Percent calibration error (rounded to the nearest tenth of a percent) (flag if using alternative performance specification for low emitters or differential pressure flow monitors);
(vii) Reference signal or calibration gas level;
(viii) For 7-day calibration error tests, a test number and reason for test;
(ix) For 7-day calibration tests for certification or recertification, a certification from the cylinder gas vendor or CEMS vendor that calibration gas, as defined in § 72.2 of this chapter and appendix A to this part, was used to conduct calibration error testing;
(x) Description of any adjustments, corrective actions, or maintenance prior to a passed test or following a failed test; and
(xi) Indication of whether the unit is off-line or on-line.
(2) For each flow monitor, the owner or operator shall record the following for all daily interference checks, including any follow-up tests after corrective action.
(i) Component-system identification code (after January 1, 2009, only the component identification code is required);
(ii) Date and hour;
(iii) Code indicating whether monitor passes or fails the interference check; and
(iv) Description of any adjustments, corrective actions, or maintenance prior to a passed test or following a failed test.
(3) For each SO 2 or NO X pollutant concentration monitor, CO 2 emissions concentration monitor (including O 2 monitors used to determine CO 2 emissions), or diluent gas monitor (including wet- and dry-basis O 2 monitors used to determine percent moisture), the owner or operator shall record the following for the initial and all subsequent linearity check(s), including any follow-up tests after corrective action.
(i) Component-system identification code (on and after January 1, 2009, only the component identification code is required);
(ii) Instrument span and span scale (only span scale is required on and after January 1, 2009);
(iii) Calibration gas level;
(iv) Date and time (hour and minute) of each gas injection at each calibration gas level;
(v) Reference value ( i.e. , reference gas concentration for each gas injection at each calibration gas level, in ppm or other appropriate units);
(vi) Observed value (monitor response to each reference gas injection at each calibration gas level, in ppm or other appropriate units);
(vii) Mean of reference values and mean of measured values at each calibration gas level;
(viii) Linearity error at each of the reference gas concentrations (rounded to nearest tenth of a percent) (flag if using alternative performance specification);
(ix) Test number and reason for test (flag if aborted test); and
(x) Description of any adjustments, corrective action, or maintenance prior to a passed test or following a failed test.
(4) For each differential pressure type flow monitor, the owner or operator shall record items in paragraphs (a)(4) (i) through (v) of this section, for all quarterly leak checks, including any follow-up tests after corrective action. For each flow monitor, the owner or operator shall record items in paragraphs (a)(4) (vi) and (vii) for all flow-to-load ratio and gross heat rate tests:
(i) Component-system identification code (on and after January 1, 2009, only the system identification code is required).
(ii) Date and hour.
(iii) Reason for test.
(iv) Code indicating whether monitor passes or fails the quarterly leak check.
(v) Description of any adjustments, corrective actions, or maintenance prior to a passed test or following a failed test.
(vi) Test data from the flow-to-load ratio or gross heat rate (GHR) evaluation, including:
(A) Monitoring system identification code;
(B) Calendar year and quarter;
(C) Indication of whether the test is a flow-to-load ratio or gross heat rate evaluation;
(D) Indication of whether bias adjusted flow rates were used;
(E) Average absolute percent difference between reference ratio (or GHR) and hourly ratios (or GHR values);
(F) Test result;
(G) Number of hours used in final quarterly average;
(H) Number of hours exempted for use of a different fuel type;
(I) Number of hours exempted for load ramping up or down;
(J) Number of hours exempted for scrubber bypass;
(K) Number of hours exempted for hours preceding a normal-load flow RATA;
(L) Number of hours exempted for hours preceding a successful diagnostic test, following a documented monitor repair or major component replacement;
(M) Number of hours excluded for flue gases discharging simultaneously thorough a main stack and a bypass stack; and
(N) Test number.
(vii) Reference data for the flow-to-load ratio or gross heat rate evaluation, including (as applicable):
(A) Reference flow RATA end date and time;
(B) Test number of the reference RATA;
(C) Reference RATA load and load level;
(D) Average reference method flow rate during reference flow RATA;
(E) Reference flow/load ratio;
(F) Average reference method diluent gas concentration during flow RATA and diluent gas units of measure;
(G) Fuel specific F d -or F c -factor during flow RATA and F-factor units of measure;
(H) Reference gross heat rate value;
(I) Monitoring system identification code;
(J) Average hourly heat input rate during RATA;
(K) Average gross unit load;
(L) Operating load level; and
(M) An indicator (“flag”) if separate reference ratios are calculated for each multiple stack.
(5) For each SO 2 pollutant concentration monitor, flow monitor, each CO 2 emissions concentration monitor (including any O 2 concentration monitor used to determine CO 2 mass emissions or heat input), each NO X -diluent continuous emission monitoring system, each NO X concentration monitoring system, each diluent gas (O 2 or CO 2 ) monitor used to determine heat input, each moisture monitoring system, and each approved alternative monitoring system, the owner or operator shall record the following information for the initial and all subsequent relative accuracy test audits:
(i) Reference method(s) used.
(ii) Individual test run data from the relative accuracy test audit for the SO 2 concentration monitor, flow monitor, CO 2 emissions concentration monitor, NO X -diluent continuous emission monitoring system, diluent gas (O 2 or CO 2 ) monitor used to determine heat input, NO X concentration monitoring system, moisture monitoring system, or approved alternative monitoring system, including:
(A) Date, hour, and minute of beginning of test run;
(B) Date, hour, and minute of end of test run;
(C) Monitoring system identification code;
(D) Test number and reason for test;
(E) Operating level (low, mid, high, or normal, as appropriate) and number of operating levels comprising test;
(F) Normal load (or operating level) indicator for flow RATAs (except for peaking units);
(G) Units of measure;
(H) Run number;
(I) Run value from CEMS being tested, in the appropriate units of measure;
(J) Run value from reference method, in the appropriate units of measure;
(K) Flag value (0, 1, or 9, as appropriate) indicating whether run has been used in calculating relative accuracy and bias values or whether the test was aborted prior to completion;
(L) Average gross unit load, expressed as a total gross unit load, rounded to the nearest MWe, or as steam load, rounded to the nearest thousand lb/hr; on and after April 27, 2011, for units that do not produce electrical or thermal output, record, instead, the average stack gas velocity at the operating level being tested; and
(M) Flag to indicate whether an alternative performance specification has been used.
(iii) Calculations and tabulated results, as follows:
(A) Arithmetic mean of the monitoring system measurement values, of the reference method values, and of their differences, as specified in Equation A-7 in appendix A to this part;
(B) Standard deviation, as specified in Equation A-8 in appendix A to this part;
(C) Confidence coefficient, as specified in Equation A-9 in appendix A to this part;
(D) Statistical “t” value used in calculations;
(E) Relative accuracy test results, as specified in Equation A-10 in appendix A to this part. For multi-level flow monitor tests the relative accuracy test results shall be recorded at each load (or operating) level tested. Each load (or operating) level shall be expressed as a total gross unit load, rounded to the nearest MWe, or as steam load, rounded to the nearest thousand lb/hr, or as otherwise specified by the Administrator, for units that do not produce electrical or thermal output;
(F) Bias test results as specified in section 7.6.4 of appendix A to this part;
(G) Bias adjustment factor from Equation A-12 in appendix A to this part for any monitoring system that failed the bias test (except as otherwise provided in section 7.6.5 of appendix A to this part) and 1.000 for any monitoring system that passed the bias test; and
(H) On and after April 27, 2011, RATA frequency code.
(iv) Description of any adjustment, corrective action, or maintenance prior to a passed test or following a failed or aborted test.
(v) F-factor value(s) used to convert NO X pollutant concentration and diluent gas (O 2 or CO 2 ) concentration measurements into NO X emission rates (in lb/mmBtu), heat input or CO 2 emissions.
(vi) For flow monitors, the equation used to linearize the flow monitor and the numerical values of the polynomial coefficients or K factor(s) of that equation.
(vii) For moisture monitoring systems, the coefficient or “K” factor or other mathematical algorithm used to adjust the monitoring system with respect to the reference method.
(6) For each SO 2 , NO X , or CO 2 pollutant concentration monitor, each component of a NO X -diluent continuous emission monitoring system, and each CO 2 or O 2 monitor used to determine heat input, the owner or operator shall record the following information for the cycle time test:
(i) Component-system identification code (on and after January 1, 2009, only the component identification code is required);
(ii) Date;
(iii) Start and end times;
(iv) Upscale and downscale cycle times for each component;
(v) Stable start monitor value;
(vi) Stable end monitor value;
(vii) Reference value of calibration gas(es);
(viii) Calibration gas level;
(ix) Total cycle time;
(x) Reason for test; and
(xi) Test number.
(7) In addition to the information in paragraph (a)(5) of this section, the owner or operator shall record, for each relative accuracy test audit, supporting information sufficient to substantiate compliance with all applicable sections and appendices in this part. Unless otherwise specified in this part or in an applicable test method, the information in paragraphs (a)(7)(i) through (a)(7)(vi) of this section may be recorded either in hard copy format, electronic format or a combination of the two, and the owner or operator shall maintain this information in a format suitable for inspection and audit purposes. This RATA supporting information shall include, but shall not be limited to, the following data elements:
(i) For each RATA using Reference Method 2 (or its allowable alternatives) in appendix A to part 60 of this chapter to determine volumetric flow rate:
(A) Information indicating whether or not the location meets requirements of Method 1 in appendix A to part 60 of this chapter; and
(B) Information indicating whether or not the equipment passed the required leak checks.
(ii) For each run of each RATA using Reference Method 2 (or its allowable alternatives in appendix A to part 60 of this chapter) to determine volumetric flow rate, record the following data elements (as applicable to the measurement method used):
(A) Operating level (low, mid, high, or normal, as appropriate);
(B) Number of reference method traverse points;
(C) Average stack gas temperature (°F);
(D) Barometric pressure at test port (inches of mercury);
(E) Stack static pressure (inches of H 2 O);
(F) Absolute stack gas pressure (inches of mercury);
(G) Percent CO 2 and O 2 in the stack gas, dry basis;
(H) CO 2 and O 2 reference method used;
(I) Moisture content of stack gas (percent H 2 O);
(J) Molecular weight of stack gas, dry basis (lb/lb-mole);
(K) Molecular weight of stack gas, wet basis (lb/lb-mole);
(L) Stack diameter (or equivalent diameter) at the test port (ft);
(M) Average square root of velocity head of stack gas (inches of H 2 O) for the run;
(N) Stack or duct cross-sectional area at test port (ft 2 );
(O) Average velocity (ft/sec);
(P) Average stack flow rate, adjusted, if applicable, for wall effects (scfh, wet basis);
(Q) Flow rate reference method used;
(R) Average velocity, adjusted for wall effects;
(S) Calculated (site-specific) wall effects adjustment factor determined during the run, and, if different, the wall effects adjustment factor used in the calculations; and
(T) Default wall effects adjustment factor used.
(iii) For each traverse point of each run of each RATA using Reference Method 2 (or its allowable alternatives in appendix A to part 60 of this chapter) to determine volumetric flow rate, record the following data elements (as applicable to the measurement method used):
(A) Reference method probe type;
(B) Pressure measurement device type;
(C) Traverse point ID;
(D) Probe or pitot tube calibration coefficient;
(E) Date of latest probe or pitot tube calibration;
(F) Average velocity differential pressure at traverse point (inches of H 2 O) or the average of the square roots of the velocity differential pressures at the traverse point ((inches of H 2 O) 1/2 );
(G) T S , stack temperature at the traverse point (°F);
(H) Composite (wall effects) traverse point identifier;
(I) Number of points included in composite traverse point;
(J) Yaw angle of flow at traverse point (degrees);
(K) Pitch angle of flow at traverse point (degrees);
(L) Calculated velocity at traverse point both accounting and not accounting for wall effects (ft/sec); and
(M) Probe identification number.
