[[pp. 28613-28662]] Acid Rain Program; Continuous Emission Monitoring Rule Revisions

Note: EPA no longer updates this information, but it may be useful as a reference or resource.
 



[Federal Register: May 26, 1999 (Volume 64, Number 101)]
[Rules and Regulations]               
[Page 28613-28662]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr26my99-20]
 
[[pp. 28613-28662]] Acid Rain Program; Continuous Emission Monitoring Rule Revisions

[[Continued from page 28612]]

[[Page 28613]]

(flag value if derived from missing data procedures);
    (vi) SO<INF>2</INF> 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); and
    (xiii) Type of oil combusted.
    (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<INF>2</INF> 
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<INF>2</INF> 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<INF>2</INF> emission rate of 0.0006 lb/mmBtu for 
pipeline natural gas, or calculated SO<INF>2</INF> 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<INF>2</INF> 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.
    (5) For each oil sample or sample of diesel fuel:
    (i) Date of sampling;
    (ii) Sulfur content (percent, rounded to the nearest hundredth for 
diesel fuel 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 
paragraph Sec. 75.54(d) or Sec. 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; and
    (x) Segment identification of the correlation curve.
    (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;

[[Page 28614]]

    (ix) Fuel flow monitoring system identification code; and
    (x) Segment identification of the correlation curve.
    (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<INF>2</INF> reading 
(percent, rounded to the nearest tenth) (flag if value exceeds by more 
than 2 percentage points the O<INF>2</INF> level recorded at the same 
heat input during the previous NO_X emission rate test).
    (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<INF>2</INF> emission record provisions during the 
combustion of gaseous fuel. (1) If SO<INF>2</INF> emissions are 
determined in accordance with the provisions in Sec. 75.11(e)(2) during 
hours in which only gaseous fuel is combusted in a unit with an 
SO<INF>2</INF> CEMS, the owner or operator shall record the information 
in paragraph (c)(3) of this section in lieu of the information in 
Secs. 75.54(c)(1) and (c)(3) or Secs. 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 Sec. 75.11(e)(3), uses an 
SO<INF>2</INF> CEMS to determine SO<INF>2</INF> 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 Sec. 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<INF>2</INF> 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<INF>2</INF>, NO_X, and CO<INF>2</INF> 
record provisions for gas-fired or oil-fired units using the optional 
low mass emissions excepted methodology in Sec. 75.19. In lieu of 
recording the information in Secs. 75.54(b) through (e) or 
Secs. 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 Sec. 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, residual oil, 
or diesel fuel) (note: if more than one type of fuel is combusted in 
the hour, indicate the fuel type which results in the highest emission 
factors for NO_X);
    (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<INF>2</INF> mass emissions (lbs, rounded to the 
nearest tenth);
    (vii) Hourly CO<INF>2</INF> 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; and
    (xii) Control status of the unit.
    (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) Component-system identification code;
    (xi) Quarter and year;
    (xii) Total heat input (mmBtu); and
    (xiii) Operating hours in period.
    42. Section 75.59 is added to subpart F to read as follows:


Sec. 75.59  Certification, quality assurance, and quality control 
record provisions.

    Before April 1, 2000, the owner or operator shall meet the 
requirements of this section or Sec. 75.56. However, the provisions of 
this section which support a regulatory option provided in another 
section of this part must be followed if that regulatory option is 
exercised prior to April 1, 2000. On or after April 1, 2000, the owner 
or operator shall meet the 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<INF>2</INF> or NO_X pollutant 
concentration monitor, flow monitor, CO<INF>2</INF> pollutant 
concentration monitor (including O<INF>2</INF> monitors used to 
determine CO<INF>2</INF> emissions), or diluent gas monitor (including 
wet- and dry-basis O<INF>2</INF> 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;
    (ii) Instrument span and span scale;
    (iii) Date and hour;
    (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) Calibration gas level;
    (viii) 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 Sec. 72.2 of this chapter 
and appendix A to this part, was used to conduct calibration error 
testing;

[[Page 28615]]

    (x) Description of any adjustments, corrective actions, or 
maintenance prior to a passed test or following a failed test; and
    (xi) For the qualifying test for off-line calibration, the owner or 
operator shall indicate 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;
    (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<INF>2</INF> or NO_X pollutant 
concentration monitor, CO<INF>2</INF> pollutant concentration monitor 
(including O<INF>2</INF> monitors used to determine CO<INF>2</INF> 
emissions), or diluent gas monitor (including wet- and dry-basis 
O<INF>2</INF> 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;
    (ii) Instrument span and span scale;
    (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.
    (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; and
    (M) Number of hours excluded for flue gases discharging 
simultaneously thorough a main stack and a bypass stack.
    (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<INF>d </INF>-or F<INF>c</INF>-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; and
    (L) Operating load level.
    (5) For each SO<INF>2</INF> pollutant concentration monitor, flow 
monitor, each CO<INF>2</INF> pollutant concentration monitor (including 
any O<INF>2</INF> concentration monitor used to determine 
CO<INF>2</INF> mass emissions or heat input), each NO_X-
diluent continuous emission monitoring system, each SO<INF>2</INF>-
diluent continuous emission monitoring system, each NO_X 
concentration monitoring system, each diluent gas (O<INF>2</INF> or 
CO<INF>2</INF>) 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<INF>2</INF> concentration monitor, flow monitor, 
CO<INF>2</INF> pollutant concentration monitor, NO_X-diluent 
continuous emission monitoring system, SO<INF>2</INF>-diluent 
continuous emission monitoring system, diluent gas (O<INF>2</INF> or 
CO<INF>2</INF>) 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 load level (low, mid, high, or normal, as 
appropriate) and number of load levels comprising test;
    (F) Normal load 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); 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

[[Page 28616]]

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 level 
tested. Each load 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;
    (F) Bias test results as specified in section 7.6.4 in appendix A 
to this part; and
    (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.
    (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<INF>2</INF> or CO<INF>2</INF>) 
concentration measurements into NO_X emission rates (in lb/
mmBtu), heat input or CO<INF>2</INF> 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<INF>2</INF>, NO_X, or CO<INF>2</INF> 
pollutant concentration monitor, NO_X-diluent continuous 
emission monitoring system, SO<INF>2</INF>-diluent continuous emission 
monitoring system, NO_X concentration monitoring system, or 
diluent gas (O<INF>2</INF> or CO<INF>2</INF>) 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;
    (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) Cycle time result for the entire system;
    (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) 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 load level (low, mid, high, or normal, as 
appropriate);
    (B) Number of reference method traverse points;
    (C) Average stack gas temperature ( deg.F);
    (D) Barometric pressure at test port (inches of mercury);
    (E) Stack static pressure (inches of H<INF>2</INF>O);
    (F) Absolute stack gas pressure (inches of mercury);
    (G) Percent CO<INF>2</INF> and O<INF>2</INF> in the stack gas, dry 
basis;
    (H) CO<INF>2</INF> and O<INF>2</INF> reference method used;
    (I) Moisture content of stack gas (percent H<INF>2</INF>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<INF>2</INF>O) for the run;
    (N) Stack or duct cross-sectional area at test port 
(ft²);
    (O) Average velocity (ft/sec);
    (P) Total volumetric flow rate (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) Velocity differential pressure at traverse point (inches of 
H<INF>2</INF>O);
    (G) T<INF>S</INF>, stack temperature at the traverse point 
( deg.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<INF>2</INF>, NO_X, 
CO<INF>2</INF>, or O<INF>2</INF> 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;

[[Page 28617]]

    (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<INF>2</INF> to NO conversion test (Method 
7E only);
    (W) Results of the latest NO<INF>2</INF> 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<INF>2</INF>O collected in the impingers (ml);
    (H) Mass of H<INF>2</INF>O collected in the silica gel (g);
    (I) Dry gas meter calibration factor;
    (J) Average dry gas meter temperature ( deg.F);
    (K) Barometric pressure (inches of mercury);
    (L) Differential pressure across the orifice meter (inches of 
H<INF>2</INF>O);
    (M) Initial and final dry gas meter readings (ft³);
    (N) Total sample gas volume, corrected to standard conditions 
(dscf); and
    (O) Percentage of moisture in the stack gas (percent 
H<INF>2</INF>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.
    (8) For each certified continuous emission monitoring system, 
continuous opacity monitoring system, or alternative monitoring system, 
the date and description of each event which requires recertification 
of the system and the date and type of each test performed to recertify 
the system in accordance with Sec. 75.20(b).
    (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 Sec. 75.60(b)(6) 
or Sec. 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

[[Page 28618]]

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.
    (10) Whenever reference methods are used as backup monitoring 
systems pursuant to Sec. 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)(A), 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<INF>2</INF>, 
NO_X, CO<INF>2</INF>, or O<INF>2</INF> 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<INF>2</INF>, NO_X, CO<INF>2</INF>, or O<INF>2</INF> 
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) For a quality assurance test extension claim based on a grace 
period:
    (A) Component-system identification code;
    (B) Type of test;
    (C) Beginning of grace period;
    (D) Date and hour of completion of required quality assurance test;
    (E) Number of unit or stack operating hours from the beginning of 
the grace period to the completion of the quality assurance test or the 
maximum allowable grace period; and
    (F) Date and hour of end of grace period.
    (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; and
    (F) Quarter and year.
    (v) For a single-load 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 level (low, mid, and high) since the previous annual flow 
RATA, to the nearest 0.1 percent.
    (D) End date of the historical load data collection period; and
    (E) Indication of the load 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<INF>2</INF> 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 
Sec. 75.64(a)(2), this information shall be reported with the quarterly 
report as descriptive text consistent with Sec. 75.64(g).
    (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;
    (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;

[[Page 28619]]

    (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;
    (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 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
orifice-, nozzle-, or venturi-type flowmeter under sections 2.1.6.1 
through 2.1.6.4 of appendix D to this part:
    (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;
    (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; and
    (I) Number of hours excluded in lower 25.0 percent range of 
operation.
    (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;
    (B) Completion date and hour of 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 or 1000 lb/hr of steam;
    (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; and
    (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.
    (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;
    (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<INF>2</INF> and NO_X reference 
method analyzers;
    (H) Type of fuel(s) combusted during the run;
    (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;
    (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;
    (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;

[[Page 28620]]

    (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<INF>2</INF> level, water/
fuel ratio);
    (G) Test number; and
    (H) Operating level for runs.
    (c) For units with add-on SO<INF>2</INF> or NO_X emission 
controls following the provisions of Sec. 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 Sec. 75.55(b) or Sec. 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 
Sec. 75.19(c)(1)(iv). For oil-and gas-fired units using the optional 
SO<INF>2</INF>, NO_X and CO<INF>2</INF> emissions 
calculations for low mass emission units under Sec. 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 
Sec. 75.19(c)(1)(iv):
    (1) For each run of each test performed under 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<INF>2</INF> 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);
    (xiii) An indicator that the resulting NO_X emission rate 
is the highest NO_X emission rate record during any run of 
the test (if appropriate);
    (xiv) The default NO_X emission rate (highest 
NO_X emission rate value during the test multiplied by 1.15);
    (xv) An indicator that control equipment was operating or not 
operating during each run of the test; and
    (xvi) Parameter data indicating the use and efficacy of control 
equipment during the test.
    (2) For each unit in a group of identical units qualifying for 
reduced testing under Sec. 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 Sec. 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 Sec. 75.19;
    (vii) The fuel and unit-specific NO_X default rate 
established for the group of identical units under Sec. 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 based on the criteria established in 
Secs. 75.19(c)(1)(iv)(B)(1) and (3); and
    (xi) Purpose of group tests.

Subpart G--Reporting Requirements

    43. Section 75.60 is amended by revising paragraphs (a), (b)(1), 
and (b)(2) and by adding new paragraphs (b)(3), (b)(4), (b)(5) and 
(b)(6) to read as follows:


Sec. 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 
Sec. 72.21 of this chapter for all submissions.
    (b) * * *
    (1) Initial certifications. The designated representative shall 
submit initial certification applications according to Sec. 75.63.
    (2) Recertifications. The designated representative shall submit 
recertification applications according to Sec. 75.63.
    (3) Monitoring plans. The designated representative shall submit 
monitoring plans according to Sec. 75.62.
    (4) Electronic quarterly reports. The designated representative 
shall submit electronic quarterly reports according to Sec. 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 Secs. 75.66 and 75.67.
    (6) Semiannual or annual RATA reports. If requested 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 Sec. 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.
* * * * *
    44. Section 75.61 is amended by revising paragraphs (a) 
introductory text, (a)(1) introductory text, and (b), by adding a new 
sentence to the end of paragraph (a)(6)(ii), and by adding a new 
paragraph (a)(1)(iv) to read as follows:


Sec. 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, 
recertification tests, and revised test dates as specified in

[[Page 28621]]

Sec. 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 and 
except for testing only of the data acquisition and handling system.
* * * * *
    (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) of this section, for a unit or a group 
of units, for one or more recertification tests. 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) of this section for 
future recertification tests of a unit or a group of units.
* * * * *
    (6) * * *
    (ii) * * * The reporting requirements of this paragraph (a)(6)(ii) 
also shall apply if the designated representative of a unit is exempt 
from certifying a fuel flowmeter for use during the combustion of 
emergency fuel under section 2.1.4.3 of appendix D to this part.
    (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 Sec. 75.20(c)(8) 
to the State or local air pollution control agency.
* * * * *
    45. Section 75.62 is amended by revising the title of the section 
and revising paragraphs (a) and (c) to read as follows:


Sec. 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 45 days prior to the initial certification test; at the time 
of recertification application submission; and in each electronic 
quarterly report.
    (2) Hardcopy. The designated representative shall submit all of the 
hardcopy information required under Sec. 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 45 days prior to the initial certification test; 
with any recertification application, if a hardcopy monitoring plan 
change is associated with the recertification event; and within 30 days 
of any other event with which a hardcopy monitoring plan change is 
associated, pursuant to Sec. 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.
* * * * *
    (c) Format. The designated representative shall submit each 
monitoring plan in a format specified by the Administrator.
    46. Section 75.63 is revised to read as follows:


Sec. 75.63  Initial certification or recertification application 
submittals.

    (a) Submission. The designated representative for an affected unit 
or a combustion source shall submit applications and reports as 
follows:
    (1) Initial certifications. (i) Within 45 days after completing all 
initial certification tests, submit to the Administrator the electronic 
information required by paragraph (b)(1) of this section and a hardcopy 
certification application form (EPA form 7610-14). 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 initial certification 
tests, submit the hardcopy information required by paragraph (b)(2) to 
the applicable EPA Regional Office and the appropriate State and/or 
local air pollution control agency.
    (iii) For units for which the owner or operator is applying for 
certification approval of the optional excepted methodology under 
Sec. 75.19 for low mass emissions units, submit:
    (A) To the Administrator, the electronic information required by 
paragraph (b)(1)(i), the hardcopy information required by paragraph 
(b)(2), and a hardcopy certification application form (EPA form 7610-
14); and
    (B) To the applicable EPA Regional Office and appropriate State 
and/or local air pollution control agency, the hardcopy information 
required by paragraphs (b)(2)(i), (iii), and (iv).
    (2) Recertifications. (i) Within 45 days after completing all 
recertification tests, submit to the Administrator the electronic 
information required by paragraph (b)(1) and a hardcopy certification 
application form (EPA form 7610-14). 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, 
submit the hardcopy information required by paragraph (b)(2) 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 for submission to it of a hardcopy recertification. 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 Sec. 75.20(b)) are required, 
no hardcopy submittal is required; however, the results of all 
diagnostic test(s) shall be submitted in the electronic quarterly 
report required under Sec. 75.64. For DAHS (missing data and formula) 
verifications, neither a hardcopy nor an electronic submittal of any 
kind 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 Secs. 75.53(c) 
and (d), or Secs. 75.53(e) and (f), as applicable, in the format 
specified in Sec. 75.62(c).
    (ii) The results of the test(s) required by Sec. 75.20, including 
the type of test conducted, testing date, information required by 
Sec. 75.56 or Sec. 75.59, as applicable, 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

[[Page 28622]]

Sec. Sec. 75.53(c) and (d), or Secs. 75.53(e) and (f), as applicable. 
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 Sec. 75.20, including 
the type of test conducted, testing date, information required by 
Sec. 75.59(a)(9), and the results of any failed tests that affect data 
validation.
    (iii) Certification or recertification application form (EPA form 
7610-14).
    (iv) Designated representative signature.
    (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 Sec. 75.59(a)(9).
    47. Section 75.64 is revised to read as follows:


Sec. 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 later of: the last 
(partial) calendar quarter of 1993 (where the calendar quarter data 
begins at November 15, 1993); or the calendar quarter corresponding to 
the date of provisional certification; or the calendar quarter 
corresponding to the relevant deadline for initial certification in 
Sec. 75.4(a), (b), or (c), whichever quarter is earlier. 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 Sec. 75.4(d) that is shutdown on the relevant compliance 
date in Sec. 75.4(a), 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 any provisionally-
certified monitoring system, Sec. 75.20(a)(3) shall apply for initial 
certifications, and Sec. 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. Each electronic report 
shall include the date of report generation for the information 
provided in paragraphs (a)(2) through (a)(11) of this section, and 
shall also include for each affected unit (or group of units using a 
common stack):
    (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 Secs. 75.53 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 Sec. 75.54(f) or Sec. 75.57(f), and in 
Sec. 75.59(a)(8);
    (iv) For units with SO<INF>2</INF> 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 Sec. 75.55(b)(3) or Sec. 75.58(b)(3);
    (v) The information recorded under Sec. 75.56(a)(7) for the period 
prior to April 1, 2000;
    (vi) Information required by Sec. 75.54(g) or Sec. 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 Sec. 75.53 
and hardcopy test data and results required by Sec. 75.56 or 
Sec. 75.59;
    (viii) Records of flow monitor and moisture monitoring system 
polynomial equations, coefficients or ``K'' factors required by 
Sec. 75.56(a)(5)(vii), Sec. 75.56(a)(5)(ix), Sec. 75.59(a)(5)(vi) or 
Sec. 75.59(a)(5)(vii);
    (ix) Daily fuel sampling information required by 
Sec. 75.58(c)(3)(i) for units using assumed values under appendix D;
    (x) Information required by Secs. 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 Secs. 75.56(a)(7) or 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
    (xiv) Supplementary RATA information required under 
Sec. 75.59(a)(7)(i) through Sec. 75.59(a)(7)(v), except that: the data 
under Sec. 75.59(a)(7)(ii)(A) through (T) and the data under 
Sec. 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported 
for flow RATAs in which angular compensation (measurement of pitch and/
or yaw angles) is used and for flow RATAs in which a site-specific wall 
effects adjustment factor is determined by direct measurement; and the 
data under Sec. 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs 
in which a default wall effects adjustment factor is applied.
    (3) Tons (rounded to the nearest tenth) of SO<INF>2</INF> emitted 
during the quarter and cumulative SO<INF>2</INF> emissions for the 
calendar year.
    (4) Average NO_X emission rate (lb/mmBtu, rounded to the 
nearest hundredth prior to April 1, 2000 and to the nearest thousandth 
on and after April 1, 2000) during the quarter and cumulative 
NO_X emission rate for the calendar year.
    (5) Tons of CO<INF>2</INF> emitted during quarter and cumulative 
CO<INF>2</INF> emissions for calendar year.
    (6) Total heat input (mmBtu) for quarter and cumulative heat input 
for calendar year.
    (7) 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.
    (8) If the affected unit is using a qualifying Phase I technology, 
then the quarterly report shall include the information required in 
paragraph (e) of this section.
    (9) For low mass emissions units for which the owner or operator is 
using the optional low mass emissions methodology in Sec. 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.
    (10) For low mass emissions units using the optional long term fuel 
flow methodology under Sec. 75.19(c), for each quarter report the long 
term fuel flow for each fuel according to Sec. 75.59.
    (11) 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

[[Page 28623]]

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 Sec. 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 
Sec. 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<INF>2</INF> or NO_X emissions, pursuant to 
Sec. 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 electronic or hardcopy submission of 
compliance certifications.
    (e) Phase I qualifying technology reports. In addition to reporting 
the information in paragraphs (a), (b), and (c) of this section, the 
designated representative for an affected unit on which SO<INF>2</INF> 
emission controls have been installed and operated for the purpose of 
meeting qualifying Phase I technology requirements pursuant to 
Sec. 72.42 of this chapter shall also submit reports documenting the 
measured percent SO<INF>2</INF> emissions removal to the Administrator 
on a quarterly basis, beginning the first quarter of 1997 and 
continuing through the fourth quarter of 1999. Each report shall 
include all measurements and calculations necessary to substantiate 
that the qualifying technology achieves the required percent reduction 
in SO<INF>2</INF> emissions.
    (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 
modem and EPA-provided software, unless otherwise approved by the 
Administrator.
    (g) Any cover letter text accompanying a quarterly report shall 
either be submitted in hardcopy to the Agency or be provided in 
electronic format compatible with the other data required to be 
reported under this section.
    48. Section 75.65 is revised to read as follows:


Sec. 75.65  Opacity reports.

    The owner or operator or designated representative shall report 
excess emissions of opacity recorded under Sec. 75.54(f) or 
Sec. 75.57(f), as applicable, to the applicable State or local air 
pollution control agency.
    49. Section 75.66 is amended by revising paragraph (a) and the 
first sentence of paragraph (e) introductory text; by redesignating 
paragraph (i) as paragraph (l) and revising it; and by adding 
paragraphs (i) through (k) to read as follows:


Sec. 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 Sec. 72.21 of this chapter for each submission.
* * * * *
    (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 Sec. 75.55(b) or Sec. 75.58(b), as applicable, for the use 
of a parametric monitoring method. * * *
* * * * *
    (i) Emergency fuel petition. The designated representative for an 
affected unit may submit a petition to the Administrator to use the 
emergency fuel provisions in section 2.1.4 of appendix E to this part. 
The designated representative shall include the following information 
in the petition:
    (1) Identification of the affected plant and unit(s);
    (2) A procedure for determining the NO_X emission rate 
for the unit when the emergency fuel is combusted; and
    (3) A demonstration that the permit restricts use of the fuel to 
emergencies only.
    (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 
Sec. 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<INF>2</INF> 
mass emissions (in lbs), NO_X emission rate (in lbs/mmBtu), 
CO<INF>2</INF> 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.

[[Page 28624]]

Subpart H--NO_X Mass Emissions Provisions

    50. Section 75.70 is amended by revising paragraphs (e), (f) 
introductory text and (f)(1)(iv), and by adding new paragraph (g)(6) to 
read as follows:


Sec. 75.70  NO_X mass emissions provisions.

* * * * *
    (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 
Sec. 75.21, appendix B to this part, and Sec. 75.74(c) for the 
NO_X-diluent continuous emission monitoring systems, flow 
monitoring systems, NO_X concentration monitoring systems, 
and diluent monitors required under Sec. 75.71. A NO_X 
concentration monitoring system for determining NO_X mass 
emissions in accordance with Sec. 75.71 shall meet the same 
certification testing requirements, quality assurance requirements, and 
bias test requirements as are specified in this part for an 
SO<INF>2</INF> pollutant concentration monitor, except as otherwise 
provided in Sec. 75.74(c). Units using excepted methods under 
Sec. 75.19 shall meet the applicable quality assurance requirements of 
that section, and, except as otherwise provided in Sec. 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 Sec. 75.34, 
paragraph (g) of this section, and Sec. 75.74, the owner or operator 
shall provide substitute data from monitoring systems required under 
Sec. 75.71 for each affected unit as follows:
    (1) * * *
    (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 volumetric flow monitor, and without a diluent 
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 
Secs. 75.31, 75.32 and 75.33.
* * * * *
    (g) * * *
    (6) For any unit using continuous emissions monitors, the 
procedures in Sec. 75.20(b)(3).
* * * * *
    51. Section 75.71 is amended by revising paragraphs (b) and (d)(2) 
to read as follows:


Sec. 75.71  Specific provisions for monitoring NO_X emission 
rate and heat input for the purpose of calculating NO_X mass 
emissions.

* * * * *
    (b) Moisture correction. (1) If a correction for the stack gas 
moisture content is needed to properly calculate the NO_X 
emission rate in lb/mmBtu (i.e., if the NO_X pollutant 
concentration monitor in a NO_X-diluent monitoring system 
measures on a different moisture basis from the diluent monitor), the 
owner or operator of an affected unit shall account for the moisture 
content of the flue gas on a continuous basis in accordance with 
Sec. 75.12(b).
    (2) If a correction for the stack gas moisture content is needed to 
properly calculate NO_X mass emissions in tons, in the case 
where a NO_X concentration monitoring system which measures 
on a dry basis is used with a flow rate monitor to determine 
NO_X mass emissions, the owner or operator of an affected 
unit shall account for the moisture content of the flue gas on a 
continuous basis in accordance with Sec. 75.11(b) except that the term 
``SO<INF>2</INF>'' shall be replaced by the term ``NO_X.''
    (3) If a correction for the stack gas moisture content is needed to 
properly calculate NO_X mass emissions, in the case where a 
diluent monitor that measures on a dry basis is used with a flow rate 
monitor to determine heat input, which is then multiplied by the 
NO_X emission rate, the owner or operator shall install, 
operate, maintain and quality assure a continuous moisture monitoring 
system, as described in Sec. 75.11(b).
* * * * *
    (d) * * *
    (2) Use the procedures in appendix D to this part for determining 
hourly heat input and the procedure specified in appendix E to this 
part for estimating hourly NO_X emission rate. However, the 
heat input apportionment provisions in section 2.1.2 of appendix D to 
this part shall not be used to meet the NO_X mass reporting 
provisions of this subpart. In addition, if after certification of an 
excepted monitoring system under appendix E to this part, the operation 
of a unit that reports emissions on an annual basis under Sec. 75.74(a) 
of this part exceeds a capacity factor of 20.0 percent in any calendar 
year or exceeds an annual capacity factor of 10.0 percent averaged over 
three years, or the operation of a unit that reports emissions on an 
ozone season basis under Sec. 75.74(b) of this part exceeds a capacity 
factor of 20.0 percent in any ozone season or exceeds an ozone season 
capacity factor of 10.0 percent averaged over three years, the owner or 
operator shall meet the requirements of paragraph (c) of this section 
or, if applicable, paragraph (e) of this section by no later than 
December 31 of the following calendar year.
* * * * *
    52. Text is added to reserved section 75.73 to read as follows:


Sec. 75.73  Recordkeeping and reporting.