(iv) For each RATA using Method 6C, 7E, or 3A in appendix A to part 60 of this chapter to determine SO 2 , NO X , CO 2 , or O 2 concentration:
(A) Pollutant or diluent gas being measured;
(B) Span of reference method analyzer;
(C) Type of reference method system (e.g., extractive or dilution type);
(D) Reference method dilution factor (dilution type systems, only);
(E) Reference gas concentrations (zero, mid, and high gas levels) used for the 3-point pre-test analyzer calibration error test (or, for dilution type reference method systems, for the 3-point pre-test system calibration error test) and for any subsequent recalibrations;
(F) Analyzer responses to the zero-, mid-, and high-level calibration gases during the 3-point pre-test analyzer (or system) calibration error test and during any subsequent recalibration(s);
(G) Analyzer calibration error at each gas level (zero, mid, and high) for the 3-point pre-test analyzer (or system) calibration error test and for any subsequent recalibration(s) (percent of span value);
(H) Upscale gas concentration (mid or high gas level) used for each pre-run or post-run system bias check or (for dilution type reference method systems) for each pre-run or post-run system calibration error check;
(I) Analyzer response to the calibration gas for each pre-run or post-run system bias (or system calibration error) check;
(J) The arithmetic average of the analyzer responses to the zero-level gas, for each pair of pre- and post-run system bias (or system calibration error) checks;
(K) The arithmetic average of the analyzer responses to the upscale calibration gas, for each pair of pre- and post-run system bias (or system calibration error) checks;
(L) The results of each pre-run and each post-run system bias (or system calibration error) check using the zero-level gas (percentage of span value);
(M) The results of each pre-run and each post-run system bias (or system calibration error) check using the upscale calibration gas (percentage of span value);
(N) Calibration drift and zero drift of analyzer during each RATA run (percentage of span value);
(O) Moisture basis of the reference method analysis;
(P) Moisture content of stack gas, in percent, during each test run (if needed to convert to moisture basis of CEMS being tested);
(Q) Unadjusted (raw) average pollutant or diluent gas concentration for each run;
(R) Average pollutant or diluent gas concentration for each run, corrected for calibration bias (or calibration error) and, if applicable, corrected for moisture;
(S) The F-factor used to convert reference method data to units of lb/mmBtu (if applicable);
(T) Date(s) of the latest analyzer interference test(s);
(U) Results of the latest analyzer interference test(s);
(V) Date of the latest NO 2 to NO conversion test (Method 7E only);
(W) Results of the latest NO 2 to NO conversion test (Method 7E only); and
(X) For each calibration gas cylinder used during each RATA, record the cylinder gas vendor, cylinder number, expiration date, pollutant(s) in the cylinder, and certified gas concentration(s).
(v) For each test run of each moisture determination using Method 4 in appendix A to part 60 of this chapter (or its allowable alternatives), whether the determination is made to support a gas RATA, to support a flow RATA, or to quality assure the data from a continuous moisture monitoring system, record the following data elements (as applicable to the moisture measurement method used):
(A) Test number;
(B) Run number;
(C) The beginning date, hour, and minute of the run;
(D) The ending date, hour, and minute of the run;
(E) Unit operating level (low, mid, high, or normal, as appropriate);
(F) Moisture measurement method;
(G) Volume of H 2 O collected in the impingers (ml);
(H) Mass of H 2 O collected in the silica gel (g);
(I) Dry gas meter calibration factor;
(J) Average dry gas meter temperature (°F);
(K) Barometric pressure (inches of mercury);
(L) Differential pressure across the orifice meter (inches of H 2 O);
(M) Initial and final dry gas meter readings (ft 3 );
(N) Total sample gas volume, corrected to standard conditions (dscf); and
(O) Percentage of moisture in the stack gas (percent H 2 O).
(vi) The raw data and calculated results for any stratification tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 of appendix A to this part.
(vii) [Reserved]
(viii) [Reserved]
(ix) For a unit with a flow monitor installed on a rectangular stack or duct, if a site-specific default or measured wall effects adjustment factor (WAF) is used to correct the stack gas volumetric flow rate data to account for velocity decay near the stack or duct wall, the owner or operator shall keep records of the following for each flow RATA performed with EPA Method 2 in appendices A-1 and A-2 to part 60 of this chapter, subsequent to the WAF determination:
(A) Monitoring system ID;
(B) Test number;
(C) Operating level;
(D) RATA end date and time;
(E) Number of Method 1 traverse points; and
(F) Wall effects adjustment factor (WAF), to the nearest 0.0001.
(8) For each certified continuous emission monitoring system, continuous opacity monitoring system, excepted monitoring system, or alternative monitoring system, the date and description of each event which requires certification, recertification, or certain diagnostic testing of the system and the date and type of each test performed. If the conditional data validation procedures of § 75.20(b)(3) are to be used to validate and report data prior to the completion of the required certification, recertification, or diagnostic testing, the date and hour of the probationary calibration error test shall be reported to mark the beginning of conditional data validation.
(9) When hardcopy relative accuracy test reports, certification reports, recertification reports, or semiannual or annual reports for gas or flow rate CEMS are required or requested under § 75.60(b)(6) or § 75.63, the reports shall include, at a minimum, the following elements (as applicable to the type(s) of test(s) performed):
(i) Summarized test results.
(ii) DAHS printouts of the CEMS data generated during the calibration error, linearity, cycle time, and relative accuracy tests.
(iii) For pollutant concentration monitor or diluent monitor relative accuracy tests at normal operating load:
(A) The raw reference method data from each run, i.e., the data under paragraph (a)(7)(iv)(Q) of this section (usually in the form of a computerized printout, showing a series of one-minute readings and the run average);
(B) The raw data and results for all required pre-test, post-test, pre-run and post-run quality assurance checks ( i.e. , calibration gas injections) of the reference method analyzers, i.e., the data under paragraphs (a)(7)(iv)(E) through (a)(7)(iv)(N) of this section;
(C) The raw data and results for any moisture measurements made during the relative accuracy testing, i.e., the data under paragraphs (a)(7)(v)(A) through (a)(7)(v)(O) of this section; and
(D) Tabulated, final, corrected reference method run data ( i.e. , the actual values used in the relative accuracy calculations), along with the equations used to convert the raw data to the final values and example calculations to demonstrate how the test data were reduced.
(iv) For relative accuracy tests for flow monitors:
(A) The raw flow rate reference method data, from Reference Method 2 (or its allowable alternatives) under appendix A to part 60 of this chapter, including auxiliary moisture data (often in the form of handwritten data sheets), i.e., the data under paragraphs (a)(7)(ii)(A) through (a)(7)(ii)(T), paragraphs (a)(7)(iii)(A) through (a)(7)(iii)(M), and, if applicable, paragraphs (a)(7)(v)(A) through (a)(7)(v)(O) of this section; and
(B) The tabulated, final volumetric flow rate values used in the relative accuracy calculations (determined from the flow rate reference method data and other necessary measurements, such as moisture, stack temperature and pressure), along with the equations used to convert the raw data to the final values and example calculations to demonstrate how the test data were reduced.
(v) Calibration gas certificates for the gases used in the linearity, calibration error, and cycle time tests and for the calibration gases used to quality assure the gas monitor reference method data during the relative accuracy test audit.
(vi) Laboratory calibrations of the source sampling equipment.
(vii) A copy of the test protocol used for the CEMS certifications or recertifications, including narrative that explains any testing abnormalities, problematic sampling, and analytical conditions that required a change to the test protocol, and/or solutions to technical problems encountered during the testing program.
(viii) Diagrams illustrating test locations and sample point locations (to verify that locations are consistent with information in the monitoring plan). Include a discussion of any special traversing or measurement scheme. The discussion shall also confirm that sample points satisfy applicable acceptance criteria.
(ix) Names of key personnel involved in the test program, including test team members, plant contacts, agency representatives and test observers on site.
(x) For testing involving use of EPA Protocol gases, the owner or operator shall record in electronic and hardcopy format the following information, as applicable:
(A) On and after September 26, 2011, for each gas monitor, for both low and high measurement ranges, record the following information for the mid-level or high-level EPA Protocol gas (as applicable) that is used for daily calibration error tests, and the low-, mid-, and high-level gases used for quarterly linearity checks. For O 2 , if purified air is used as the high-level gas for daily calibrations or linearity checks, record the following information for the low- and mid-level EPA Protocol gas used for linearity checks, instead:
( 1 ) Gas level code;
( 2 ) A code for the type of EPA Protocol gas used;
( 3 ) The PGVP vendor ID issued by EPA for the EPA Protocol gas production site that supplied the EPA Protocol gas cylinder;
( 4 ) The expiration date for the EPA Protocol gas cylinder; and
( 5 ) The cylinder number.
(B) On and after September 26, 2011, for each usage of Reference Method 3A in appendix A-2 to part 60 of this chapter, or Method 6C or 7E in appendix A-4 to part 60 of this chapter performed using EPA Protocol gas for the certification, recertification, routine quality assurance or diagnostic testing (reportable diagnostics, only) of a Part 75 monitoring system, record the information required by paragraphs (a)(9)(x)(A)( 1 ) through ( 5 ) of this section.
(xi) On and after March 27, 2012, for all RATAs performed pursuant to § 75.74(c)(2)(ii), section 6.5 of appendix A to this part and section 2.3.1 of appendix B to this part, and for all NO X emission testing performed pursuant to section 2.1 of appendix E to this part, or § 75.19(c)(1)(iv), the owner or operator shall record the following information as provided by the AETB:
(A) The name, telephone number and e-mail address of the Air Emission Testing Body;
(B) The name of each on-site Qualified Individual, as defined in § 72.2 of this chapter;
(C) For the reference method(s) that were performed, the date(s) that each on-site Qualified Individual took and passed the relevant qualification exam(s) required by ASTM D7036-04 (incorporated by reference, see § 75.6); and
(D) The name and e-mail address of each qualification exam provider.
(10) Whenever reference methods are used as backup monitoring systems pursuant to § 75.20(d)(3), the owner or operator shall record the following information:
(i) For each test run using Reference Method 2 (or its allowable alternatives in appendix A to part 60 of this chapter) to determine volumetric flow rate, record the following data elements (as applicable to the measurement method used):
(A) Unit or stack identification number;
(B) Reference method system and component identification numbers;
(C) Run date and hour;
(D) The data in paragraph (a)(7)(ii) of this section, except for paragraphs (a)(7)(ii)(A), (F), (H), (L) and (Q) through (T); and
(E) The data in paragraph (a)(7)(iii), except on a run basis.
(ii) For each reference method test run using Method 6C, 7E, or 3A in appendix A to part 60 of this chapter to determine SO 2 , NO X , CO 2 , or O 2 concentration:
(A) Unit or stack identification number;
(B) The reference method system and component identification numbers;
(C) Run number;
(D) Run start date and hour;
(E) Run end date and hour;
(F) The data in paragraphs (a)(7)(iv)(B) through (I) and (L) through (O); and (G) Stack gas density adjustment factor (if applicable).
(iii) For each hour of each reference method test run using Method 6C, 7E, or 3A in appendix A to part 60 of this chapter to determine SO 2 , NO X , CO 2 , or O 2 concentration:
(A) Unit or stack identification number;
(B) The reference method system and component identification numbers;
(C) Run number;
(D) Run date and hour;
(E) Pollutant or diluent gas being measured;
(F) Unadjusted (raw) average pollutant or diluent gas concentration for the hour; and
(G) Average pollutant or diluent gas concentration for the hour, adjusted as appropriate for moisture, calibration bias (or calibration error) and stack gas density.