    (a) General recordkeeping provisions. The owner or operator of any 
affected unit shall maintain for each affected unit and each non-
affected unit under Sec. 75.72(b)(2)(ii) 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. Except for the certification data 
required in Sec. 75.57(a)(4) and the initial submission of the 
monitoring plan required in Sec. 75.57(a)(5), the data shall be 
collected beginning with the earlier of the date of provisional 
certification or the deadline in Sec. 75.70. The certification data 
required in Sec. 75.57(a)(4) shall be collected beginning with the date 
of the first certification test performed. The file shall contain the 
following information:
    (1) The information required in Secs. 75.57(a)(2), (a)(4), (a)(5), 
(a)(6), (b), (c)(2), (d), (g), and (h).
    (2) The information required in Secs. 75.58(b)(2) or (b)(3) (for 
units with add-on NO_X emission controls), as applicable, (d) 
(as applicable for units using Appendix E to this part), and (f) (as 
applicable for units using the low mass emissions unit provisions of 
Sec. 75.19).
    (3) For each hour when the unit is operating, NO_X mass 
emissions, calculated in accordance with section 8.1 of appendix F to 
this part.
    (4) During the second and third calendar quarters, cumulative ozone 
season heat input and cumulative ozone season operating hours.
    (5) Heat input and NO_X methodologies for the hour.
    (6) Specific heat input record provisions for gas-fired or oil-
fired units using the procedures in appendix D to this part. In lieu of 
the information required in Sec. 75.57(c)(2), the owner or operator 
shall record the following information in this paragraph for each

[[Page 28625]]

affected gas-fired or oil-fired unit and each non-affected gas- or oil-
fired unit under Sec. 75.72(b)(2)(ii) for which the owner or operator 
is using the procedures in appendix D to this part for estimating heat 
input:
    (i) For each hour when the unit is combusting oil:
    (A) Date and hour;
    (B) Hourly average mass flow rate of oil, while the unit combusts 
oil (in lb/hr, rounded to the nearest tenth) (flag value if derived 
from missing data procedures);
    (C) Method of oil sampling (flow proportional, continuous drip, as 
delivered, manual from storage tank, or daily manual);
    (D) For units using volumetric flowmeters, volumetric flow rate of 
oil combusted each hour (in gal/hr, lb/hr, m³/hr, or bbl/hr, 
rounded to the nearest tenth) (flag value if derived from missing data 
procedures);
    (E) For units using volumetric oil flowmeters, density of oil (flag 
value if derived from missing data procedures);
    (F) Gross calorific value of oil used to determine heat input (in 
Btu/lb);
    (G) Hourly heat input rate during combustion of oil, according to 
procedures in appendix F to this part (in mmBtu/hr, to the nearest 
tenth);
    (H) 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); and
    (I) Monitoring system identification code.
    (ii) For gas-fired units or oil-fired units, using the procedures 
in appendix D to this part with an assumed density or for as-delivered 
fuel sampled from each delivery:
    (A) Measured gross calorific value and, if measuring with 
volumetric oil flowmeters, density from each fuel sample; and
    (B) Assumed gross calorific value and, if measuring with volumetric 
oil flowmeters, density used to calculate heat input rate.
    (iii) For each hour when the unit is combusting gaseous fuel:
    (A) Date and hour;
    (B) Hourly heat input rate from gaseous fuel, according to 
procedures in appendix F to this part (in mmBtu/hr, rounded to the 
nearest tenth);
    (C) Hourly flow rate of gaseous fuel, while the unit combusts gas 
(in 100 scfh) (flag value if derived from missing data procedures);
    (D) Gross calorific value of gaseous fuel used to determine heat 
input rate (in Btu/100 scf) (flag value if derived from missing data 
procedures);
    (E) 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); and
    (F) Monitoring system identification code.
    (iv) For each oil sample or sample of diesel fuel:
    (A) Date of sampling;
    (B) Gross calorific value (in Btu/lb) (flag value if derived from 
missing data procedures); and
    (C) Density or specific gravity, if required to convert volume to 
mass (flag value if derived from missing data procedures).
    (v) For each sample of gaseous fuel:
    (A) Date of sampling; and
    (B) Gross calorific value (in Btu/100 scf) (flag value if derived 
from missing data procedures).
    (vi) For each oil sample or sample of gaseous fuel:
    (A) Type of oil or gas; and
    (B) Percent carbon or F-factor of fuel.
    (7) Specific NO_X record provisions for gas-fired or oil-
fired units using the optional low mass emissions excepted methodology 
in Sec. 75.19. In lieu of recording the information in Secs. 75.57(b), 
(c)(2), (d), and (g), the owner or operator shall record, for each hour 
when the unit is operating for any portion of the hour, the following 
information for each affected low mass emissions unit for which the 
owner or operator is using the low mass emissions excepted methodology 
in Sec. 75.19(c):
    (i) Date and hour;
    (ii) If one type of fuel is combusted in the hour, fuel type 
(pipeline natural gas, natural gas, residual oil, or diesel fuel) or, 
if more than one type of fuel is combusted in the hour, the fuel type 
which results in the highest emission factors for NO_X;
    (iii) Average hourly NO_X emission rate (in lb/mmBtu, 
rounded to the nearest thousandth); and
    (iv) Hourly NO_X mass emissions (in lbs, rounded to the 
nearest tenth).
    (b) Certification, quality assurance and quality control record 
provisions. The owner or operator of any affected unit shall record the 
applicable information in Sec. 75.59 for each affected unit or group of 
units monitored at a common stack and each non-affected unit under 
Sec. 75.72(b)(2)(ii).
    (c) Monitoring plan recordkeeping provisions--(1) General 
provisions. The owner or operator of an affected unit shall prepare and 
maintain a monitoring plan for each affected unit or group of units 
monitored at a common stack and each non-affected unit under 
Sec. 75.72(b)(2)(ii). Except as provided in paragraph (d) or (f) of 
this section, a monitoring plan shall contain sufficient information on 
the continuous emission monitoring systems, excepted methodology under 
Sec. 75.19, or excepted monitoring systems under appendix D or E to 
this part and the use of data derived from these systems to demonstrate 
that all the unit's NO_X emissions are monitored and 
reported.
    (2) Whenever the owner or operator makes a replacement, 
modification, or change in the certified continuous emission monitoring 
system, excepted methodology under Sec. 75.19, excepted monitoring 
system under appendix D or E to this part, or alternative monitoring 
system under subpart E of this part, including a change in the 
automated data acquisition and handling system or in the flue gas 
handling system, that affects information reported in the monitoring 
plan (e.g., a change to a serial number for a component of a monitoring 
system), then the owner or operator shall update the monitoring plan.
    (3) Contents of the monitoring plan for units not subject to an 
Acid Rain emissions limitation. Each monitoring plan shall contain the 
information in Sec. 75.53(e)(1) in electronic format and the 
information in Sec. 75.53(e)(2) in hardcopy format. In addition, to the 
extent applicable, each monitoring plan shall contain the information 
in Secs. 75.53(f)(1)(i), (f)(2)(i), (f)(4), and (f)(5)(i) for units 
using the low mass emitter methodology in electronic format and the 
information in Secs. 75.53(f)(1)(ii), (f)(2)(ii), and (f)(5)(ii) in 
hardcopy format. The monitoring plan also shall identify, in electronic 
format, the reporting schedule for the affected unit (ozone season or 
quarterly), the beginning and end dates for the reporting schedule, and 
whether year-round reporting for the unit is required by a state or 
local agency.
    (d) General reporting provisions. (1) The designated representative 
for an affected unit shall comply with all reporting requirements in 
this section and with 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 designated representative for an affected unit shall submit 
the following for each affected unit or group of units monitored at a 
common stack and each non-affected unit under Sec. 75.72(b)(2)(ii):

[[Page 28626]]

    (i) Initial certification and recertification applications in 
accordance with Sec. 75.70(d);
    (ii) Monitoring plans in accordance with paragraph (e) of this 
section; and
    (iii) Quarterly reports in accordance with paragraph (f) of this 
section.
    (3) Other petitions and communications. The designated 
representative for an affected unit shall submit petitions, 
correspondence, application forms, and petition-related test results in 
accordance with the provisions in Sec. 75.70(h).
    (4) Quality assurance RATA reports. If requested by the permitting 
authority, the designated representative of an affected unit shall 
submit the quality assurance RATA report for each affected unit or 
group of units monitored at a common stack and each non-affected unit 
under Sec. 75.72(b)(2)(ii) by the later of 45 days after completing a 
quality assurance RATA according to section 2.3 of appendix B to this 
part or 15 days of receiving the request. The designated representative 
shall report the hardcopy information required by Sec. 75.59(a)(9) to 
the permitting authority.
    (5) Notifications. The designated representative for an affected 
unit shall submit written notice to the permitting authority according 
to the provisions in Sec. 75.61 for each affected unit or group of 
units monitored at a common stack and each non-affected unit under 
Sec. 75.72(b)(2)(ii).
    (e) Monitoring plan reporting.--(1) Electronic submission. 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 (e)(2) of this section) for each 
affected unit or group of units monitored at a common stack and each 
non-affected unit under Sec. 75.72(b)(2)(ii) as follows:
    (i) To the permitting authority, no later than 45 days prior to the 
initial certification test and at the time of recertification 
application submission; and
    (ii) To the Administrator, no later than 45 days prior to the 
initial certification test, at the time of submission of a 
recertification application, and in each electronic quarterly report.
    (2) Hardcopy submission. The designated representative of an 
affected unit shall submit all of the hardcopy information required 
under Sec. 75.53, for each affected unit or group of units monitored at 
a common stack and each non-affected unit under Sec. 75.72(b)(2)(ii), 
to the permitting authority 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 45 days prior to the initial certification test; 
with any recertification application, if a hardcopy monitoring plan 
change is associated with the recertification event; and within 30 days 
of any other event with which a hardcopy monitoring plan change is 
associated, pursuant to Sec. 75.53(b).
    (f) Quarterly reports.--(1) Electronic submission. The designated 
representative for an affected unit shall electronically report the 
data and information in this paragraph (f)(1) and in paragraphs (f)(2) 
and (3) of this section to the Administrator quarterly. Each electronic 
report must be submitted to the Administrator within 30 days following 
the end of each calendar quarter. Each electronic report shall include 
the date of report generation, for the information provided in 
paragraphs (f)(1)(ii) through (1)(vi) of this section, and shall also 
include for each affected unit or group of units monitored at a common 
stack:
    (i) Facility information:
    (A) Identification, including:
    (1) Facility/ORISPL number;
    (2) Calendar quarter and year data contained in the report; and
    (3) Electronic data reporting format version used for the report.
    (B) Location of facility, including:
    (1) Plant name and facility identification code;
    (2) EPA AIRS facility system identification code;
    (3) State facility identification code;
    (4) Source category/type;
    (5) Primary SIC code;
    (6) State postal abbreviation;
    (7) FIPS county code; and
    (8) Latitude and longitude.
    (ii) The information and hourly data required in paragraph (a) of 
this section, except for:
    (A) Descriptions of adjustments, corrective action, and 
maintenance;
    (B) Information which is incompatible with electronic reporting 
(e.g., field data sheets, lab analyses, quality control plan);
    (C) For units with 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 
Sec. 75.58(b)(3);
    (D) Information required by Sec. 75.57(h) concerning the causes of 
any missing data periods and the actions taken to cure such causes;
    (E) Hardcopy monitoring plan information required by Sec. 75.53 and 
hardcopy test data and results required by Sec. 75.59;
    (F) Records of flow polynomial equations and numerical values 
required by Sec. 75.59(a)(5)(vi);
    (G) Daily fuel sampling information required by Sec. 75.58(c)(3)(i) 
for units using assumed values under appendix D;
    (H) Information required by Sec. 75.59(b)(2) concerning transmitter 
or transducer accuracy tests;
    (I) Stratification test results required as part of the RATA 
supplementary records under Sec. 75.59(a)(7);
    (J) 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 operational problems with the unit; and
    (K) Supplementary RATA information required under 
Sec. 75.59(a)(7)(i) through Sec. 75.59(a)(7)(v), except that: the data 
under Sec. 75.59(a)(7)(ii)(A) through (T) and the data under 
Sec. 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported 
for flow RATAs in which angular compensation (measurement of pitch and/
or yaw angles) is used and for flow RATAs in which a site-specific wall 
effects adjustment factor is determined by direct measurement; and the 
data under Sec. 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs 
in which a default wall effects adjustment factor is applied.
    (iii) 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.
    (iv) Tons of NO_X emitted during quarter, cumulative tons 
of NO_X emitted during the year, and, during the second and 
third calendar quarters, cumulative tons of NO_X emitted 
during the ozone season.
    (v) During the second and third calendar quarters, cumulative heat 
input for the ozone season.
    (vi) Unit or stack or common pipe header operating hours for 
quarter, cumulative unit, stack or common pipe header operating hours 
for calendar year, and, during the second and third calendar quarters, 
cumulative operating hours during the ozone season.
    (2) The designated representative shall certify that the component 
and system identification codes and formulas in the quarterly 
electronic reports submitted to the Administrator pursuant to paragraph 
(e) of this section represent current operating conditions.
    (3) Compliance certification. The designated representative shall 
submit and sign a compliance certification in

[[Page 28627]]

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 state that:
    (i) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this part, including the quality 
assurance procedures and specifications; and
    (ii) With regard to a unit with add-on emission controls and for 
all hours where data are substituted in accordance with 
Sec. 75.34(a)(1), the add-on emission controls were operating within 
the range of parameters listed in the monitoring plan and the 
substitute values do not systematically underestimate NO_X 
emissions.
    (4) The designated representative shall comply with all of the 
quarterly reporting requirements in Secs. 75.64(d), (f), and (g).
    53. Section 75.74 is amended by:
    a. Revising paragraphs (b)(2), (c)(1) and (c)(2);
    b. Redesignating paragraphs (c)(3), (c)(4), (c)(5), (c)(6), (c)(7), 
(c)(8), (c)(9) and (c)(10), as paragraphs (c)(4), (c)(5), (c)(6), 
(c)(7), (c)(8), (c)(9), (c)(10) and (c)(11), respectively;
    c. Adding a new paragraph (c)(3); and
    d. Revising newly redesignated paragraphs (c)(4), (c)(5), (c)(6) 
and (c)(7), to read as follows:


Sec. 75.74  Annual and ozone season monitoring and reporting 
requirements.

* * * * *
    (b) * * *
    (2) Meet the requirements of this subpart during the ozone season, 
except as specified in paragraph (c) of this section.
    (c) * * *
    (1) The owner or operator of a unit that uses continuous emissions 
monitoring systems or a fuel flowmeter to meet any of the requirements 
of this subpart shall quality assure the hourly ozone season emission 
data required by this subpart. To achieve this, the owner or operator 
shall operate, maintain and calibrate each required CEMS and shall 
perform diagnostic testing and quality assurance testing of each 
required CEMS or fuel flowmeter according to the applicable provisions 
of paragraphs (c)(2) through (c)(5) of this section. Except where 
otherwise noted, the provisions of paragraphs (c)(2) and (c)(3) of this 
section apply instead of the quality assurance provisions in sections 
2.1 through 2.3 of appendix B to this part, and shall be used in lieu 
of those appendix B provisions.
    (2) Quality assurance requirements prior to the ozone season. The 
provisions of this paragraph apply to each ozone season. In the time 
period prior to the start of the current ozone season (i.e., in the 
period extending from October 1 of the previous calendar year through 
April 30 of the current calendar year), the owner or operator shall, at 
a minimum, perform the following diagnostic testing and quality 
assurance assessments, and shall maintain the following records, to 
ensure that the hourly emission data recorded at the beginning of the 
current ozone season are suitable for reporting as quality-assured 
data:
    (i) For each required gas monitor (i.e., for each NO_X 
pollutant concentration monitor and each diluent gas (CO<INF>2</INF> or 
O<INF>2</INF>) monitor, including CO<INF>2</INF> and O<INF>2</INF> 
monitors used exclusively for heat input determination and 
O<INF>2</INF> monitors used for moisture determination), a linearity 
check shall be performed and passed.
    (A) Conduct each linearity check in accordance with the general 
procedures in section 6.2 of appendix A to this part, except that the 
data validation procedures in sections 6.2(a) through (f) of appendix A 
do not apply.
    (B) Each linearity check shall be done ``hands-off,'' as described 
in section 2.2.3(c) of appendix B to this part.
    (C) In the time period extending from the date and hour in which 
the linearity check is passed through April 30 of the current calendar 
year, the owner or operator shall operate and maintain the CEMS and 
shall perform daily calibration error tests of the CEMS in accordance 
with section 2.1 of appendix B to this part. When a calibration error 
test is failed, as described in section 2.1.4 of appendix B to this 
part, corrective actions shall be taken. The additional calibration 
error test provisions of section 2.1.3 of appendix B to this part shall 
be followed. Records of the required daily calibration error tests 
shall be kept in a format suitable for inspection on a year-round 
basis.
    (D) Exceptions. (1) If the monitor passed a linearity check on or 
after January 1 of the previous year and the unit or stack on which the 
monitor is located operated for less than 336 hours in the previous 
ozone season, the owner or operator may have a grace period of up to 
168 hours to perform a linearity check. In addition, if the unit or 
stack operates for 168 hours or less in the current ozone season the 
owner or operator is exempt from the linearity check requirement for 
that ozone season and the owner or operator may submit quality assured 
data from that monitor as long as all other required quality assurance 
tests are passed. If the unit or stack operates for more than 168 hours 
in the current ozone season, the owner or operator of the unit shall 
report substitute data using the missing data procedures under 
paragraph (c)(7) of this section starting with the 169th unit or stack 
operating hour of the ozone season and continuing until the successful 
completion of a linearity check.
    (2) If a monitor does not qualify for an exception under paragraph 
(c)(2)(i)(D)(1) and if a required linearity check has not been 
completed prior to the start of the current ozone season, follow the 
applicable procedures in paragraph (c)(3)(vi) of this section.
    (ii) For each required CEMS (i.e., for each NO_X 
concentration monitoring system, each NO_X-diluent monitoring 
system, each flow rate monitoring system, each moisture monitoring 
system and each diluent gas CEMS used exclusively for heat input 
determination), a relative accuracy test audit (RATA) shall be 
performed and passed.
    (A) Conduct each RATA in accordance with the applicable procedures 
in sections 6.5 through 6.5.10 of appendix A to this part, except that 
the data validation procedures in sections 6.5(f)(1) through (f)(6) do 
not apply, and, for flow rate monitoring systems, the required RATA 
load level(s) shall be as specified in this paragraph.
    (B) Each RATA shall be done ``hands-off,'' as described in section 
2.3.2 (c) of appendix B to this part. The provisions in section 2.3.1.4 
of appendix B to this part, pertaining to the number of allowable RATA 
attempts, shall apply.
    (C) For flow rate monitoring systems installed on peaking units or 
bypass stacks, a single-load RATA is required. For all other flow rate 
monitoring systems, a 2-load RATA is required at the two most 
frequently-used load levels (as defined under section 6.5.2.1 of 
appendix A to this part), with the following exceptions. A 3-load flow 
RATA is required at least once in every period of five consecutive 
calendar years. A 3-load RATA is also required if the flow monitor 
polynomial coefficients or K factor(s) are changed prior to conducting 
the flow RATA required under this paragraph.
    (D) A bias test of each required NO_X concentration 
monitoring system, each NO_X-diluent monitoring system and 
each flow rate monitoring system shall be performed in accordance with 
section 7.6 of appendix A to this part. If the bias test is failed, a 
bias adjustment factor (BAF) shall be calculated for the monitoring 
system, as described in section 7.6.5 of appendix A to this part and 
shall be applied to the subsequent data recorded by the CEMS.

[[Page 28628]]

    (E) In the time period extending from the hour of completion of the 
required RATA through April 30 of the current calendar year, the owner 
or operator shall operate and maintain the CEMS by performing, at a 
minimum, the following activities:
    (1) The owner or operator shall perform daily calibration error 
tests and (if applicable) daily flow monitor interference checks, 
according to section 2.1 of appendix B to this part. When a daily 
calibration error test or interference check is failed, as described in 
section 2.1.4 of appendix B to this part, corrective actions shall be 
taken. The additional calibration error test provisions in section 
2.1.3 of appendix B to this part shall be followed. Records of the 
required daily calibration error tests and interference checks shall be 
kept in a format suitable for inspection on a year-round basis.
    (2) If the owner or operator makes a replacement, modification, or 
change in a certified monitoring system that significantly affects the 
ability of the system to accurately measure or record NO_X 
mass emissions or heat input or to meet the requirements of Sec. 75.21 
or appendix B to this part, the owner or operator shall recertify the 
monitoring system according to Sec. 75.20(b).
    (F) If the results of a RATA performed according to the provisions 
of this paragraph indicate that the CEMS qualifies for an annual RATA 
frequency (see Figure 2 in appendix B to this part), the RATA may be 
used to quality assure data for the entire current ozone season.
    (G) If the results of a RATA performed according to the provisions 
of this paragraph indicate that the CEMS qualifies for a semiannual 
RATA frequency rather than an annual frequency, provided that the RATA 
was completed on or after January 1 of the current calendar year, the 
RATA may be used to quality assure data for the entire current ozone 
season. However, if the RATA was performed in the fourth calendar 
quarter of the previous year, the RATA may only be used to quality 
assure data for a part of the current ozone season, from May 1 through 
June 30. An additional RATA is then required by June 30 of the current 
calendar year to quality assure the remainder of the data (from June 30 
through September 30) for the current ozone season. If such an 
additional RATA is required but is not completed by June 30 of the 
current calendar year, data from the CEMS shall be considered invalid 
as of the first unit or stack operating hour subsequent to June 30 of 
the current calendar year and shall remain invalid until the required 
RATA is performed and passed.
    (H) Exceptions. (1) If the monitoring system passed a RATA on or 
after January 1 of the previous year and the unit or stack on which the 
monitor is located operated for less than 336 hours in the previous 
ozone season, the owner or operator may have a grace period of up to 
720 hours to perform a RATA. If the unit or stack operates for 720 
hours or less in the current ozone season, the owner or operator of the 
unit is exempt from the requirement to perform a RATA for that ozone 
season and the owner or operator may submit quality assured data from 
that monitor as long as all other required quality assurance tests are 
passed. If the unit or stack operates for more than 720 hours in the 
current ozone season, the owner or operator of the unit or stack shall 
report substitute data using the missing data procedures under 
paragraph (c)(7) of this section, starting with the 721st unit 
operating hour and continuing until the successful completion of the 
RATA.
    (2) If a monitor does not qualify for a grace period under 
paragraph (c)(2)(ii)(H)(1) of this section and if a required RATA has 
not been completed prior to the start of the current ozone season, 
follow the applicable procedures in paragraph (c)(3)(vi) of this 
section.
    (3) Quality assurance requirements within the ozone season. The 
provisions of this paragraph apply to each ozone season. The owner or 
operator shall, at a minimum, perform the following quality assurance 
testing during the ozone season, i.e. in the time period extending from 
May 1 through September 30 of each calendar year:
    (i) Daily calibration error tests and (if applicable) interference 
checks of each CEMS required by this subpart shall be performed in 
accordance with sections 2.1.1 and 2.1.2 of appendix B to this part. 
The applicable provisions in sections 2.1.3, 2.1.4 and 2.1.5 of 
appendix B to this part, pertaining, respectively, to additional 
calibration error tests and calibration adjustments, data validation, 
and quality assurance of data with respect to daily assessments, shall 
also apply.
    (ii) For each gas monitor required by this subpart, linearity 
checks shall be performed in the second and third calendar quarters, in 
accordance with section 2.2.1 of appendix B to this part (see also 
paragraph (c)(3)(vii) of this section). For the second calendar quarter 
of the year, only unit or stack operating hours in the months of May 
and June shall be included when determining whether the second calendar 
quarter is a ``QA operating quarter'' (as defined in Sec. 72.2 of this 
chapter). Data validation for these linearity checks shall be done in 
accordance with sections 2.2.3(a) through (e) of appendix B to this 
part. The grace period provision in section 2.2.4 of appendix B to this 
part does not apply to these linearity checks. If the required 
linearity check has not been completed by the end of the calendar 
quarter, unless the conditional data validation provisions of 
Sec. 75.20(b)(3) are applied, data from the CEMS are considered to be 
invalid, beginning with the first unit or stack operating hour after 
the end of the quarter and shall remain invalid until a linearity check 
of the CEMS is performed and passed.
    (iii) For each flow monitoring system required by this subpart, 
flow-to-load ratio tests are required in the second and third calendar 
quarters, in accordance with section 2.2.5 of appendix B to this part. 
If the flow-to-load ratio test for the second calendar quarter is 
failed, the owner or operator shall declare the flow monitor out-of-
control as of the first unit or stack operating hour following the 
second calendar quarter and shall either implement Option 1 in section 
2.2.5.1 of appendix B to this part or Option 2 in section 2.2.5.2 of 
appendix B to this part. If the flow-to-load ratio test for the third 
calendar quarter is failed, data from the flow monitor shall be 
considered invalid at the beginning of the next ozone season unless, 
prior to May 1 of the next calendar year, the owner or operator has 
either successfully implemented Option 1 in section 2.2.5.1 of appendix 
B to this part or Option 2 in section 2.2.5.2 of appendix B to this 
part, or unless a flow RATA has been performed and passed in accordance 
with paragraph (c)(2)(ii) of this section.
    (iv) For each differential pressure-type flow monitor used to meet 
the requirements of this subpart, quarterly leak checks are required in 
the second and third calendar quarters, in accordance with section 
2.2.2 of appendix B to this part. For the second calendar quarter of 
the year, only unit or stack operating hours in the months of May and 
June shall be included when determining whether the second calendar 
quarter is a QA operating quarter (as defined in Sec. 72.2 of this 
chapter). Data validation for quarterly flow monitor leak checks shall 
be done in accordance with section 2.2.3(g) of appendix B to this part. 
If the leak check for the third calendar quarter is failed and a 
subsequent leak check is not passed by the end of the ozone season, 
then data from the flow monitor shall be considered invalid at the 
beginning of the next ozone season unless a leak