(11) For each other quality-assurance test or other quality assurance activity, the owner or operator shall record the following (as applicable):
(i) Component/system identification code;
(ii) Parameter;
(iii) Test or activity completion date and hour;
(iv) Test or activity description;
(v) Test result;
(vi) Reason for test; and
(vii) Test code.
(12) For each request for a quality assurance test extension or exemption, for any loss of exempt status, and for each single-load flow RATA claim pursuant to section 2.3.1.3(c)(3) of appendix B to this part, the owner or operator shall record the following (as applicable):
(i) For a RATA deadline extension or exemption request:
(A) Monitoring system identification code;
(B) Date of last RATA;
(C) RATA expiration date without extension;
(D) RATA expiration date with extension;
(E) Type of RATA extension of exemption claimed or lost;
(F) Year to date hours of usage of fuel other than very low sulfur fuel;
(G) Year to date hours of non-redundant back-up CEMS usage at the unit/stack; and
(H) Quarter and year.
(ii) For a linearity test or flow-to-load ratio test quarterly exemption:
(A) Component-system identification code;
(B) Type of test;
(C) Basis for exemption;
(D) Quarter and year; and
(E) Span scale.
(iii) [Reserved]
(iv) For a fuel flowmeter accuracy test extension:
(A) Component-system identification code;
(B) Date of last accuracy test;
(C) Accuracy test expiration date without extension;
(D) Accuracy test expiration date with extension;
(E) Type of extension;
(F) Quarter and year; and
(G) On and after April 27, 2011, fuel code for Ozone Season Only reporters under § 75.74(c).
(v) For a single-load (or single-level) flow RATA claim:
(A) Monitoring system identification code;
(B) Ending date of last annual flow RATA;
(C) The relative frequency (percentage) of unit or stack operation at each load (or operating) level (low, mid, and high) since the previous annual flow RATA, to the nearest 0.1 percent;
(D) End date of the historical load (or operating level) data collection period; and
(E) Indication of the load (or operating) level (low, mid or high) claimed for the single-load flow RATA.
(13) An indication that data have been excluded from a periodic span and range evaluation of an SO 2 or NO X monitor under section 2.1.1.5 or 2.1.2.5 of appendix A to this part and the reason(s) for excluding the data. For purposes of reporting under § 75.64(a), this information shall be reported with the quarterly report as descriptive text consistent with § 75.64(g).
(14) [Reserved]
(15) On and after March 27, 2012, for all RATAs 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, the owner or operator shall record in electronic format the following information as provided by the AETB:
(i) The name, telephone number and e-mail address of the Air Emission Testing Body;
(ii) The name of each on-site Qualified Individual, as defined in § 72.2 of this chapter;
(iii) For the reference method(s) that were performed, the date(s) that each on-site Qualified Individual took and passed the relevant qualification exam(s) required by ASTM D7036-04 (incorporated by reference, see § 75.6); and
(iv) The name and e-mail address of each qualification exam provider.
(b) Excepted monitoring systems for gas-fired and oil-fired units. The owner or operator shall record the applicable information in this section for each excepted monitoring system following the requirements of appendix D to this part or appendix E to this part for determining and recording emissions from an affected unit.
(1) For certification and quality assurance testing of fuel flowmeters tested against a reference fuel flow rate ( i.e. , flow rate from another fuel flowmeter under section 2.1.5.2 of appendix D to this part or flow rate from a procedure according to a standard incorporated by reference under section 2.1.5.1 of appendix D to this part):
(i) Unit or common pipe header identification code;
(ii) Component and system identification codes of the fuel flowmeter being tested (on and after January 1, 2009, only the component identification code is required);
(iii) Date and hour of test completion, for a test performed in-line at the unit;
(iv) Date and hour of flowmeter reinstallation, for laboratory tests;
(v) Test number;
(vi) Upper range value of the fuel flowmeter;
(vii) Flowmeter measurements during accuracy test (and mean of values), including units of measure;
(viii) Reference flow rates during accuracy test (and mean of values), including units of measure;
(ix) Level of fuel flowrate test during runs (low, mid or high);
(x) Average flowmeter accuracy for low and high fuel flowrates and highest flowmeter accuracy of any level designated as mid, expressed as a percent of upper range value;
(xi) Indicator of whether test method was a lab comparison to reference meter or an in-line comparison against a master meter;
(xii) Test result (aborted, pass, or fail); and
(xiii) Description of fuel flowmeter calibration specification or procedure (in the certification application, or periodically if a different method is used for annual quality assurance testing).
(2) For each transmitter or transducer accuracy test for an orifice-, nozzle-, or venturi-type flowmeter used under section 2.1.6 of appendix D to this part:
(i) Component and system identification codes of the fuel flowmeter being tested (on and after January 1, 2009, only the component identification code is required);
(ii) Completion date and hour of test;
(iii) For each transmitter or transducer: transmitter or transducer type (differential pressure, static pressure, or temperature); the full-scale value of the transmitter or transducer, transmitter input (pre-calibration) prior to accuracy test, including units of measure; and expected transmitter output during accuracy test (reference value from NIST-traceable equipment), including units of measure;
(iv) For each transmitter or transducer tested: output during accuracy test, including units of measure; transmitter or transducer accuracy as a percent of the full-scale value; and transmitter output level as a percent of the full-scale value;
(v) Average flowmeter accuracy at low and high level fuel flowrates and highest flowmeter accuracy of any level designated as mid fuel flowrate, expressed as a percent of upper range value;
(vi) Test result (pass, fail, or aborted);
(vii) Test number; and
(viii) Accuracy determination methodology.
(3) For each visual inspection of the primary element or transmitter or transducer accuracy test for an
(i) Date of inspection/test;
(ii) Hour of completion of inspection/test;
(iii) Component and system identification codes of the fuel flowmeter being inspected/tested; and
(iv) Results of inspection/test (pass or fail).
(4) For fuel flowmeters that are tested using the optional fuel flow-to-load ratio procedures of section 2.1.7 of appendix D to this part:
(i) Test data for the fuel flowmeter flow-to-load ratio or gross heat rate check, including:
(A) Component/system identification code (on and after January 1, 2009, only the monitoring system identification code is required);
(B) Calendar year and quarter;
(C) Indication of whether the test is for fuel flow-to-load ratio or gross heat rate;
(D) Quarterly average absolute percent difference between baseline for fuel flow-to-load ratio (or baseline gross heat rate and hourly quarterly fuel flow-to-load ratios (or gross heat rate value);
(E) Test result;
(F) Number of hours used in the analysis;
(G) Number of hours excluded due to co-firing;
(H) Number of hours excluded due to ramping;
(I) Number of hours excluded in lower 25.0 percent range of operation; and
(J) Test number.
(ii) Reference data for the fuel flowmeter flow-to-load ratio or gross heat rate evaluation, including:
(A) Completion date and hour of most recent primary element inspection or test number of the most recent primary element inspection (as applicable); (on and after January 1, 2009, the test number of the most recent primary element inspection is required in lieu of the completion date and hour for the most recent primary element inspection);
(B) Completion date and hour of most recent flow meter of transmitter accuracy test or test number of the most recent flowmeter or transmitter accuracy test (as applicable); (on and after January 1, 2009, the test number of the most recent flowmeter or transmitter accuracy test is required in lieu of the completion date and hour for the most recent flowmeter or transmitter accuracy test);
(C) Beginning date and hour of baseline period;
(D) Completion date and hour of baseline period;
(E) Average fuel flow rate, in 100 scfh for gas and lb/hr for oil;
(F) Average load, in megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output;
(G) Baseline fuel flow-to-load ratio, in the appropriate units of measure (if using fuel flow-to-load ratio);
(H) Baseline gross heat rate if using gross heat rate, in the appropriate units of measure (if using gross heat rate check);
(I) Number of hours excluded from baseline data due to ramping;
(J) Number of hours excluded from baseline data in lower 25.0 percent of range of operation;
(K) Average hourly heat input rate;
(L) Flag indicating baseline data collection is in progress and that fewer than four calendar quarters have elapsed since the quarter of the last flowmeter QA test;
(M) Number of hours excluded due to co-firing; and
(N) Monitoring system identification code.
(5) For gas-fired peaking units or oil-fired peaking units using the optional procedures of appendix E to this part, for each initial performance, periodic, or quality assurance/quality control-related test:
(i) For each run of emission data, record the following data:
(A) Unit or common pipe identification code;
(B) Monitoring system identification code for appendix E system (on and after January 1, 2009, component identification codes shall be reported in addition to the monitoring system identification code);
(C) Run start date and time;
(D) Run end date and time;
(E) Total heat input during the run (mmBtu);
(F) NO X emission rate (lb/mmBtu) from reference method;
(G) Response time of the O 2 and NO X reference method analyzers;
(H) Type of fuel(s) combusted during the run. This requirement remains in effect through December 31, 2008;
(I) Heat input rate (mmBtu/hr) during the run;
(J) Test number;
(K) Run number;
(L) Operating level during the run;
(M) NO X concentration recorded by the reference method during the run;
(N) Diluent concentration recorded by the reference method during the run; and
(O) Moisture measurement for the run (if applicable).
(ii) For each run during which oil or mixed fuels are combusted record the following data:
(A) Unit or common pipe identification code;
(B) Monitoring system identification code for oil monitoring system (on and after January 1, 2009, component identification codes shall be reported in addition to the monitoring system identification code);
(C) Run start date and time;
(D) Run end date and time;
(E) Mass flow or volumetric flow of oil, in the units of measure for the type of fuel flowmeter;
(F) Gross calorific value of oil in the appropriate units of measure;
(G) Density of fuel oil in the appropriate units of measure (if density is used to convert oil volume to mass);
(H) Hourly heat input (mmBtu) during run from oil;
(I) Test number;
(J) Run number; and
(K) Operating level during the run.
(iii) For each run during which gas or mixed fuels are combusted record the following data:
(A) Unit or common pipe identification code;
(B) Monitoring system identification code for gas monitoring system (on and after January 1, 2009, component identification codes shall be reported in addition to the monitoring system identification code);
(C) Run start date and time;
(D) Run end date and time;
(E) Volumetric flow of gas (100 scf);
(F) Gross calorific value of gas (Btu/100 scf);
(G) Hourly heat input (mmBtu) during run from gas;
(H) Test number;
(I) Run number; and
(J) Operating level during the run.
(iv) For each operating level at which runs were performed:
(A) Completion date and time of last run for operating level (as applicable). This requirement remains in effect through December 31, 2008;
(B) Type of fuel(s) combusted during test;
(C) Average heat input rate at that operating level (mmBtu/hr);
(D) Arithmetic mean of NO X emission rates from reference method run at this level;
(E) F-factor used in calculations of NO X emission rate at that operating level;
(F) Unit operating parametric data related to NO X formation for that unit type (e.g., excess O 2 level, water/fuel ratio);
(G) Test number;
(H) Operating level for runs; and
(I) Component identification code (required on and after January 1, 2009).
(6) On and after March 27, 2012, for all stack testing performed pursuant to section 2.1 of appendix E to this part, the owner or operator shall record in electronic format the following information as provided by the AETB:
(i) The name, telephone number and e-mail address of the Air Emission Testing Body;
(ii) The name of each on-site Qualified Individual, as defined in § 72.2 of this chapter;
(iii) For the reference method(s) that were performed, the date(s) that each on-site Qualified Individual took and passed the relevant qualification exam(s) required by ASTM D7036-04 (incorporated by reference, see § 75.6); and
(iv) The name and e-mail address of each qualification exam provider.