[[Page 28629]]

check is passed prior to May 1 of the next calendar year.
    (v) A fuel flow-to-load ratio test in section 2.1.7 of appendix D 
to this part shall be performed in the second and third calendar 
quarters if, for a unit using a fuel flowmeter to determine heat input 
under this subpart, the owner or operator has elected to use the fuel 
flow-to-load ratio test to extend the deadline for the next fuel 
flowmeter accuracy test. If a fuel flow-to-load ratio test is failed, 
follow the applicable procedures and data validation provisions in 
section 2.1.7.4 of appendix D to this part. If the fuel flow-to-load 
ratio test for the third calendar quarter is failed, data from the fuel 
flowmeter shall be considered invalid at the beginning of the next 
ozone season unless the requirements of section 2.1.7.4 of appendix D 
to this part have been fully met prior to May 1 of the next calendar 
year.
    (vi) If, at the start of the current ozone season (i.e., as of May 
1 of the current calendar year), the linearity check or RATA required 
under paragraph (c)(2)(i) or (c)(2)(ii) of this section has not been 
performed for a particular monitor or monitoring system, and if, during 
the previous ozone season, the unit or stack on which the monitoring 
system is installed operated for 336 hours or more the owner or 
operator shall invalidate all data from the CEMS until either:
    (A) The required linearity check or RATA of the CEMS has been 
performed and passed; or
    (B) A ``probationary calibration error test'' of the CEMS is passed 
in accordance with Sec. 75.20(b)(3). Note that a calibration error test 
passed on April 30 may be used as the probationary calibration error 
test, to ensure that emission data recorded by the CEMS at the 
beginning of the ozone season will have a conditionally valid status. 
Once the probationary calibration error test has been passed, the owner 
or operator shall perform the required linearity check or RATA in 
accordance with the conditional data validation provisions and within 
the associated timelines in Sec. 75.20(b)(3), with the term 
``diagnostic'' applying instead of the term ``recertification''. 
However, in lieu of the provisions in Sec. 75.20(b)(3)(ix), the owner 
or operator shall follow the applicable provisions in paragraphs 
(c)(3)(xi) and (c)(3)(xii) of this section.
    (vii) A RATA which is performed and passed during the second or 
third quarter of the current calendar year may be used to quality 
assure data in the next ozone season, provided that:
    (A) The results of the RATA indicate that the CEMS qualifies for an 
annual RATA frequency (see Figure 2 in appendix B to this part); and
    (B) The CEMS is continuously operated and maintained, and daily 
calibration error tests and (if applicable) interference checks of the 
CEMS are performed in the time period extending from the end of the 
current ozone season (October 1 of the current calendar year) through 
April 30 of the next calendar year; and
    (C) For a gas monitoring system, the linearity check requirement of 
paragraph (c)(2)(i) of this section is met prior to May 1 of the next 
calendar year.
    (D) If conditions in paragraphs (c)(3)(vii)(A), (B) and, if 
applicable, (c)(3)(vii)(C) of this section are met, then a RATA 
completed and passed in the second or third calendar quarter of the 
current year may be used to quality assure data for the next ozone 
season, as follows:
    (1) If the RATA is completed and passed in the second calendar 
quarter of the current year, the RATA may be used to quality assure 
data from the CEMS through June 30 of the next calendar year.
    (2) If the RATA is completed and passed in the third calendar 
quarter of the current year, the RATA may be used to quality assure 
data from the CEMS through September 30 of the next calendar year.
    (viii) If a linearity check performed to meet the requirement of 
paragraph (c)(2)(i) of this section is completed and passed in the 
second calendar quarter of the current year, provided that the date and 
hour of completion of the test is within the first 168 unit or stack 
operating hours of the current ozone season, the linearity check may be 
used to satisfy both the requirement of paragraph (c)(2)(i) of this 
section and to meet the second quarter linearity check requirement of 
paragraph (c)(3)(ii) of this section.
    (ix) If, for any required CEMS, diagnostic linearity checks or 
RATAs other than those required by this section are performed during 
the ozone season, use the applicable data validation procedures in 
section 2.2.3 (for linearity checks) or 2.3.2 (for RATAs) of appendix B 
to this part.
    (x) If any required CEMS is recertified within the ozone season, 
use the data validation provisions in Sec. 75.20(b)(3) and paragraphs 
(c)(3)(xi) and (c)(3)(xii) of this section.
    (xi) If, at the end of the second quarter of any calendar year, a 
required quality assurance, diagnostic or recertification test of a 
monitoring system has not been completed, and if data contained in the 
quarterly report are conditionally valid pending the results of test(s) 
to be completed in a subsequent quarter, the owner or operator shall 
indicate this by means of a suitable conditionally valid data flag in 
the electronic quarterly report for the second calendar quarter. The 
owner or operator shall resubmit the report for the second quarter if 
the required quality assurance, diagnostic or recertification test is 
subsequently failed. In the resubmitted report, the owner or operator 
shall use the appropriate missing data routine in Sec. 75.31 or 
Sec. 75.33 to replace with substitute data each hour of conditionally 
valid data that was invalidated by the failed quality assurance, 
diagnostic or recertification test. Alternatively, if any required 
quality assurance, diagnostic or recertification test is not completed 
by the end of the second calendar quarter but is completed no later 
than 30 days after the end of that quarter (i.e., prior to the deadline 
for submitting the quarterly report under Sec. 75.73), the test data 
and results may be submitted with the second quarter report even though 
the test date(s) are from the third calendar quarter. In such 
instances, if the quality assurance, diagnostic or recertification 
test(s) are passed in accordance with the provisions of 
Sec. 75.20(b)(3), conditionally valid data may be reported as quality-
assured, in lieu of reporting a conditional data flag. If the tests are 
failed and if conditionally valid data are replaced, as appropriate, 
with substitute data, then neither the reporting of a conditional data 
flag nor resubmission is required.
    (xii) If, at the end of the third quarter of any calendar year, a 
required quality assurance, diagnostic or recertification test of a 
monitoring system has not been completed, and if data contained in the 
quarterly report are conditionally valid pending the results of test(s) 
to be completed, the owner or operator shall do one of the following:
    (A) If the results of the required tests are not available within 
30 days of the end of the third calendar quarter and cannot be 
submitted with the quarterly report for the third calendar quarter, 
then the test results are considered to be missing and the owner or 
operator shall use the appropriate missing data routine in Sec. 75.31 
or Sec. 75.33 to replace with substitute data each hour of 
conditionally valid data in the third quarter report. In addition, if 
the data in the second quarterly report were flagged as conditionally 
valid at the end of the quarter, pending the results of the same 
missing tests, the owner or operator shall resubmit the report for the 
second quarter and shall use the appropriate missing data routine in 
Sec. 75.31 or Sec. 75.33 to replace with substitute data

[[Page 28630]]

each hour of conditionally valid data associated with the missing 
quality assurance, diagnostic or recertification tests; or
    (B) If the required quality assurance, diagnostic or 
recertification tests are completed no later than 30 days after the end 
of the third calendar quarter, the test data and results may be 
submitted with the third quarter report even though the test date(s) 
are from the fourth calendar quarter. In this instance, if the required 
tests are passed in accordance with the provisions of Sec. 75.20(b)(3), 
all conditionally valid data associated with the tests shall be 
reported as quality assured. If the tests are failed, the owner or 
operator shall use the appropriate missing data routine in Sec. 75.31 
or Sec. 75.33 to replace with substitute data each hour of 
conditionally valid data associated with the failed test(s). In 
addition, if the data in the second quarterly report were flagged as 
conditionally valid at the end of the quarter, pending the results of 
the same failed test(s), the owner or operator shall resubmit the 
report for the second quarter and shall use the appropriate missing 
data routine in Sec. 75.31 or Sec. 75.33 to replace with substitute 
data each hour of conditionally valid data associated with the failed 
test(s).
    (4) The owner or operator of a unit using the procedures in 
appendix D of this part to determine heat input is required to maintain 
fuel flowmeters only during the ozone season, except that for purposes 
of determining the deadline for the next periodic quality assurance 
test on the fuel flowmeter, the owner or operator shall include all 
fuel flowmeter QA operating quarters (as defined in Sec. 72.2) for the 
entire calendar year, not just fuel flowmeter QA operating quarters in 
the ozone season. For each calendar year, the owner or operator shall 
record, for each fuel flowmeter, the number of fuel flowmeter QA 
operating quarters.
    (5) The owner or operator of a unit using the procedures in 
appendix D of this part to determine heat input is only required to 
sample fuel for the purposes of determining density and GCV during the 
ozone season, except that:
    (i) The owner or operator of a unit that performs sampling from the 
fuel storage tank upon delivery must sample the tank between the date 
and hour of the most recent delivery before the first date and hour 
that the unit operates in the ozone season and the first date and hour 
that the unit operates in the ozone season.
    (ii) The owner or operator of a unit that performs sampling upon 
delivery from the delivery vehicle must ensure that all shipments 
received during the calendar year are sampled.
    (iii) The owner or operator of a unit that performs sampling on 
each day the unit combusts fuel or that performs fuel sampling 
continuously must sample the fuel starting on the first day the unit 
operates during the ozone season. The owner or operator then shall use 
that sampled value for all hours of combustion during the first day of 
unit operation, continuing until the date and hour of the next sample.
    (6) The owner or operator shall, in accordance with Sec. 75.73, 
record and report the hourly data required by this subpart and shall 
record and report the results of all required quality assurance tests, 
as follows:
    (i) All hourly emission data for the period of time from May 1 
through September 30 of each calendar year shall be recorded and 
reported. For missing data purposes, only the data recorded in the time 
period from May 1 through September 30 shall be considered quality-
assured;
    (ii) The results of all daily calibration error tests and flow 
monitor interference checks performed in the time period from May 1 
through September 30 shall be recorded and reported;
    (iii) For the time periods described in paragraphs (c)(2)(i)(C) and 
(c)(2)(ii)(E) of this section, hourly emission data and the results of 
all daily calibration error tests and flow monitor interference checks 
shall be recorded. The results of all daily calibration error tests and 
flow monitor interference checks performed in the time period from 
April 1 through April 30 shall be reported. The owner or operator may 
also report the hourly emission data and unit operating data recorded 
in the time period from April 1 through April 30. However, only the 
emission data recorded in the time period from May 1 through September 
30 shall be used for NO_X mass compliance determination;
    (iv) The results of all required quality assurance tests (RATAs, 
linearity checks, flow-to-load ratio tests and leak checks) performed 
during the ozone season shall be reported in the appropriate ozone 
season quarterly report; and
    (v) The results of RATAs (and any other quality assurance test(s) 
required under paragraph (c)(2) or (c)(3) of this section) which affect 
data validation for the current ozone season, but which were performed 
outside the ozone season (i.e., between October 1 of the previous 
calendar year and April 30 of the current calendar year), shall be 
reported in the quarterly report for the second quarter of the current 
calendar year.
    (7) The owner or operator shall use only quality-assured data from 
within ozone seasons in the substitute data procedures under subpart D 
of this part and section 2.4.2 of appendix D to this part.
    (i) The lookback periods (e.g., 2160 quality-assured monitor 
operating hours for a NO_X-diluent continuous emission 
monitoring system, a NO_X concentration monitoring system, or 
a flow monitoring system) used to calculate missing data must include 
only quality-assured data from periods within ozone seasons.
    (ii) The missing data procedures of Secs. 75.31 through 75.33 shall 
be used, with two exceptions. First, when the NO_X emission 
rate or NO_X concentration of the unit was consistently lower 
in the previous ozone season because the unit combusted a fuel that 
produces less NO_X than the fuel currently being combusted; 
and second, when the unit's add-on emission controls are not working 
properly, as shown by the parametric data recorded under paragraph 
(c)(8) of this section. In those two cases, the owner or operator shall 
substitute the maximum potential NO_X emission rate, as 
defined in Sec. 72.2 of this chapter, from a NO_X-diluent 
continuous emission monitoring system, or the maximum potential 
concentration of NO_X, as defined in section 2.1.2.1 of 
appendix A to this part, from a NO_X concentration monitoring 
system. The maximum potential value used shall be for the fuel 
currently being combusted. The length of time for which the owner or 
operator shall substitute these maximum potential values for each hour 
of missing NO_X operator shall substitute these maximum 
potential value for each hour of missing NO_X data, shall be 
as follows:
    (A) For a unit that changed fuels, substitute the maximum potential 
values until the first hour when the unit combusts a fuel that produces 
the same or less NO_X than the fuel combusted in the previous 
ozone season; and
    (B) For a unit with add-on emission controls that are not working 
properly, substitute the maximum potential values until the first hour 
in which the add-on emission controls are documented to be operating 
properly, according to paragraph (c)(8) of this section.
* * * * *
    54. Appendix A to part 75 is amended by--
    a. Revising sections 2 through 2.1.1.4;
    b. Adding section 2.1.1.5;
    c. Revising sections 2.1.2 through 2.1.2.4;
    d. Adding section 2.1.2.5;

[[Page 28631]]

    e. Revising section 2.1.3;
    f. Adding sections 2.1.3.1 through 2.1.3.3;
    g. Revising section 2.1.4;
    h. Adding sections 2.1.4.1 through 2.1.6;
    i. Removing and reserving section 2.2 and removing sections 2.2.1 
through 2.2.2.2 to read as follows:

Appendix A to Part 75--Specifications and Test Procedures

* * * * *

2. Equipment Specifications

2.1  Instrument Span and Range

    In implementing sections 2.1.1 through 2.1.6 of this appendix, 
set the measurement range for each parameter (SO<INF>2</INF>, 
NO_X, CO<INF>2</INF>, O<INF>2</INF>, or flow rate) high 
enough to prevent full-scale exceedances from occurring, yet low 
enough to ensure good measurement accuracy and to maintain a high 
signal-to-noise ratio. To meet these objectives, select the range 
such that the readings obtained during typical unit operation are 
kept, to the extent practicable, between 20.0 and 80.0 percent of 
full-scale range of the instrument. These guidelines do not apply 
to: (1) SO<INF>2</INF> readings obtained during the combustion of 
very low sulfur fuel (as defined in Sec. 72.2 of this chapter); (2) 
SO<INF>2</INF> or NO_X readings recorded on the high 
measurement range, for units with SO<INF>2</INF> or NO_X 
emission controls and two span values; or (3) SO<INF>2</INF> or 
NO_X readings less than 20.0 percent of full-scale on the 
low measurement range for a dual span unit with SO<INF>2</INF> or 
NO_X emission controls, provided that the readings occur 
during periods of high control device efficiency.

2.1.1  SO<INF>2</INF> Pollutant Concentration Monitors

    Determine, as indicated in this section 2, the span value(s) and 
range(s) for an SO<INF>2</INF> pollutant concentration monitor so 
that all potential and expected concentrations can be accurately 
measured and recorded. Note that if a unit exclusively combusts 
fuels that are very low sulfur fuels (as defined in Sec. 72.2 of 
this chapter), the SO<INF>2</INF> monitor span requirements in 
Sec. 75.11(e)(3)(iv) apply in lieu of the requirements of this 
section.

2.1.1.1  Maximum Potential Concentration

    (a) Make an initial determination of the maximum potential 
concentration (MPC) of SO<INF>2</INF> by using Equation A-1a or A-
1b. Base the MPC calculation on the maximum percent sulfur and the 
minimum gross calorific value (GCV) for the highest-sulfur fuel to 
be burned. The maximum sulfur content and minimum GCV shall be 
determined from all available fuel sampling and analysis data for 
that fuel from the previous 12 months (minimum), excluding clearly 
anomalous fuel sampling values. If the designated representative 
certifies that the highest-sulfur fuel is never burned alone in the 
unit during normal operation but is always blended or co-fired with 
other fuel(s), the MPC may be calculated using a best estimate of 
the highest sulfur content and lowest gross calorific value expected 
for the blend or fuel mixture and inserting these values into 
Equation A-1a or A-1b. Derive the best estimate of the highest 
percent sulfur and lowest GCV for a blend or fuel mixture from 
weighted-average values based upon the historical composition of the 
blend or mixture in the previous 12 (or more) months. If 
insufficient representative fuel sampling data are available to 
determine the maximum sulfur content and minimum GCV, use values 
from contract(s) for the fuel(s) that will be combusted by the unit 
in the MPC calculation.
    (b) Alternatively, if a certified SO<INF>2</INF> CEMS is already 
installed, the owner or operator may make the initial MPC 
determination based upon quality assured historical data recorded by 
the CEMS. If this option is chosen, the MPC shall be the maximum 
SO<INF>2</INF> concentration observed during the previous 720 (or 
more) quality assured monitor operating hours when combusting the 
highest-sulfur fuel (or highest-sulfur blend if fuels are always 
blended or co-fired) that is to be combusted in the unit or units 
monitored by the SO<INF>2</INF> monitor. For units with 
SO<INF>2</INF> emission controls, the certified SO<INF>2</INF> 
monitor used to determine the MPC must be located at or before the 
control device inlet. Report the MPC and the method of determination 
in the monitoring plan required under Sec. 75.53.
    (c) When performing fuel sampling to determine the MPC, use ASTM 
Methods: ASTM D3177-89, ``Standard Test Methods for Total Sulfur in 
the Analysis Sample of Coal and Coke''; ASTM D4239-85, ``Standard 
Test Methods for Sulfur in the Analysis Sample of Coal and Coke 
Using High Temperature Tube Furnace Combustion Methods''; ASTM 
D4294-90, ``Standard Test Method for Sulfur in Petroleum Products by 
Energy-Dispersive X-Ray Fluorescence Spectroscopy''; ASTM D1552-90, 
``Standard Test Method for Sulfur in Petroleum Products (High 
Temperature Method)''; ASTM D129-91, ``Standard Test Method for 
Sulfur in Petroleum Products (General Bomb Method)''; ASTM D2622-92, 
``Standard Test Method for Sulfur in Petroleum Products by X-Ray 
Spectrometry'' for sulfur content of solid or liquid fuels; ASTM 
D3176-89, ``Standard Practice for Ultimate Analysis of Coal and 
Coke''; ASTM D240-87 (Reapproved 1991), ``Standard Test Method for 
Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 
Calorimeter''; or ASTM D2015-91, ``Standard Test Method for Gross 
Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter'' 
for GCV (incorporated by reference under Sec. 75.6).
[GRAPHIC] [TIFF OMITTED] TR26MY99.000

    or
[GRAPHIC] [TIFF OMITTED] TR26MY99.001

Where,

MPC = Maximum potential concentration (ppm, wet basis). (To convert 
to dry basis, divide the MPC by 0.9.)
MEC = Maximum expected concentration (ppm, wet basis). (To convert 
to dry basis, divide the MEC by 0.9).
%S = Maximum sulfur content of fuel to be fired, wet basis, weight 
percent, as determined by ASTM D3177-89, ASTM D4239-85, ASTM D4294-
90, ASTM D1552-90, ASTM D129-91, or ASTM D2622-92 for solid or 
liquid fuels (incorporated by reference under Sec. 75.6).
%O<INF>2w</INF> = Minimum oxygen concentration, percent wet basis, 
under typical operating conditions.
%CO<INF>2w</INF> = Maximum carbon dioxide concentration, percent wet 
basis, under typical operating conditions.
11.32  x  10⁶ = Oxygen-based conversion factor in Btu/lb 
(ppm)/%.
66.93  x  10⁶ = Carbon dioxide-based conversion factor in 
Btu/lb (ppm)/%.

    Note: All percent values to be inserted in the equations of this 
section are to be expressed as a percentage, not a fractional value 
(e.g., 3, not .03).

2.1.1.2  Maximum Expected Concentration

    (a) Make an initial determination of the maximum expected 
concentration (MEC) of SO<INF>2</INF> whenever: (a) SO<INF>2</INF> 
emission controls are used; or (b) both high-sulfur and low-sulfur 
fuels (e.g., high-sulfur coal and low-sulfur coal or different 
grades of fuel oil) or high-sulfur and low-sulfur fuel blends are 
combusted as primary or backup fuels in a unit without 
SO<INF>2</INF> emission controls. For units with SO<INF>2</INF> 
emission controls, use Equation A-2 to make the initial MEC 
determination. When high-sulfur and low-sulfur fuels or blends are 
burned as primary or backup fuels in a unit without SO<INF>2</INF> 
controls, use Equation A-1a or A-1b to calculate the initial MEC 
value for each fuel or blend, except for: (1) the highest-sulfur 
fuel or blend (for which the MPC was previously calculated in 
section 2.1.1.1 of this appendix); (2) fuels or blends that are very 
low sulfur fuels (as defined in Sec. 72.2 of this chapter); or (3) 
fuels or blends that are used only for unit startup.
    (b) For each MEC determination, substitute into Equation A-1a or 
A-1b the highest sulfur content and minimum GCV value for

[[Page 28632]]

that fuel or blend, based upon all available fuel sampling and 
analysis results from the previous 12 months (or more), or, if fuel 
sampling data are unavailable, based upon fuel contract(s).
    (c) Alternatively, if a certified SO<INF>2</INF> CEMS is already 
installed, the owner or operator may make the initial MEC 
determination(s) based upon historical monitoring data. If this 
option is chosen for a unit with SO<INF>2</INF> emission controls, 
the MEC shall be the maximum SO<INF>2</INF> concentration measured 
downstream of the control device outlet by the CEMS over the 
previous 720 (or more) quality assured monitor operating hours with 
the unit and the control device both operating normally. For units 
that burn high- and low-sulfur fuels or blends as primary and backup 
fuels and have no SO<INF>2</INF> emission controls, the MEC for each 
fuel shall be the maximum SO<INF>2</INF> concentration measured by 
the CEMS over the previous 720 (or more) quality assured monitor 
operating hours in which that fuel or blend was the only fuel being 
burned in the unit.
[GRAPHIC] [TIFF OMITTED] TR26MY99.002

Where:

MEC = Maximum expected concentration (ppm).
MPC = Maximum potential concentration (ppm), as determined by Eq. A-
1a or A-1b.
RE = Expected average design removal efficiency of control equipment 
(%).

2.1.1.3  Span Value(s) and Range(s)

    Determine the high span value and the high full-scale range of 
the SO<INF>2</INF> monitor as follows. (Note: For purposes of this 
part, the high span and range refer, respectively, either to the 
span and range of a single span unit or to the high span and range 
of a dual span unit.) The high span value shall be obtained by 
multiplying the MPC by a factor no less than 1.00 and no greater 
than 1.25. Round the span value upward to the next highest multiple 
of 100 ppm. If the SO<INF>2</INF> span concentration is 
<ls-thn-eq>500 ppm, the span value may be rounded upward to the next 
highest multiple of 10 ppm, instead of the nearest 100 ppm. The high 
span value shall be used to determine concentrations of the 
calibration gases required for daily calibration error checks and 
linearity tests. Select the full-scale range of the instrument to be 
consistent with section 2.1 of this appendix and to be greater than 
or equal to the span value. Report the full-scale range setting and 
calculations of the MPC and span in the monitoring plan for the 
unit. Note that for certain applications, a second (low) 
SO<INF>2</INF> span and range may be required (see section 2.1.1.4 
of this appendix). If an existing state, local, or federal 
requirement for span of an SO<INF>2</INF> pollutant concentration 
monitor requires a span lower than that required by this section or 
by section 2.1.1.4 of this appendix, the state, local, or federal 
span value may be used if a satisfactory explanation is included in 
the monitoring plan, unless span and/or range adjustments become 
necessary in accordance with section 2.1.1.5 of this appendix. Span 
values higher than those required by either this section or section 
2.1.1.4 of this appendix must be approved by the Administrator.