(c) Except as otherwise provided in § 75.58(b)(3)(i), for units with add-on SO 2 or NO X emission controls following the provisions of § 75.34(a)(1) or (a)(2), the owner or operator shall keep the following records on-site in the quality assurance/quality control plan required by section 1 of appendix B to this part:
(1) A list of operating parameters for the add-on emission controls, including parameters in § 75.58(b), appropriate to the particular installation of add-on emission controls; and
(2) The range of each operating parameter in the list that indicates the add-on emission controls are properly operating.
(d) Excepted monitoring for low mass emissions units under § 75.19(c)(1)(iv). For oil-and gas-fired units using the optional SO 2 , NO X and CO 2 emissions calculations for low mass emission units under § 75.19, the owner or operator shall record the following information for tests performed to determine a fuel and unit-specific default as provided in § 75.19(c)(1)(iv):
(1) For each run of each test performed using the procedures of section 2.1 of appendix E to this part, record the following data:
(i) Unit or common pipe identification code;
(ii) Run start date and time;
(iii) Run end date and time;
(iv) NO X emission rate (lb/mmBtu) from reference method;
(v) Response time of the O 2 and NO X reference method analyzers;
(vi) Type of fuel(s) combusted during the run;
(vii) Test number;
(viii) Run number;
(ix) Operating level during the run;
(x) NO X concentration recorded by the reference method during the run;
(xi) Diluent concentration recorded by the reference method during the run;
(xii) Moisture measurement for the run (if applicable); and
(xiii) An indicator (“flag”) if the run is used to calculate the highest 3-run average NO X emission rate at any load level.
(2) For each single-load or multiple-load appendix E test, record the following:
(i) The three-run average NO X emission rate for each load level;
(ii) An indicator that the average NO X emission rate is the highest NO X average emission rate recorded at any load level of the test (if appropriate);
(iii) The default NO X emission rate (highest three-run average NO X emission rate at any load level);
(iv) An indicator that the add-on NO X emission controls were operating or not operating during each run of the test;
(v) Parameter data indicating the use and efficacy of control equipment during the test; and
(vi) Indicator of whether the testing was done at base load, peak load or both (if appropriate); and
(vii) The default NO X emission rate for peak load hours (if applicable).
(3) For each unit in a group of identical units qualifying for reduced testing under § 75.19(c)(1)(iv)(B), record the following data:
(i) The unique group identification code assigned to the group. This code must include the ORIS code of one of the units in the group;
(ii) The ORIS code or facility identification code for the unit;
(iii) The plant name of the facility at which the unit is located, consistent with the facility's monitoring plan;
(iv) The identification code for the unit, consistent with the facility's monitoring plan;
(v) A record of whether or not the unit underwent fuel and unit-specific testing for purposes of establishing a fuel and unit-specific NO X emission rate for purposes of § 75.19;
(vi) The completion date of the fuel and unit-specific test performed for purposes of establishing a fuel and unit-specific NO X emission rate for purposes of § 75.19;
(vii) The fuel and unit-specific NO X default rate established for the group of identical units under § 75.19;
(viii) The type of fuel combusted for the units during testing and represented by the resulting default NO X emission rate;
(ix) The control status for the units during testing and represented by the resulting default NO X emission rate;
(x) Documentation supporting the qualification of all units in the group for reduced testing, in accordance with the criteria established in § 75.19(c)(1)(iv)(B)( 1 );
(xi) Purpose of group tests;
(xii) On and after April 27, 2011, the number of tests for group; and
(xiii) On and after April 27, 2011, the number of units in group.
(4) On and after March 27, 2012, for all NO X emission testing performed pursuant to § 75.19(c)(1)(iv), the owner or operator shall record in electronic format the following information as provided by the AETB:
(i) The name, telephone number and e-mail address of the Air Emission Testing Body;
(ii) The name of each on-site Qualified Individual, as defined in § 72.2 of this chapter;
(iii) For the reference method(s) that were performed, the date(s) that each on-site Qualified Individual took and passed the relevant qualification exam(s) required by ASTM D7036-04 (incorporated by reference, see § 75.6); and
(iv) The name and e-mail address of each qualification exam provider.
(e) DAHS Verification. For each DAHS (missing data and formula) verification that is required for initial certification, recertification, or for certain diagnostic testing of a monitoring system, record the date and hour that the DAHS verification is successfully completed. (This requirement only applies to units that report monitoring plan data in accordance with § 75.53(g) and (h).)
§ 75.60   General provisions.
(a) The designated representative for any affected unit subject to the requirements of this part shall comply with all reporting requirements in this section and with the signatory requirements of § 72.21 of this chapter for all submissions.
(b) Submissions. The designated representative shall submit all reports and petitions (except as provided in § 75.61) as follows:
(1) Initial certifications. The designated representative shall submit initial certification applications according to § 75.63.
(2) Recertifications. The designated representative shall submit recertification applications according to § 75.63.
(3) Monitoring plans. The designated representative shall submit monitoring plans according to § 75.62.
(4) Electronic quarterly reports. The designated representative shall submit electronic quarterly reports according to § 75.64.
(5) Other petitions and communications. The designated representative shall submit petitions, correspondence, application forms, designated representative signature, and petition-related test results in hardcopy to the Administrator. Additional petition requirements are specified in §§ 75.66 and 75.67.
(6) Semiannual or annual RATA reports. If requested in writing (or by electronic mail) by the applicable EPA Regional Office, appropriate State, and/or appropriate local air pollution control agency, the designated representative shall submit a hardcopy RATA report within 45 days after completing a required semiannual or annual RATA according to section 2.3.1 of appendix B to this part, or within 15 days of receiving the request, whichever is later. The designated representative shall report the hardcopy information required by § 75.59(a)(9) to the applicable EPA Regional Office, appropriate State, and/or appropriate local air pollution control agency that requested the RATA report.
(7) Routine appendix E retest reports. If requested in writing (or by electronic mail) by the applicable EPA Regional Office, appropriate State, and/or appropriate local air pollution control agency, the designated representative shall submit a hardcopy report within 45 days after completing a required periodic retest according to section 2.2 of appendix E to this part, or within 15 days of receiving the request, whichever is later. The designated representative shall report the hardcopy information required by § 75.59(b)(5) to the applicable EPA Regional Office, appropriate State, and/or appropriate local air pollution control agency that requested the hardcopy report.
(c) Confidentiality of data. The following provisions shall govern the confidentiality of information submitted under this part.
(1) All emission data reported in quarterly reports under § 75.64 shall remain public information.
(2) For information submitted under this part other than emission data submitted in quarterly reports, the designated representative must assert a claim of confidentiality at the time of submission for any information he or she wishes to have treated as confidential business information (CBI) under subpart B of part 2 of this chapter. Failure to assert a claim of confidentiality at the time of submission may result in disclosure of the information by EPA without further notice to the designated representative.
(3) Any claim of confidentiality for information submitted in quarterly reports under § 75.64 must include substantiation of the claim. Failure to provide substantiation may result in disclosure of the information by EPA without further notice.
(4) As provided under subpart B of part 2 of this chapter, EPA may review information submitted to determine whether it is entitled to confidential treatment even when confidentiality claims are initially received. The EPA will contact the designated representative as part of such a review process.
§ 75.61   Notifications.
(a) Submission. The designated representative for an affected unit (or owner or operator, as specified) shall submit notice to the Administrator, to the appropriate EPA Regional Office, and to the applicable State and local air pollution control agencies for the following purposes, as required by this part.
(1) Initial certification and recertification test notifications. The owner or operator or designated representative for an affected unit shall submit written notification of initial certification tests and revised test dates as specified in § 75.20 for continuous emission monitoring systems, for alternative monitoring systems under subpart E of this part, or for excepted monitoring systems under appendix E to this part, except as provided in paragraphs (a)(1)(iii), (a)(1)(iv) and (a)(4) of this section. The owner or operator shall also provide written notification of testing performed under § 75.19(c)(1)(iv)(A) to establish fuel-and-unit-specific NO X emission rates for low mass emissions units. Such notifications are not required, however, for initial certifications and recertifications of excepted monitoring systems under appendix D to this part.
(i) Notification of initial certification testing and full recertification. Initial certification test notifications and notifications of full recertification testing under § 75.20(b)(2) shall be submitted not later than 21 days prior to the first scheduled day of certification or recertification testing. In emergency situations when full recertification testing is required following an uncontrollable failure of equipment that results in lost data, notice shall be sufficient if provided within 2 business days following the date when testing is scheduled. Testing may be performed on a date other than that already provided in a notice under this subparagraph as long as notice of the new date is provided either in writing or by telephone or other means at least 7 days prior to the original scheduled test date or the revised test date, whichever is earlier.
(ii) Notification of certification retesting, and partial recertification testing. For retesting required following a loss of certification under § 75.20(a)(5) or for partial recertification testing required under § 75.20(b)(2), notice of the date of any required RATA testing or any requred retesting under section 2.3 in appendix E to this part shall be submitted either in writing or by telephone at least 7 days prior to the first scheduled day of testing; except that in emergency situations when testing is required following an uncontrollable failure of equipment that results in lost data, notice shall be sufficient if provided within 2 business days following the date when testing is scheduled. Testing may be performed on a date other than that already provided in a notice under this subparagraph as long as notice of the new date is provided by telephone or other means at least 2 business days prior to the original scheduled test date or the revised test date, whichever is earlier.
(iii) Repeat of testing without notice. Notwithstanding the above notice requirements, the owner or operator may elect to repeat a certification or recertification test immediately, without advance notification, whenever the owner or operator has determined during the certification or recertification testing that a test was failed or must be aborted, or that a second test is necessary in order to attain a reduced relative accuracy test frequency.
(iv) Waiver from notification requirements. The Administrator, the appropriate EPA Regional Office, or the applicable State or local air pollution control agency may issue a waiver from the notification requirement of paragraph (a)(1)(ii) of this section, for a unit or a group of units, for one or more recertification tests or other retests. The Administrator, the appropriate EPA Regional Office, or the applicable State or local air pollution control agency may also discontinue the waiver and reinstate the notification requirement of paragraph (a)(1)(ii) of this section for future recertification tests (or other retests) of a unit or a group of units.
(2) New unit, newly affected unit, new stack, or new flue gas desulfurization system operation notification. The designated representative for an affected unit shall submit written notification: For a new unit or a newly affected unit, of the planned date when a new unit or newly affected unit will commence commercial operation, or becomes affected, or, for new stack or flue gas desulfurization system, of the planned date when a new stack or flue gas desulfurization system will be completed and emissions will first exit to the atmosphere.
(i) Notification of the planned date shall be submitted not later than 45 days prior to the date the unit commences commercial operation or becomes affected, or not later than 45 days prior to the date when a new stack or flue gas desulfurization system exhausts emissions to the atmosphere.
(ii) If the date when the unit commences commercial operation or becomes affected, or the date when the new stack or flue gas desulfurization system exhausts emissions to the atmosphere, whichever is applicable, changes from the planned date, a notification of the actual date shall be submitted not later than 7 days following: The date the unit commences commercial operation or becomes affected, or the date when a new stack or flue gas desulfurization system exhausts emissions to the atmosphere.
(3) Unit shutdown and recommencement of commercial operation. For an affected unit that will be shut down on the relevant compliance date specified in § 75.4 or in a State or Federal pollutant mass emissions reduction program that adopts the monitoring and reporting requirements of this part, if the owner or operator is relying on the provisions in § 75.4(d) to postpone certification testing, the designated representative for the unit shall submit notification of unit shutdown and recommencement of commercial operation as follows:
(i) For planned unit shutdowns (e.g., extended maintenance outages), written notification of the planned shutdown date shall be provided at least 21 days prior to the applicable compliance date, and written notification of the planned date of recommencement of commercial operation shall be provided at least 21 days in advance of unit restart. If the actual shutdown date or the actual date of recommencement of commercial operation differs from the planned date, written notice of the actual date shall be submitted no later than 7 days following the actual date of shutdown or of recommencement of commercial operation, as applicable;
(ii) For unplanned unit shutdowns (e.g., forced outages), written notification of the actual shutdown date shall be provided no more than 7 days after the shutdown, and written notification of the planned date of recommencement of commercial operation shall be provided at least 21 days in advance of unit restart. If the actual date of recommencement of commercial operation differs from the expected date, written notice of the actual date shall be submitted no later than 7 days following the actual date of recommencement of commercial operation.