2.1.1.4  Dual Span and Range Requirements

    For most units, the high span value based on the MPC, as 
determined under section 2.1.1.3 of this appendix will suffice to 
measure and record SO<INF>2</INF> concentrations (unless span and/or 
range adjustments become necessary in accordance with section 
2.1.1.5 of this appendix). In some instances, however, a second 
(low) span value based on the MEC may be required to ensure accurate 
measurement of all possible or expected SO<INF>2</INF> 
concentrations. To determine whether two SO<INF>2</INF> span values 
are required, proceed as follows:
    (a) For units with SO<INF>2</INF> emission controls, compare the 
MEC from section 2.1.1.2 of this appendix to the high full-scale 
range value from section 2.1.1.3 of this appendix. If the MEC is 
<gr-thn-eq>20.0 percent of the high range value, then the high span 
value and range determined under section 2.1.1.3 of this appendix 
are sufficient. If the MEC is <20.0 percent of the high range value, 
then a second (low) span value is required.
    (b) For units that combust high- and low-sulfur primary and 
backup fuels (or blends) and have no SO<INF>2</INF> controls, 
compare the high range value from section 2.1.1.3 of this appendix 
(for the highest-sulfur fuel or blend) to the MEC value for each of 
the other fuels or blends, as determined under section 2.1.1.2 of 
this appendix. If all of the MEC values are <gr-thn-eq>20.0 percent 
of the high range value, the high span and range determined under 
section 2.1.1.3 of this appendix are sufficient, regardless of which 
fuel or blend is burned in the unit. If any MEC value is <20.0 
percent of the high range value, then a second (low) span value must 
be used when that fuel or blend is combusted.
    (c) When two SO<INF>2</INF> spans are required, the owner or 
operator may either use a single SO<INF>2</INF> analyzer with a dual 
range (i.e., low- and high-scales) or two separate SO<INF>2</INF> 
analyzers connected to a common sample probe and sample interface. 
For units with SO<INF>2</INF> emission controls, the owner or 
operator may use a low range analyzer and a default high range 
value, as described in paragraph (f) of this section, in lieu of 
maintaining and quality assuring a high-scale range. Other monitor 
configurations are subject to the approval of the Administrator.
    (d) The owner or operator shall designate the monitoring systems 
and components in the monitoring plan under Sec. 75.53 as follows: 
designate the low and high monitor ranges as separate SO<INF>2</INF> 
components of a single, primary SO<INF>2</INF> monitoring system; or 
designate the low and high monitor ranges as the SO<INF>2</INF> 
components of two separate, primary SO<INF>2</INF> monitoring 
systems; or designate the normal monitor range as a primary 
monitoring system and the other monitor range as a non-redundant 
backup monitoring system; or, when a single, dual-range 
SO<INF>2</INF> analyzer is used, designate the low and high ranges 
as a single SO<INF>2</INF> component of a primary SO<INF>2</INF> 
monitoring system (if this option is selected, use a special dual-
range component type code, as specified by the Administrator, to 
satisfy the requirements of Sec. 75.53(e)(1)(iv)(D)); or, for units 
with SO<INF>2</INF> controls, if the default high range value is 
used, designate the low range analyzer as the SO<INF>2</INF> 
component of a primary SO<INF>2</INF> monitoring system. Do not 
designate the default high range as a monitoring system or 
component. Other component and system designations are subject to 
approval by the Administrator. Note that the component and system 
designations for redundant backup monitoring systems shall be the 
same as for primary monitoring systems.
    (e) Each monitoring system designated as primary or redundant 
backup shall meet the initial certification and quality assurance 
requirements for primary monitoring systems in Sec. 75.20(c) or 
Sec. 75.20(d)(1), as applicable, and appendices A and B to this 
part, with one exception: relative accuracy test audits (RATAs) are 
required only on the normal range (for units with SO<INF>2</INF> 
emission controls, the low range is considered normal). Each 
monitoring system designated as a non-redundant backup shall meet 
the applicable quality assurance requirements in Sec. 75.20(d)(2).
    (f) For dual span units with SO<INF>2</INF> emission controls, 
the owner or operator may, as an alternative to maintaining and 
quality assuring a high monitor range, use a default high range 
value. If this option is chosen, the owner or operator shall report 
a default SO<INF>2</INF> concentration of 200 percent of the MPC for 
each unit operating hour in which the full-scale of the low range 
SO<INF>2</INF> analyzer is exceeded.
    (g) The high span value and range shall be determined in 
accordance with section 2.1.1.3 of this appendix. The low span value 
shall be obtained by multiplying the MEC by a factor no less than 
1.00 and no greater than 1.25, and rounding the result upward to the 
next highest multiple of 10 ppm (or 100 ppm, as appropriate). For 
units that burn high- and low-sulfur primary and backup fuels or 
blends and have no SO<INF>2</INF> emission controls, select, as the 
basis for calculating the appropriate low span value and range, the 
fuel-specific MEC value closest to 20.0 percent of the high full-
scale range value (from paragraph (b) of this section). The low 
range must be greater than or equal to the low span value, and the 
required calibration gases must be selected based on the low span 
value. For units with two SO<INF>2</INF> spans, use the low range 
whenever the SO<INF>2</INF> concentrations are expected to be 
consistently below 20.0 percent of the high full-scale range value, 
i.e., when the MEC of the fuel or blend being combusted is less than 
20.0 percent of the high full-scale range value. When the full-scale 
of the low range is exceeded, the high range shall be used to 
measure and record the SO<INF>2</INF> concentrations; or, if 
applicable, the default high range value in paragraph (f) of this 
section shall be reported for each hour of the full-scale 
exceedance.

2.1.1.5  Adjustment of Span and Range

    For each affected unit or common stack, the owner or operator 
shall make a periodic evaluation of the MPC, MEC, span, and range 
values for each SO<INF>2</INF> monitor (at a minimum, an annual 
evaluation is required) and shall make any necessary span and range 
adjustments, with corresponding monitoring plan updates, as 
described in paragraphs (a) and (b) of this section. Span and range

[[Page 28633]]

adjustments may be required, for example, as a result of changes in 
the fuel supply, changes in the manner of operation of the unit, or 
installation or removal of emission controls. In implementing the 
provisions in paragraphs (a) and (b) of this section, SO<INF>2</INF> 
data recorded during short-term, non-representative process 
operating conditions (e.g., a trial burn of a different type of 
fuel) shall be excluded from consideration. The owner or operator 
shall keep the results of the most recent span and range evaluation 
on-site, in a format suitable for inspection. Make each required 
span or range adjustment no later than 45 days after the end of the 
quarter in which the need to adjust the span or range is identified, 
except that up to 90 days after the end of that quarter may be taken 
to implement a span adjustment if the calibration gases currently 
being used for daily calibration error tests and linearity checks 
are unsuitable for use with the new span value.
    (a) If the fuel supply, the composition of the fuel blend(s), 
the emission controls, or the manner of operation change such that 
the maximum expected or potential concentration changes 
significantly, adjust the span and range setting to assure the 
continued accuracy of the monitoring system. A ``significant'' 
change in the MPC or MEC means that the guidelines in section 2.1 of 
this appendix can no longer be met, as determined by either a 
periodic evaluation by the owner or operator or from the results of 
an audit by the Administrator. The owner or operator should evaluate 
whether any planned changes in operation of the unit may affect the 
concentration of emissions being emitted from the unit or stack and 
should plan any necessary span and range changes needed to account 
for these changes, so that they are made in as timely a manner as 
practicable to coordinate with the operational changes. Determine 
the adjusted span(s) using the procedures in sections 2.1.1.3 and 
2.1.1.4 of this appendix (as applicable). Select the full-scale 
range(s) of the instrument to be greater than or equal to the new 
span value(s) and to be consistent with the guidelines of section 
2.1 of this appendix.
    (b) Whenever a full-scale range is exceeded during a quarter and 
the exceedance is not caused by a monitor out-of-control period, 
proceed as follows:
    (1) For exceedances of the high range, report 200.0 percent of 
the current full-scale range as the hourly SO<INF>2</INF> 
concentration for each hour of the full-scale exceedance and make 
appropriate adjustments to the MPC, span, and range to prevent 
future full-scale exceedances.
    (2) For units with two SO<INF>2</INF> spans and ranges, if the 
low range is exceeded, no further action is required, provided that 
the high range is available and is not out-of-control or out-of-
service for any reason. However, if the high range is not able to 
provide quality assured data at the time of the low range exceedance 
or at any time during the continuation of the exceedance, report the 
MPC as the SO<INF>2</INF> concentration until the readings return to 
the low range or until the high range is able to provide quality 
assured data (unless the reason that the high-scale range is not 
able to provide quality assured data is because the high-scale range 
has been exceeded; if the high-scale range is exceeded follow the 
procedures in paragraph (b)(1) of this section).
    (c) Whenever changes are made to the MPC, MEC, full-scale range, 
or span value of the SO<INF>2</INF> monitor, as described in 
paragraphs (a) or (b) of this section, record and report (as 
applicable) the new full-scale range setting, the new MPC or MEC and 
calculations of the adjusted span value in an updated monitoring 
plan. The monitoring plan update shall be made in the quarter in 
which the changes become effective. In addition, record and report 
the adjusted span as part of the records for the daily calibration 
error test and linearity check specified by appendix B to this part. 
Whenever the span value is adjusted, use calibration gas 
concentrations that meet the requirements of section 5.1 of this 
appendix, based on the adjusted span value. When a span adjustment 
is so significant that the calibration gases currently being used 
for daily calibration error tests and linearity checks are 
unsuitable for use with the new span value, then a diagnostic 
linearity test using the new calibration gases must be performed and 
passed. Data from the monitor are considered invalid from the hour 
in which the span is adjusted until the required linearity check is 
passed in accordance with section 6.2 of this appendix.

2.1.2  NO_X Pollutant Concentration Monitors

    Determine, as indicated in section 2.1.2.1, the span and range 
value(s) for the NO_X pollutant concentration monitor so 
that all expected NO_X concentrations can be determined 
and recorded accurately.

2.1.2.1  Maximum Potential Concentration

    (a) The maximum potential concentration (MPC) of NO_X 
for each affected unit shall be based upon whichever fuel or blend 
combusted in the unit produces the highest level of NO_X 
emissions. Make an initial determination of the MPC using the 
appropriate option as follows:
    Option 1: Use 800 ppm for coal-fired and 400 ppm for oil- or 
gas-fired units as the maximum potential concentration of 
NO_X (if an MPC of 1600 ppm for coal-fired units or 480 
ppm for oil- or gas-fired units was previously selected under this 
part, that value may still be used, provided that the guidelines of 
section 2.1 of this appendix are met);
    Option 2: Use the specific values based on boiler type and fuel 
combusted, listed in Table 2-1 or Table 2-2;
    Option 3: Use NO_X emission test results; or
    Option 4: Use historical CEM data over the previous 720 (or 
more) unit operating hours when combusting the fuel or blend with 
the highest NO_X emission rate.
    (b) For the purpose of providing substitute data during 
NO_X missing data periods in accordance with Secs. 75.31 
and 75.33 and as required elsewhere under this part, the owner or 
operator shall also calculate the maximum potential NO_X 
emission rate (MER), in lb/mmBtu, by substituting the MPC for 
NO_X in conjunction with the minimum expected 
CO<INF>2</INF> or maximum O<INF>2</INF> concentration (under all 
unit operating conditions except for unit startup, shutdown, and 
upsets) and the appropriate F-factor into the applicable equation in 
appendix F to this part. The diluent cap value of 5.0 percent 
CO<INF>2</INF> (or 14.0 percent O<INF>2</INF>) for boilers or 1.0 
percent CO<INF>2</INF> (or 19.0 percent O<INF>2</INF>) for 
combustion turbines may be used in the NO_X MER 
calculation.
    (c) Report the method of determining the initial MPC and the 
calculation of the maximum potential NO_X emission rate in 
the monitoring plan for the unit.
    (d) For units with add-on NO_X controls (whether or 
not the unit is equipped with low-NO_X burner technology), 
NO_X emission testing may only be used to determine the 
MPC if testing can be performed either upstream of the add-on 
controls or during a time or season when the add-on controls are not 
in operation. If NO_X emission testing is performed, use 
the following guidelines. Use Method 7E from appendix A to part 60 
of this chapter to measure total NO_X concentration. 
(Note: Method 20 from appendix A to part 60 may be used for gas 
turbines, instead of Method 7E.) Operate the unit, or group of units 
sharing a common stack, at the minimum safe and stable load, the 
normal load, and the maximum load. If the normal load and maximum 
load are identical, an intermediate level need not be tested. 
Operate at the highest excess O<INF>2</INF> level expected under 
normal operating conditions. Make at least three runs of 20 minutes 
(minimum) duration with three traverse points per run at each 
operating condition. Select the highest point NO_X 
concentration from all test runs as the MPC for NO_X.
    (e) If historical CEM data are used to determine the MPC, the 
data must, for uncontrolled units or units equipped with low-
NO_X burner technology and no other NO_X 
controls, represent a minimum of 720 quality assured monitor 
operating hours, obtained under various operating conditions 
including the minimum safe and stable load, normal load (including 
periods of high excess air at normal load), and maximum load. For a 
unit with add-on NO_X controls (whether or not the unit is 
equipped with low-NO_X burner technology), historical CEM 
data may only be used to determine the MPC if the 720 quality 
assured monitor operating hours of CEM data are collected upstream 
of the add-on controls or if the 720 hours of data include periods 
when the add-on controls are not in operation. The highest hourly 
NO_X concentration in ppm shall be the MPC.