(4) Use of backup fuels for appendix E procedures. The designated representative for an affected oil-fired or gas-fired peaking unit that is using an excepted monitoring system under appendix E of this part and that is relying on the provisions in § 75.4(f) to postpone testing of a fuel shall submit written notification of that fact no later than 45 days prior to the deadline in § 75.4. The designated representative shall also submit a notification that such a fuel has been combusted no later than 7 days after the first date of combustion of any fuel for which testing has not been performed under appendix E after the deadline in § 75.4. Such notice shall also include notice that testing under appendix E either was performed during the initial combustion or notice of the date that testing will be performed.
(5) Periodic relative accuracy test audits, appendix E retests, and low mass emissions unit retests. The owner or operator or designated representative of an affected unit shall submit written notice of the date of periodic relative accuracy testing performed under section 2.3.1 of appendix B to this part, of periodic retesting performed under section 2.2 of appendix E to this part, and of periodic retesting of low mass emissions units performed under § 75.19(c)(1)(iv)(D), no later than 21 days prior to the first scheduled day of testing. Testing may be performed on a date other than that already provided in a notice under this subparagraph as long as notice of the new date is provided either in writing or by telephone or other means acceptable to the respective State agency or office of EPA, and the notice is provided as soon as practicable after the new testing date is known, but no later than twenty-four (24) hours in advance of the new date of testing.
(i) Written notification under paragraph (a) (5) of this section may be provided either by mail or by facsimile. In addition, written notification may be provided by electronic mail, provided that the respective State agency or office of EPA agrees that this is an acceptable form of notification.
(ii) Notwithstanding the notice requirements under paragraph (a)(5) of this section, the owner or operator may elect to repeat a periodic relative accuracy test, appendix E restest, or low mass emissions unit retest immediately, without additional notification whenever the owner or operator has determined that a test was failed, or that a second test is necessary in order to attain a reduced relative accuracy test frequency.
(iii) Waiver from notification requirements. The Administrator, the appropriate EPA Regional Office, or the applicable State air pollution control agency may issue a waiver from the requirement of paragraph (a)(5) of this section to provide notice to the respective State agency or office of EPA for a unit or a group of units for one or more tests. The Administrator, the appropriate EPA Regional Office, or the applicable State air pollution control agency may also discontinue the waiver and reinstate the requirement of paragraph (a)(5) of this section to provide notice to the respective State agency or office of EPA for future tests for a unit or a group of units. In addition, if an observer from a State agency or EPA is present when a test is rescheduled, the observer may waive all notification requirements under paragraph (a)(5) of this section for the rescheduled test.
(6) Notice of combustion of emergency fuel under appendix D or E. The designated representative of an oil-fired unit or gas-fired unit using appendix D or E of this part shall, for each calendar quarter in which emergency fuel is combusted, provide notice of the combustion of the emergency fuel in the cover letter (or electronic equivalent) which transmits the next quarterly report submitted under § 75.64. The notice shall specify the exact dates and hours during which the emergency fuel was combusted.
(7) Long-term cold storage and recommencement of commercial operation. The designated representative for an affected unit that is placed into long-term cold storage that is relying on the provisions in § 75.4(d) or § 75.64(a), either to postpone certification testing or to discontinue the submittal of quarterly reports during the period of long-term cold storage, shall provide written notification of long-term cold storage status and recommencement of commercial operation as follows:
(i) Whenever an affected unit has been placed into long-term cold storage, written notification of the date and hour that the unit was shutdown and a statement from the designated representative stating that the shutdown is expected to last for at least two years from that date, in accordance with the definition for long-term cold storage of a unit as provided in § 72.2 of this chapter.
(ii) Whenever an affected unit that has been placed into long-term cold storage is expected to resume operation, written notification shall be submitted 45 calendar days prior to the planned date of recommencement of commercial operation. If the actual date of recommencement of commercial operation differs from the expected date, written notice of the actual date shall be submitted no later than 7 days following the actual date of recommencement of commercial operation.
(8) Certification deadline date for new or newly affected units. The designated representative of a new or newly affected unit shall provide notification of the date on which the relevant deadline for initial certification is reached, either as provided in § 75.4(b) or § 75.4(c), or as specified in a State or Federal SO 2 or NO X mass emission reduction program that incorporates by reference, or otherwise adopts, the monitoring, recordkeeping, and reporting requirements of subpart F, G, or H of this part. The notification shall be submitted no later than 7 calendar days after the applicable certification deadline is reached.
(b) The owner or operator or designated representative shall submit notification of certification tests and recertification tests for continuous opacity monitoring systems as specified in § 75.20(c)(8) to the State or local air pollution control agency.
(c) If the Administrator determines that notification substantially similar to that required in this section is required by any other State or local agency, the owner or operator or designated representative may send the Administrator a copy of that notification to satisfy the requirements of this section, provided the ORISPL unit identification number(s) is denoted.
§ 75.62   Monitoring plan submittals.
(a) Submission —(1) Electronic. Using the format specified in paragraph (c) of this section, the designated representative for an affected unit shall submit a complete, electronic, up-to-date monitoring plan file (except for hardcopy portions identified in paragraph (a)(2) of this section) to the Administrator as follows: no later than 21 days prior to the initial certification tests; at the time of each certification or recertification application submission; and (prior to or concurrent with) the submittal of the electronic quarterly report for a reporting quarter where an update of the electronic monitoring plan information is required, either under § 75.53(b) or elsewhere in this part.
(2) Hardcopy. The designated representative shall submit all of the hardcopy information required under § 75.53 to the appropriate EPA Regional Office and the appropriate State and/or local air pollution control agency prior to initial certification. Thereafter, the designated representative shall submit hardcopy information only if that portion of the monitoring plan is revised. The designated representative shall submit the required hardcopy information as follows: no later than 21 days prior to the initial certification test; with any certification or recertification application, if a hardcopy monitoring plan change is associated with the certification or recertification event; and within 30 days of any other event with which a hardcopy monitoring plan change is associated, pursuant to § 75.53(b). Electronic submittal of all monitoring plan information, including hardcopy portions, is permissible provided that a paper copy of the hardcopy portions can be furnished upon request.
(b) Contents. Monitoring plans shall contain the information specified in § 75.53 of this part.
(c) Format. The designated representative shall submit each monitoring plan in a format specified by the Administrator.
(d) On and after April 27, 2011, consistent with § 72.21 of this chapter, a hardcopy cover letter signed by the Designated Representative (DR) shall accompany each hardcopy monitoring plan submittal. The cover letter shall include the certification statement described in § 72.21(b) of this chapter, and shall be submitted to the applicable EPA Regional Office and to the appropriate State or local air pollution control agency. For electronic monitoring plan submittals to the Administrator, a cover letter is not required. However, at his or her discretion, the DR may include important explanatory text or comments with an electronic monitoring plan submittal, so long as the information is provided in an electronic format that is compatible with the other data required to be reported under this section.
§ 75.63   Initial certification or recertification application.
(a) Submission. The designated representative for an affected unit or a combustion source shall submit applications and reports as follows:
(1) Initial certifications. (i) For CEM systems or excepted monitoring systems under appendix D or E to this part, within 45 days after completing all initial certification tests, submit:
(A) To the Administrator, the electronic information required by paragraph (b)(1) of this section. Except for subpart E applications for alternative monitoring systems or unless specifically requested by the Administrator, do not submit a hardcopy of the test data and results to the Administrator.
(B) To the applicable EPA Regional Office and the appropriate State and/or local air pollution control agency, the hardcopy information required by paragraph (b)(2) of this section.
(ii) For units for which the owner or operator is applying for certification approval of the optional excepted methodology under § 75.19 for low mass emissions units, submit, no later than 45 days prior to commencing use of the methodology:
(A) To the Administrator, the electronic low mass emission qualification information required by § 75.53(f)(5)(i) or § 75.53(h)(4)(i) (as applicable) and paragraph (b)(1)(i) of this section; and
(B) To the applicable EPA Regional Office and appropriate State and/or local air pollution control agency, the hardcopy information required by § 75.19(a)(2) and § 75.53(f)(5)(ii) or § 75.53(h)(4)(ii) (as applicable), the hardcopy results of any appendix E (of this part) tests or any CEMS data analysis used to derive a fuel-and-unit-specific default NO X emission rate.
(2) Recertifications and diagnostic testing. (i) Within 45 days after completing all recertification tests under § 75.20(b), submit to the Administrator the electronic information required by paragraph (b)(1) of this section. Except for subpart E applications for alternative monitoring systems or unless specifically requested by the Administrator, do not submit a hardcopy of the test data and results to the Administrator.
(ii) Within 45 days after completing all recertification tests under § 75.20(b), submit the hardcopy information required by paragraph (b)(2) of this section to the applicable EPA Regional Office and the appropriate State and/or local air pollution control agency. The applicable EPA Regional Office or appropriate State or local air pollution control agency may waive the requirement to provide hardcopy recertification test and data results. The applicable EPA Regional Office or the appropriate State or local air pollution control agency may also discontinue the waiver and reinstate the requirement of this paragraph to provide a hardcopy report of the recertification test data and results.
(iii) Notwithstanding the requirements of paragraphs (a)(2)(i) and (a)(2)(ii) of this section, for an event for which the Administrator determines that only diagnostic tests ( see § 75.20(b)) are required rather than recertification testing, no hardcopy submittal is required; however, the results of all diagnostic test(s) shall be submitted prior to or concurrent with the electronic quarterly report required under § 75.64. Notwithstanding the requirement of § 75.59(e), for DAHS (missing data and formula) verifications, no hardcopy submittal is required; the owner or operator shall keep these test results on-site in a format suitable for inspection.
(b) Contents. Each application for initial certification or recertification shall contain the following information, as applicable:
(1) Electronic. (i) A complete, up-to-date version of the electronic portion of the monitoring plan, according to § 75.53(e) and (f), in the format specified in § 75.62(c).
(ii) The results of the test(s) required by § 75.20, including the type of test conducted, testing date, information required by § 75.59, and the results of any failed tests that affect data validation.
(2) Hardcopy. (i) Any changed portions of the hardcopy monitoring plan information required under § 75.53(e) and (f). Electronic submittal of all monitoring plan information, including the hardcopy portions, is permissible, provided that a paper copy can be furnished upon request.
(ii) The results of the test(s) required by § 75.20, including the type of test conducted, testing date, information required by § 75.59(a)(9), and the results of any failed tests that affect data validation.
(iii) [Reserved]
(iv) Designated representative signature certifying the accuracy of the submission.
(c) Format. The electronic portion of each certification or recertification application shall be submitted in a format to be specified by the Administrator. The hardcopy test results shall be submitted in a format suitable for review and shall include the information in § 75.59(a)(9).
(d) Consistent with § 72.21 of this chapter, a hardcopy cover letter signed by the Designated Representative (DR) shall accompany the hardcopy portion of each certification or recertification application. The cover letter shall include the certification statement described in § 72.21(b) of this chapter, and shall be submitted to the applicable EPA Regional Office and to the appropriate State or local air pollution control agency. For the electronic portion of a certification or recertification application submitted to the Administrator, a cover letter is not required. However, at his or her discretion, the DR may include important explanatory text or comments with the electronic portion of a certification or recertification application, so long as the information is provided in an electronic format compatible with the other data required to be reported under this section.
§ 75.64   Quarterly reports.
(a) Electronic submission. The designated representative for an affected unit shall electronically report the data and information in paragraphs (a), (b), and (c) of this section to the Administrator quarterly, beginning with the data from the earlier of the calendar quarter corresponding to the date of provisional certification or the calendar quarter corresponding to the relevant deadline for initial certification in § 75.4(a), (b), or (c). The initial quarterly report shall contain hourly data beginning with the hour of provisional certification or the hour corresponding to the relevant certification deadline, whichever is earlier. For an affected unit subject to § 75.4(d) that is shutdown on the relevant compliance date in § 75.4(a) or has been placed in long-term cold storage (as defined in § 72.2 of this chapter), quarterly reports are not required. In such cases, the owner or operator shall submit quarterly reports for the unit beginning with the data from the quarter in which the unit recommences commercial operation (where the initial quarterly report contains hourly data beginning with the first hour of recommenced commercial operation of the unit). For units placed into long-term cold storage during a reporting quarter, the exemption from submitting quarterly reports begins with the calendar quarter following the date that the unit is placed into long-term cold storage. For any provisionally-certified monitoring system, § 75.20(a)(3) shall apply for initial certifications, and § 75.20(b)(5) shall apply for recertifications. Each electronic report must be submitted to the Administrator within 30 days following the end of each calendar quarter. Prior to January 1, 2008, each electronic report shall include for each affected unit (or group of units using a common stack), the information provided in paragraphs (a)(1), (a)(2), and (a)(8) through (a)(15) of this section. During the time period of January 1, 2008 to January 1, 2009, each electronic report shall include, either the information provided in paragraphs (a)(1), (a)(2), and (a)(8) through (a)(15) of this section or the information provided in paragraphs (a)(3) through (a)(15) of this section. On and after January 1, 2009, the owner or operator shall meet the requirements of paragraphs (a)(3) through (a)(15) of this section only. Each electronic report shall also include the date of report generation.
(1) Facility information:
(i) Identification, including:
(A) Facility/ORISPL number;
(B) Calendar quarter and year for the data contained in the report; and
(C) Version of the electronic data reporting format used for the report.
(ii) Location, including:
(A) Plant name and facility ID;
(B) EPA AIRS facility system ID;
(C) State facility ID;
(D) Source category/type;
(E) Primary SIC code;
(F) State postal abbreviation;
(G) County code; and
(H) Latitude and longitude.
(2) The information and hourly data required in § 75.53 and §§ 75.57 through 75.59, excluding the following:
(i) Descriptions of adjustments, corrective action, and maintenance;
(ii) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan);
(iii) Opacity data listed in or § 75.57(f), and in § 75.59(a)(8);
(iv) For units with SO 2 or NO X add-on emission controls that do not elect to use the approved site-specific parametric monitoring procedures for calculation of substitute data, the information in § 75.58(b)(3);
(v) [Reserved]
(vi) Information required by § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes;
(vii) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.59;
(viii) Records of flow monitor and moisture monitoring system polynomial equations, coefficients, or “K” factors required by § 75.59(a)(5)(vi) or § 75.59(a)(5)(vii);
(ix) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D;
(x) Information required by §§ 75.59(b)(1)(vi), (vii), (viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel flowmeter accuracy tests and transmitter/transducer accuracy tests;
(xi) Stratification test results required as part of the RATA supplementary records under § 75.59(a)(7);
(xii) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to problems unrelated to monitor performance; and
(xiii) Supplementary RATA information required under § 75.59(a)(7), except that:
(A) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for flow RATAs at circular or rectangular stacks (or ducts) in which angular compensation for yaw and/or pitch angles is used ( i.e. , Method 2F or 2G in appendices A-1 and A-2 to part 60 of this chapter), with or without wall effects adjustments;
(B) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for any flow RATA run at a circular stack in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is determined by direct measurement;
(C) The data under § 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs at circular stacks in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a default wall effects adjustment factor is applied; and
(D) The data under § 75.59(a)(7)(ix)(A) through (F) shall be reported for all flow RATAs at rectangular stacks or ducts in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is applied.
(3) Facility identification information, including:
(i) Facility/ORISPL number;
(ii) Calendar quarter and year for the data contained in the report; and
(iii) Version of the electronic data reporting format used for the report.
(4) In accordance with § 75.62(a)(1), if any monitoring plan information required in § 75.53 requires an update, either under § 75.53(b) or elsewhere in this part, submission of the electronic monitoring plan update shall be completed prior to or concurrent with the submittal of the quarterly electronic data report for the appropriate quarter in which the update is required.
(5) The daily calibration error test and daily interference check information required in § 75.59(a)(1) and (a)(2) must always be included in the electronic quarterly emissions report. All other certification, quality assurance, and quality control information in § 75.59 that is not excluded from electronic reporting under paragraph (a)(2) or (a)(7) of this section shall be submitted separately, either prior to or concurrent with the submittal of the relevant electronic quarterly emissions report. However, reporting of the information in § 75.59(a)(9)(x) is not required until September 26, 2011, and reporting of the information in § 75.59(a)(15), (b)(6), and (d)(4) is not required until March 27, 2012.
(6) The information and hourly data required in §§ 75.57 through 75.59, and daily calibration error test data, daily interference check, and off-line calibration demonstration information required in § 75.59(a)(1) and (2).
(7) Notwithstanding the requirements of paragraphs (a)(4) through (a)(6) of this section, the following information is excluded from electronic reporting:
(i) Descriptions of adjustments, corrective action, and maintenance;
(ii) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan);
(iii) Opacity data listed in § 75.57(f), and in § 75.59(a)(8);
(iv) For units with SO 2 or NO X add-on emission controls that do not elect to use the approved site-specific parametric monitoring procedures for calculation of substitute data, the information in § 75.58(b)(3);
(v) Information required by § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes;
(vi) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.59;
(vii) Records of flow monitor and moisture monitoring system polynomial equations, coefficients, or “K” factors required by § 75.59(a)(5)(vi) or § 75.59(a)(5)(vii);
(viii) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D of this part;
(ix) Information required by §§ 75.59(b)(1)(vi), (vii), (viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel flowmeter accuracy tests and transmitter/transducer accuracy tests;
(x) Stratification test results required as part of the RATA supplementary records under § 75.59(a)(7);
(xi) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to problems unrelated to monitor performance;
(xii) Supplementary RATA information required under § 75.59(a)(7)(i) through § 75.59(a)(7)(v), except that:
(A) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for flow RATAs at circular or rectangular stacks (or ducts) in which angular compensation for yaw and/or pitch angles is used ( i.e. , Method 2F or 2G in appendices A-1 and A-2 to part 60 of this chapter), with or without wall effects adjustments;
(B) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for any flow RATA run at a circular stack in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is determined by direct measurement;
(C) The data under § 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs at circular stacks in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a default wall effects adjustment factor is applied; and
(D) The data under § 75.59(a)(7)(ix)(A) through (F) shall be reported for all flow RATAs at rectangular stacks or ducts in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is applied; and
(xiii) The certification required by section 6.1.2(b) of appendix A to this part and recorded under § 75.57(a)(7).
(8) Tons (rounded to the nearest tenth) of SO 2 emitted during the quarter and cumulative SO 2 emissions for the calendar year.
(9) Average NO X emission rate (lb/mmBtu, rounded to the nearest thousandth) during the quarter and cumulative NO X emission rate for the calendar year.
(10) Tons of CO 2 emitted during quarter and cumulative CO 2 emissions for calendar year.
(11) Total heat input (mmBtu) for quarter and cumulative heat input for calendar year.
(12) Unit or stack or common pipe header operating hours for quarter and cumulative unit or stack or common pipe header operating hours for calendar year.
(13) For low mass emissions units for which the owner or operator is using the optional low mass emissions methodology in § 75.19(c) to calculate NO X mass emissions, the designated representative must also report tons (rounded to the nearest tenth) of NO X emitted during the quarter and cumulative NO X mass emissions for the calendar year.
(14) For low mass emissions units using the optional long term fuel flow methodology under § 75.19(c), for each quarter report the long term fuel flow for each fuel according to § 75.58(f)(2).
(15) For units using the optional fuel flow to load procedure in section 2.1.7 of appendix D to this part, report both the fuel flow-to-load baseline data and the results of the fuel flow-to-load test each quarter.
(b) The designated representative shall affirm that the component/system identification codes and formulas in the quarterly electronic reports, submitted to the Administrator pursuant to § 75.53, represent current operating conditions.
(c) Compliance certification. The designated representative shall submit a certification in support of each quarterly emissions monitoring report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit's emissions are correctly and fully monitored. The certification shall indicate whether the monitoring data submitted were recorded in accordance with the applicable requirements of this part including the quality control and quality assurance procedures and specifications of this part and its appendices, and any such requirements, procedures and specifications of an applicable excepted or approved alternative monitoring method. For a unit with add-on emission controls, the designated representative shall also include a certification, for all hours where data are substituted following the provisions of § 75.34(a)(1), that the add-on emission controls were operating within the range of parameters listed in the monitoring plan and that the substitute values recorded during the quarter do not systematically underestimate SO 2 or NO X emissions, pursuant to § 75.34.
(d) Electronic format. Each quarterly report shall be submitted in a format to be specified by the Administrator, including both electronic submission of data and (unless otherwise approved by the Administrator) electronic submission of compliance certifications.
(e) [Reserved]
(f) Method of submission. Beginning with the quarterly report for the first quarter of the year 2001, all quarterly reports shall be submitted to EPA by direct computer-to-computer electronic transfer via EPA-provided software, unless otherwise approved by the Administrator.
(g) At his or her discretion, the DR may include important explanatory text or comments with an electronic quarterly report submittal, so long as the information is provided in a format that is compatible with the other data required to be reported under this section.
§ 75.65   Opacity reports.
The owner or operator or designated representative shall report excess emissions of opacity recorded under § 75.57(f) to the applicable State or local air pollution control agency.
§ 75.66   Petitions to the Administrator.
(a) General. The designated representative for an affected unit subject to the requirements of this part may submit a petition to the Administrator requesting that the Administrator exercise his or her discretion to approve an alternative to any requirement prescribed in this part or incorporated by reference in this part. Any such petition shall be submitted in accordance with the requirements of this section. The designated representative shall comply with the signatory requirements of § 72.21 of this chapter for each submission.
(b) Alternative flow monitoring method petition. In cases where no location exists for installation of a flow monitor in either the stack or the ducts serving an affected unit that satisfies the minimum physical siting criteria in appendix A of this part or where installation of a flow monitor in either the stack or duct is demonstrated to the satisfaction of the Administrator to be technically infeasible, the designated representative for the affected unit may petition the Administrator for an alternative method for monitoring volumetric flow. The petition shall, at a minimum, contain the following information:
(1) Identification of the affected unit(s);
(2) Description of why the minimum siting criteria cannot be met within the existing ductwork or stack(s). This description shall include diagrams of the existing ductwork or stack, as well as documentation of any attempts to locate a flow monitor; and
(3) Description of proposed alternative method for monitoring flow.
(c) Alternative to standards incorporated by reference. The designated representative for an affected unit may apply to the Administrator for an alternative to any standard incorporated by reference and prescribed in this part. The designated representative shall include the following information in an application:
(1) A description of why the prescribed standard is not being used;
(2) A description and diagram(s) of any equipment and procedures used in the proposed alternative;
(3) Information demonstrating that the proposed alternative produces data acceptable for use in the Acid Rain Program, including accuracy and precision statements, NIST traceability certificates or protocols, or other supporting data, as applicable to the proposed alternative.
(d) Alternative monitoring system petitions. The designated representative for an affected unit may submit a petition to the Administrator for approval and certification of an alternative monitoring system or component according to the procedure in subpart E of this part. Each petition shall contain the information and data specified in subpart E, including the information specified in § 75.48, in a format to be specified by the Administrator.
(e) Parametric monitoring procedure petitions. The designated representative for an affected unit may submit a petition to the Administrator, where each petition shall contain the information specified in § 75.58(b) for the use of a parametric monitoring method. The Administrator will either:
(1) Publish a notice in the Federal Register indicating receipt of a parametric monitoring procedure petition;, or
(2) Notify interested parties of receipt of a parametric monitoring petition.
(f) [Reserved]
(g) Petitions for emissions or heat input apportionments. The designated representative of an affected unit shall provide information to describe a method for emissions or heat input apportionment under §§ 75.13, 75.16, 75.17, or appendix D of this part. This petition may be submitted as part of the monitoring plan. Such a petition shall contain, at a minimum, the following information:
(1) A description of the units, including their fuel type, their boiler type, and their categorization as Phase I units, substitution units, compensating units, Phase II units, new units, or non-affected units;
(2) A formula describing how the emissions or heat input are to be apportioned to which units;
(3) A description of the methods and parameters used to apportion the emissions or heat input; and
(4) Any other information necessary to demonstrate that the apportionment method accurately measures emissions or heat input and does not underestimate emissions or heat input from affected units.
(h) Partial recertification petition. The designated representative of an affected unit may provide information and petition the Administrator to specify which of the certification tests required by § 75.20 apply for partial recertification of the affected unit. Such a petition shall include the following information:
(1) Identification of the monitoring system(s) being changed;
(2) A description of the changes being made to the system;
(3) An explanation of why the changes are being made; and
(4) A description of the possible effect upon the monitoring system's ability to measure, record, and report emissions.
(i) [Reserved]
(j) Petition for alternative method of accounting for emissions prior to completion of certification tests. The designated representative for an affected unit may submit a petition to the Administrator to use an alternative to the procedures in § 75.4(d)(3), (e)(3), (f)(3) or (g)(3) to account for emissions during the period between the compliance date for a unit and the completion of certification testing for that unit. The designated representative shall include:
(1) Identification of the affected unit(s);
(2) A detailed explanation of the alternative method to account for emissions of the following parameters, as applicable: SO 2 mass emissions (in lbs), NO X emission rate (in lbs/mmBtu), CO 2 mass emissions (in lbs) and, if the unit is subject to the requirements of subpart H of this part, NO X mass emissions (in lbs); and
(3) A demonstration that the proposed alternative does not underestimate emissions.
(k) Petition for an alternative to the stabilization criteria for the cycle time test in section 6.4 of appendix A to this part. The designated representative for an affected unit may submit a petition to the Administrator to use an alternative stabilization criteria for the cycle time test in section 6.4 of appendix A to this part, if the installed monitoring system does not record data in 1-minute or 3-minute intervals. The designated representative shall provide a description of the alternative criteria.
(l) Any other petitions to the Administrator under this part. Except for petitions addressed in paragraphs (b) through (k) of this section, any petition submitted under this paragraph shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(1) Identification of the affected plant and unit(s);
(2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used in the proposed alternative, if applicable;
(4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and is consistent with the purposes of this part and of section 412 of the Act and that any adverse effect of approving such alternative will be de minimis ; and
(5) Any other relevant information that the Administrator may require.
§ 75.67   Retired units petitions.
(a) [Reserved]
(b) For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter that will be permanently retired and governed upon entry into the Opt-in Program by a thermal energy plan in accordance with § 74.47 of this chapter, an exemption from the requirements of this part, including the requirement to install and certify a continuous emissions monitoring system, may be obtained from the Administrator if the designated representative submits to the Administrator a petition for such an exemption prior to the deadline in § 75.4 by which the continuous emission or opacity monitoring systems must complete the required certification tests.
§ 75.68   Temporary modifications to otherwise applicable quality-assurance requirements during the COVID-19 national emergency.
(a) Notwithstanding any other provision of this part, during and following the emergency period defined in paragraph (a)(1) of this section, the provisions of this section shall apply for purposes of reporting the data that are required to be reported under this part and completing the tests that are required to be completed under this part.
(1) For purposes of this section, the emergency period begins on March 13, 2020, the date of the declaration of a national emergency concerning the novel coronavirus disease (COVID-19) outbreak by the President of the United States in accordance with 50 U.S.C. 1621, and concludes 60 days after the date of termination of the national emergency by Congress or the President in accordance with 50 U.S.C. 1622, provided that the emergency period under this section shall not extend past the expiration of the effectiveness of this section.
(2) The provisions of this section shall apply with respect to the following tests that are required to be completed under this part:
(i) Any quality-assurance test of a continuous emission monitoring system required under appendix B to this part or § 75.74(c).
(ii) Any quality-assurance test of a fuel flowmeter required under section 2.1.6 of appendix D to this part or § 75.74(c).
(iii) Any certification or recertification test of a continuous emission monitoring system required under § 75.20 or § 75.70(d).
(iv) Any certification test of a fuel flowmeter required under section 2.1.5 of appendix D to this part or § 75.70(d).
(v) Any periodic analysis of fuel sulfur content, density, or gross calorific value required under section 2.2 or 2.3 of appendix D to this part, provided that there have been no changes in the fuel supply since the most recent previous fuel analysis that would reasonably be expected to cause a change in such fuel characteristics.
(vi) Any periodic retest of NO X emission rates required under section 2.2 of appendix E to this part.
(vii) Any periodic retest of fuel-and-unit-specific NO X emission rates required under § 75.19(c)(4)(i)(D) that is required only because of the passage of time and not because of changes in the fuel supply, physical changes to the unit, changes in the manner of unit operation, or changes to the emission controls.
(3) Following a failure to complete by the applicable deadline (or by the end of any grace period following the deadline) any required quality-assurance test or tests described in paragraph (a)(2)(i) or (ii) of this section for any continuous emission monitoring system or fuel flowmeter under this part, for any subsequent operating hour in the emergency period prior to completion of the test or tests in accordance with paragraph (a)(6)(i) of this section, the owner or operator of an affected unit may continue to report data determined using measurements obtained from the continuous emission monitoring system or fuel flowmeter as valid, provided that the following conditions are met:
(i) But for the failure to complete the quality-assurance test or tests, the data obtained from the monitoring system would be considered valid without the benefit of the provisions of this section;
(ii) The reason for failure to complete each such quality-assurance test is travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency; and
(iii) The owner or operator creates and maintains the records specified in paragraph (a)(7)(i) of this section and the designated representative submits the notifications required under paragraphs (a)(7)(ii) and (iii) of this section.
(4) Following a failure to complete by the applicable deadline any required certification or recertification test or tests described in paragraph (a)(2)(iii) or (iv) of this section for any continuous emission monitoring system or fuel flowmeter under this part, for any subsequent operating hour in an emergency period prior to completion of the test or tests in accordance with paragraph (a)(6)(i) of this section, the owner or operator of an affected unit may continue to report data determined using measurements obtained from the continuous emission monitoring system or fuel flowmeter as conditionally valid provided that the following conditions are met:
(i) But for the failure to complete the certification or recertification test or tests, the data obtained from the monitoring system would be considered conditionally valid without the benefit of the provisions of this section;
(ii) The reason for failure to complete each such certification or recertification test is travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency; and
(iii) The owner or operator creates and maintains the records specified in paragraph (a)(7)(i) of this section and the designated representative submits the notifications required under paragraphs (a)(7)(ii) and (iii) of this section.
(5) Following a failure to complete by the applicable deadline any required periodic analysis of fuel characteristics under appendix D to this part described in paragraph (a)(2)(v) of this section or any required periodic NO X emission rate testing under appendix E to this part or § 75.19 described in paragraph (a)(2)(vi) or (vii) of this section, for any subsequent operating hour during the emergency period prior to completion of the analysis or testing in accordance with paragraph (a)(6)(i) of this section, the owner or operator of an affected unit using the methodology in appendix D may continue to report data determined using the fuel characteristics authorized for use under the regulations following the most recent previous analysis for that fuel, the owner or operator of an affected unit using the methodology in appendix E may continue to report data determined using the correlation curve developed from the most recent previous appendix E NO X emission rate testing, and the owner or operator of an affected unit using a fuel-and-unit-specific emission rate under the LME methodology in § 75.19(c)(1)(iv) may continue to report data determined using the fuel-and-unit-specific emission rate developed from the most recent previous LME NO X emission rate testing, provided that the following conditions are met:
(i) But for the failure to complete the appendix D fuel analysis or the appendix E or LME NO X emission rate testing, the data obtained from the appendix D, appendix E, or LME monitoring methodology would be considered valid without the benefit of the provisions of this section;
(ii) The reason for failure to complete each such appendix D fuel analysis or appendix E or LME NO X emission rate test is travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency; and
(iii) The owner or operator creates and maintains the records specified in paragraph (a)(7)(i) of this section and the designated representative submits the notifications required under paragraphs (a)(7)(ii) and (iii) of this section.
(6)(i) Each quality-assurance test, certification or recertification test, appendix D fuel analysis, and appendix E or LME NO X emission rate test required under this part that was not completed for a unit by the applicable deadline (or by the end of any grace period following the deadline) must be completed as soon as practicable following the end of travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency that affect that unit or the personnel or supplies required to complete the analysis or testing for that unit, but in no event later than the conclusion of the emergency period as defined in paragraph (a)(1) of this section.
(ii) If a test or analysis for which a deadline is established under paragraph (a)(6)(i) of this section is not completed by that deadline, the test or analysis shall be completed as soon as practicable thereafter, and for each operating hour following that deadline until completion of the test or analysis, the owner or operator shall report substitute data as if the originally applicable deadline for the test or analysis were the deadline under paragraph (a)(6)(i) of this section.
(iii) For purposes of determining the applicable deadline for the next quality-assurance test, appendix D fuel analysis, or appendix E or LME NO X emission rate test required under this part after a delayed quality-assurance test, appendix D fuel analysis, or appendix E or LME NO X emission rate test is completed or due to be completed in accordance with paragraph (a)(6)(i) of this section, the delayed test or analysis shall be considered to have been completed in a timely manner as of the date on which such delayed test or analysis was actually completed or, if earlier, the deadline for completion of the delayed test or analysis under paragraph (a)(6)(i) of this section.
(7) The following recordkeeping and reporting requirements shall apply to any use of the procedures under paragraphs (a)(3) through (6) of this section:
(i) The owner or operator of an affected unit reporting data under paragraph (a)(3), (4), or (5) of this section shall maintain records documenting the reasons for failure to complete by the applicable deadline each test or analysis referenced in such paragraph and demonstrating that such failure is caused by travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency. The owner or operator shall also maintain records documenting when any such travel, plant access, or other safety restrictions impairing the ability to complete testing or analyses for that unit ceased to apply. The records shall be maintained on site at the source in a form suitable for inspection for a period of three years from the date of each record.
(ii) By five business days after the applicable deadline for a test or analysis referenced in paragraph (a)(3), (4), or (5) of this section, the designated representative shall submit to the Administrator, by email transmitted to camdpetitions@epa.gov, a notification containing the following information:
(A) Facility ID (ORIS);
(B) Facility name;
(C) Monitoring location ID and/or unit ID;
(D) Identification of the quality-assurance test, certification or recertification test, appendix D fuel analysis, or appendix E or LME NO X emission rate test for which the notification is being submitted;
(E) Identification of the applicable deadline for the test or analysis under part 75 (not including any applicable grace period);
(F) A detailed explanation of the reason for failure to complete the test or analysis by the applicable deadline under part 75, including an explanation of how such failure is caused by travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency;
(G) The certification statements in § 72.21(b)(1) and (2) of this chapter.
(iii) By five business days after the completion in accordance with paragraph (a)(6)(i) or (ii) of this section of a delayed test or analysis referenced in paragraph (a)(3), (4), or (5) of this section, the designated representative shall submit to the Administrator, by email transmitted to camdpetitions@epa.gov, a notification containing the following information:
(A) Facility ID (ORIS);
(B) Facility name;
(C) Monitoring location ID and/or unit ID;
(D) Identification of the quality-assurance test, certification or recertification test, appendix D fuel analysis, or appendix E or LME NO X emission rate test for which the notification is being submitted;
(E) Identification of the date as of which travel, plant access, or other safety restrictions previously impairing the ability to complete the delayed test or analysis for the unit no longer applied;
(F) Identification of the date as of which the test or analysis was completed in accordance with paragraph (a)(6)(i) or (ii) of this section; and
(G) The certification statements in § 72.21(b)(1) and (2) of this chapter.
(iv) With respect to any test or analysis of a type that is required to be performed more frequently than once per unit operating quarter, a series of such required tests or analyses may be treated as a single test or analysis for purposes of a notification submitted under paragraph (a)(7)(ii) or (iii) of this section, with the notification under paragraph (a)(7)(ii) to be submitted by five business days after the first failure to perform such a test or analysis by the applicable deadline and the notification under paragraph (a)(7)(iii) to be submitted by five business days after the first completion of such a test or analysis in accordance with paragraph (a)(6)(i) or (ii) of this section.
(v) A notification submitted under paragraph (a)(7)(ii) or (iii) of this section may include information for more than one required test for a given unit or monitoring location, provided that each item of information required to be included in such notification pursuant to paragraphs (a)(7)(ii)(D) through (F) of this section or paragraphs (a)(7)(iii)(D) through (F) of this section is provided separately for each required test included in the notification.
(vi) No claim of confidentiality may be asserted with respect to any information included in a notification submitted under paragraph (a)(7)(ii) or (iii) of this section.
(vii) Notwithstanding the deadlines for submission of notifications in paragraphs (a)(7)(ii), (iii), and (iv) of this section, no such notification from any owner or operator shall be due less than 30 days after the effective date of this section.
(b) The requirements of this section are effective from April 22, 2020 and, except for those in paragraphs (a)(6)(ii) and (iii) and (a)(7)(i) of this section, shall cease to have effect October 19, 2020.
§ 75.70   NOXmass emissions provisions.
(a) Applicability. The owner or operator of a unit shall comply with the requirements of this subpart to the extent that compliance is required by an applicable State or federal NO X mass emission reduction program that incorporates by reference, or otherwise adopts the provisions of, this subpart.
(1) For purposes of this subpart, the term “affected unit” shall mean any unit that is subject to a State or federal NO X mass emission reduction program requiring compliance with this subpart, the term “non-affected unit” shall mean any unit that is not subject to such a program, the term “permitting authority” shall mean the permitting authority under an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart, and the term “designated representative” shall mean the responsible party under the applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart.
(2) In addition, the provisions of subparts A, C, D, E, F, and G and appendices A through G of this part applicable to NO X concentration, flow rate, NO X emission rate and heat input, as set forth and referenced in this subpart, shall apply to the owner or operator of a unit required to meet the requirements of this subpart by a State or federal NO X mass emission reduction program. When applying these requirements, the term “affected unit” shall mean any unit that is subject to a State or federal NO X mass emission reduction program requiring compliance with this subpart, the term “permitting authority” shall mean the permitting authority under an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart, and the term “designated representative” shall mean the responsible party under the applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart. The requirements of this part for SO 2 , CO 2 and opacity monitoring, recordkeeping and reporting do not apply to units that are subject to a State or federal NO X mass emission reduction program only and are not affected units with an Acid Rain emission limitation.
(b) Compliance dates. The owner or operator of an affected unit shall meet the compliance deadlines established by an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart.
(c) Prohibitions. (1) No owner or operator of an affected unit or a non-affected unit under § 75.72(b)(2)(ii) shall use any alternative monitoring system, alternative reference method, or any other alternative for the required continuous emission monitoring system without having obtained prior written approval in accordance with paragraph (h) of this section.
(2) No owner or operator of an affected unit or a non-affected unit under § 75.72(b)(2)(ii) shall operate the unit so as to discharge, or allow to be discharged emissions of NO X to the atmosphere without accounting for all such emissions in accordance with the applicable provisions of this part, except as provided in § 75.74.
(3) No owner or operator of an affected unit or a non-affected unit under § 75.72(b)(2)(ii) shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording NO X mass emissions discharged into the atmosphere, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the provisions of this part applicable to monitoring systems under § 75.71, except as provided in § 75.74.
(4) No owner or operator of an affected unit or a non-affected unit under § 75.72(b)(2)(ii) shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, or any other approved emission monitoring system under this part, except under any one of the following circumstances:
(i) During the period that the unit is covered by a retired unit exemption that is in effect under the State or federal NO X mass emission reduction program that adopts the requirements of this subpart;
(ii) The owner or operator is monitoring NO X mass emissions from the affected unit with another certified monitoring system approved, in accordance with the provisions of paragraph (d) of this section; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system in accordance with § 75.61.
(d) Initial certification and recertification procedures. (1) The owner or operator of an affected unit that is subject to an Acid Rain emissions limitation shall comply with the initial certification and recertification procedures in § 75.20 of this part, except that the owner or operator shall meet any additional requirements set forth in an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart.
(2) The owner or operator of an affected unit that is not subject to an Acid Rain emissions limitation shall comply with the initial certification and recertification procedures established by an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart. The owner or operator of an affected unit that is subject to an Acid Rain emissions limitation shall comply with the initial certification and recertification procedures established by an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart for any additional NO X -diluent CEMS, flow monitors, diluent monitors or NO X concentration monitoring system required under the NO X mass emissions provisions of § 75.71 or the common stack provisions in § 75.72.
(e) Quality assurance and quality control requirements. For units that use continuous emission monitoring systems to account for NO X mass emissions, the owner or operator shall meet the applicable quality assurance and quality control requirements in § 75.21, appendix B to this part, and § 75.74(c) for the NO X -diluent continuous emission monitoring systems, flow monitoring systems, NO X concentration monitoring systems, moisture monitoring systems, and diluent monitors required under § 75.71. Units using the low mass emissions excepted methodology under § 75.19 shall meet the applicable quality assurance requirements of that section, except as otherwise provided in § 75.74(c). Units using excepted monitoring methods under appendices D and E to this part shall meet the applicable quality assurance requirements of those appendices.
(f) Missing data procedures. Except as provided in § 75.34, paragraph (g) of this section, and § 75.74(c)(7), the owner or operator shall provide substitute data from monitoring systems required under § 75.71 for each affected unit as follows:
(1) For an owner or operator using a continuous emissions monitoring system, substitute for missing data in accordance with the applicable missing data procedures in §§ 75.31 through 75.37 whenever the unit combusts fuel and:
(i) A valid, quality-assured hour of NO X emission rate data (in lb/mmBtu) has not been measured and recorded for a unit by a certified NO X -diluent continuous emission monitoring system or by an approved monitoring system under subpart E of this part;
(ii) A valid, quality-assured hour of flow data (in scfh) has not been measured and recorded for a unit from a certified flow monitor or by an approved alternative monitoring system under subpart E of this part;
(iii) A valid, quality-assured hour of heat input rate data (in mmBtu/hr) has not been measured and recorded for a unit from a certified flow monitor and a certified diluent (CO 2 or O 2 ) monitor or by an approved alternative monitoring system under subpart E of this part, where heat input is required either for calculating NO X mass or allocating allowances under the applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart;
(iv) A valid, quality-assured hour of NO X concentration data (in ppm) has not been measured and recorded by a certified NO X concentration monitoring system, or by an approved alternative monitoring method under subpart E of this part, where the owner or operator chooses to use a NO X concentration monitoring system with a flow monitor, to calculate NO X mass emissions. The initial missing data procedures for determining monitor data availability and the standard missing data procedures for a NO X concentration monitoring system shall be the same as the procedures specified for a NO X -diluent continuous emission monitoring system under §§ 75.31, 75.32, and 75.33; or
(v) A valid, quality-assured hour of moisture data (in percent H 2 O) has not been measured or recorded for an affected unit, either by a certified moisture monitoring system or an approved alternative monitoring method under subpart E of this part. This requirement does not apply when a default percent moisture value, as provided in § 75.11(b) or § 75.12(b), is used to account for the hourly moisture content of the stack gas.
(2) For an owner or operator using an excepted monitoring system under appendix D or E of this part, substitute for missing data in accordance with the missing data procedures in section 2.4 of appendix D to this part or in section 2.5 of appendix E to this part whenever the unit combusts fuel and:
(i) A valid, quality-assured hour of fuel flow rate data has not been measured and recorded by a certified fuel flowmeter that is part of an excepted monitoring system under appendix D or E of this part; or
(ii) A fuel sample value for gross calorific value, or if necessary, density or specific gravity, from a sample taken an analyzed in accordance with appendix D of this part is not available; or
(iii) A valid, quality-assured hour of NO X emission rate data has not been obtained according to the procedures and specifications of appendix E to this part.
(g) Reporting data prior to initial certification. If the owner or operator of an affected unit has not successfully completed all certification tests required by the State or federal NO X mass emission reduction program that adopts the requirements of this subpart by the applicable date required by that program, he or she shall determine, record and report hourly data prior to initial certification using one of the following procedures, consistent with the monitoring equipment to be certified:
(1) For units that the owner or operator intends to monitor for NO X mass emissions using NO X emission rate and heat input rate, the maximum potential NO X emission rate and the maximum potential hourly heat input of the unit, as defined in § 72.2 of this chapter.
(2) For units that the owner or operator intends to monitor for NO X mass emissions using a NO X concentration monitoring system and a flow monitoring system, the maximum potential concentration of NO X and the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part;
(3) For any unit, the reference methods under § 75.22 of this part.
(4) For any unit using the low mass emission excepted monitoring methodology under § 75.19, the procedures in paragraphs (g)(1) or (2) of this section.
(5) Any unit using the procedures in paragraph (g)(2) of this section that is required to report heat input for purposes of allocating allowances shall also report the maximum potential hourly heat input of the unit, as defined in § 72.2 of this chapter.
(6) For any unit using continuous emissions monitors, the conditional data validation procedures in § 75.20(b)(3)(ii) through (b)(3)(ix).
(h) Petitions. (1) The designated representative of an affected unit that is subject to an Acid Rain emissions limitation may submit a petition to the Administrator requesting an alternative to any requirement of this subpart. Such a petition shall meet the requirements of § 75.66 and any additional requirements established by an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart. Use of an alternative to any requirement of this subpart is in accordance with this subpart and with such State or federal NO X mass emission reduction program only to the extent that the petition is approved by the Administrator, in consultation with the permitting authority.
(2) Notwithstanding paragraph (h)(1) of this section, petitions requesting an alternative to a requirement concerning any additional CEMS required solely to meet the common stack provisions of § 75.72 shall be submitted to the permitting authority and the Administrator and shall be governed by paragraph (h)(3)(ii) of this section. Such a petition shall meet the requirements of § 75.66 and any additional requirements established by an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart.
(3)(i) The designated representative of an affected unit that is not subject to an Acid Rain emissions limitation may submit a petition to the permitting authority and the Administrator requesting an alternative to any requirement of this subpart. Such a petition shall meet the requirements of § 75.66 and any additional requirements established by an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart.
(ii) Use of an alternative to any requirement of this subpart is in accordance with this subpart only to the extent that it is approved by the Administrator and by the permitting authority if required by an applicable State or federal NO X mass emission reduction program that adopts the requirements of this subpart.