[[Page 28634]]



  Table 2-1.--Maximum Potential Concentration for NO_X--Coal-Fired Units
------------------------------------------------------------------------
                                                              Maximum
                                                             potential
                        Unit type                          concentration
                                                           for NO_X (ppm)
------------------------------------------------------------------------
Tangentially-fired dry bottom and fluidized bed.........             460
Wall-fired dry bottom, turbo-fired dry bottom, stokers..             675
Roof-fired (vertically-fired) dry bottom, cell burners,              975
 arch-fired.............................................
Cyclone, wall-fired wet bottom, wet bottom turbo-fired..            1200
Others..................................................           (\1\)
------------------------------------------------------------------------
\1\ As approved by the Administrator.


 Table 2-2.--Maximum Potential Concentration for NO_X--Gas-and Oil-Fired
                                  Units
------------------------------------------------------------------------
                                                              Maximum
                                                             potential
                        Unit type                          concentration
                                                           for NO_X (ppm)
------------------------------------------------------------------------
Tangentially-fired dry bottom...........................             380
Wall-fired dry bottom...................................             600
Roof-fired (vertically-fired) dry bottom, arch-fired....             550
Existing combustion turbine or combined cycle turbine...             200
New stationary gas turbine/combustion turbine...........              50
Others..................................................           (\1\)
------------------------------------------------------------------------
\1\ As approved by the Administrator

2.1.2.2  Maximum Expected Concentration

    (a) Make an initial determination of the maximum expected 
concentration (MEC) of NO_X during normal operation for 
affected units with add-on NO_X controls of any kind 
(e.g., steam injection, water injection, SCR, or SNCR). Determine a 
separate MEC value for each type of fuel (or blend) combusted in the 
unit, except for fuels that are only used for unit startup and/or 
flame stabilization. Calculate the MEC of NO_X using 
Equation A-2, if applicable, inserting the maximum potential 
concentration, as determined using the procedures in section 2.1.2.1 
of this appendix. Where Equation A-2 is not applicable, set the MEC 
either by: (1) measuring the NO_X concentration using the 
testing procedures in this section; or (2) using historical CEM data 
over the previous 720 (or more) quality assured monitor operating 
hours. Include in the monitoring plan for the unit each MEC value 
and the method by which the MEC was determined.
    (b) If NO_X emission testing is used to determine the 
MEC value(s), the MEC for each type of fuel (or blend) shall be 
based upon testing at minimum load, normal load, and maximum load. 
At least three tests of 20 minutes (minimum) duration, using at 
least three traverse points, shall be performed at each load, using 
Method 7E from appendix A to part 60 of this chapter (Note: Method 
20 from appendix A to part 60 may be used for gas turbines instead 
of Method 7E). The test must be performed at a time when all 
NO_X control devices and methods used to reduce 
NO_X emissions are operating properly. The testing shall 
be conducted downstream of all NO_X controls. The highest 
point NO_X concentration (e.g., the highest one-minute 
average) recorded during any of the test runs shall be the MEC.
    (c)If historical CEM data are used to determine the MEC 
value(s), the MEC for each type of fuel shall be based upon 720 (or 
more) hours of quality assured data representing the entire load 
range under stable operating conditions. The data base for the MEC 
shall not include any CEM data recorded during unit startup, 
shutdown, or malfunction or during any NO_X control device 
malfunctions or outages. All NO_X control devices and 
methods used to reduce NO_X emissions must be operating 
properly during each hour. The CEM data shall be collected 
downstream of all NO_X controls. For each type of fuel, 
the highest of the 720 (or more) quality assured hourly average 
NO_X concentrations recorded by the CEMS shall be the MEC.

2.1.2.3  Span Value(s) and Range(s)

    (a) Determine the high span value of the NO_X monitor 
as follows. The high span value shall be obtained by multiplying the 
MPC by a factor no less than 1.00 and no greater than 1.25. Round 
the span value upward to the next highest multiple of 100 ppm. If 
the NO_X span concentration is <ls-thn-eq> 500 ppm, the 
span value may be rounded upward to the next highest multiple of 10 
ppm, rather than 100 ppm. The high span value shall be used to 
determine the concentrations of the calibration gases required for 
daily calibration error checks and linearity tests. Note that for 
certain applications, a second (low) NO_X span and range 
may be required (see section 2.1.2.4 of this appendix).
    (b) If an existing State, local, or federal requirement for span 
of a NO_X pollutant concentration monitor requires a span 
lower than that required by this section or by section 2.1.2.4 of 
this appendix, the State, local, or federal span value may be used, 
where a satisfactory explanation is included in the monitoring plan, 
unless span and/or range adjustments become necessary in accordance 
with section 2.1.2.5 of this appendix. Span values higher than 
required by this section or by section 2.1.2.4 of this appendix must 
be approved by the Administrator.
    (c) Select the full-scale range of the instrument to be 
consistent with section 2.1 of this appendix and to be greater than 
or equal to the high span value. Include the full-scale range 
setting and calculations of the MPC and span in the monitoring plan 
for the unit.

2.1.2.4  Dual Span and Range Requirements

    For most units, the high span value based on the MPC, as 
determined under section 2.1.2.3 of this appendix will suffice to 
measure and record NO_X concentrations (unless span and/or 
range adjustments must be made in accordance with section 2.1.2.5 of 
this appendix). In some instances, however, a second (low) span 
value based on the MEC may be required to ensure accurate 
measurement of all expected and potential NO_X 
concentrations. To determine whether two NO_X spans are 
required, proceed as follows:
    (a) Compare the MEC value(s) determined in section 2.1.2.2 of 
this appendix to the high full-scale range value determined in 
section 2.1.2.3 of this appendix. If the MEC values for all fuels 
(or blends) are <gr-thn-eq>20.0 percent of the high range value, the 
high span and range values determined under section 2.1.2.3 of this 
appendix are sufficient, irrespective of which fuel or blend is 
combusted in the unit. If any of the MEC values is <20.0 percent of 
the high range value, two spans (low and high) are required, one 
based on the MPC and the other based on the MEC.
    (b) When two NO_X spans are required, the owner or 
operator may either use a single NO_X analyzer with a dual 
range (low-and high-scales) or two separate NO_X analyzers 
connected to a common sample probe and sample interface. For units 
with add-on NO_X emission controls (i.e., steam injection, 
water injection, SCR, or SNCR), the owner or operator may use a low 
range analyzer and

[[Page 28635]]

a ``default high range value,'' as described in paragraph 2.1.2.4(e) 
of this section, in lieu of maintaining and quality assuring a high-
scale range. Other monitor configurations are subject to the 
approval of the Administrator.
    (c) The owner or operator shall designate the monitoring systems 
and components in the monitoring plan under Sec. 75.53 as follows: 
designate the low and high ranges as separate NO_X 
components of a single, primary NO_X monitoring system; or 
designate the low and high ranges as the NO_X components 
of two separate, primary NO_X monitoring systems; or 
designate the normal range as a primary monitoring system and the 
other range as a non-redundant backup monitoring system; or, when a 
single, dual-range NO_X analyzer is used, designate the 
low and high ranges as a single NO_X component of a 
primary NO_X monitoring system (if this option is 
selected, use a special dual-range component type code, as specified 
by the Administrator, to satisfy the requirements of 
Sec. 75.53(e)(1)(iv)(D)); or, for units with add-on NO_X 
controls, if the default high range value is used, designate the low 
range analyzer as the NO_X component of the primary 
NO_X monitoring system. Do not designate the default high 
range as a monitoring system or component. Other component and 
system designations are subject to approval by the Administrator. 
Note that the component and system designations for redundant backup 
monitoring systems shall be the same as for primary monitoring 
systems.
    (d) Each monitoring system designated as primary or redundant 
backup shall meet the initial certification and quality assurance 
requirements in Sec. 75.20(c) (for primary monitoring systems), in 
Sec. 75.20(d)(1) (for redundant backup monitoring systems) and 
appendices A and B to this part, with one exception: relative 
accuracy test audits (RATAs) are required only on the normal range 
(for dual span units with add-on NO_X emission controls, 
the low range is considered normal). Each monitoring system 
designated as non-redundant backup shall meet the applicable quality 
assurance requirements in Sec. 75.20(d)(2).
    (e) For dual span units with add-on NO_X emission 
controls (e.g., steam injection, water injection, SCR, or SNCR), the 
owner or operator may, as an alternative to maintaining and quality 
assuring a high monitor range, use a default high range value. If 
this option is chosen, the owner or operator shall report a default 
value of 200.0 percent of the MPC for each unit operating hour in 
which the full-scale of the low range NO_X analyzer is 
exceeded.
    (f) The high span and range shall be determined in accordance 
with section 2.1.2.3 of this appendix. The low span value shall be 
100.0 to 125.0 percent of the MEC, rounded up to the next highest 
multiple of 10 ppm (or 100 ppm, if appropriate). If more than one 
MEC value (as determined in section 2.1.2.2 of this appendix) is 
<20.0 percent of the high full-scale range value, the low span value 
shall be based upon whichever MEC value is closest to 20.0 percent 
of the high range value. The low range must be greater than or equal 
to the low span value, and the required calibration gases for the 
low range must be selected based on the low span value. For units 
with two NO_X spans, use the low range whenever 
NO_X concentrations are expected to be consistently <20.0 
percent of the high range value, i.e., when the MEC of the fuel 
being combusted is <20.0 percent of the high range value. When the 
full-scale of the low range is exceeded, the high range shall be 
used to measure and record the NO_X concentrations; or, if 
applicable, the default high range value in paragraph (e) of this 
section shall be reported for each hour of the full-scale 
exceedance.

2.1.2.5  Adjustment of Span and Range

    For each affected unit or common stack, the owner or operator 
shall make a periodic evaluation of the MPC, MEC, span, and range 
values for each NO_X monitor (at a minimum, an annual 
evaluation is required) and shall make any necessary span and range 
adjustments, with corresponding monitoring plan updates, as 
described in paragraphs (a) and (b) of this section. Span and range 
adjustments may be required, for example, as a result of changes in 
the fuel supply, changes in the manner of operation of the unit, or 
installation or removal of emission controls. In implementing the 
provisions in paragraphs (a) and (b) of this section, note that 
NO_X data recorded during short-term, non-representative 
operating conditions (e.g., a trial burn of a different type of 
fuel) shall be excluded from consideration. The owner or operator 
shall keep the results of the most recent span and range evaluation 
on-site, in a format suitable for inspection. Make each required 
span or range adjustment no later than 45 days after the end of the 
quarter in which the need to adjust the span or range is identified, 
except that up to 90 days after the end of that quarter may be taken 
to implement a span adjustment if the calibration gases currently 
being used for daily calibration error tests and linearity checks 
are unsuitable for use with the new span value.
    (a) If the fuel supply, emission controls, or other process 
parameters change such that the maximum expected concentration or 
the maximum potential concentration changes significantly, adjust 
the NO_X pollutant concentration span(s) and (if 
necessary) monitor range(s) to assure the continued accuracy of the 
monitoring system. A ``significant'' change in the MPC or MEC means 
that the guidelines in section 2.1 of this appendix can no longer be 
met, as determined by either a periodic evaluation by the owner or 
operator or from the results of an audit by the Administrator. The 
owner or operator should evaluate whether any planned changes in 
operation of the unit or stack may affect the concentration of 
emissions being emitted from the unit and should plan any necessary 
span and range changes needed to account for these changes, so that 
they are made in as timely a manner as practicable to coordinate 
with the operational changes. An example of a change that may 
require a span and range adjustment is the installation of low-
NO_X burner technology on a previously uncontrolled unit. 
Determine the adjusted span(s) using the procedures in section 
2.1.2.3 or 2.1.2.4 of this appendix (as applicable). Select the 
full-scale range(s) of the instrument to be greater than or equal to 
the adjusted span value(s) and to be consistent with the guidelines 
of section 2.1 of this appendix.
    (b) Whenever a full-scale range is exceeded during a quarter and 
the exceedance is not caused by a monitor out-of-control period, 
proceed as follows:
    (1) For exceedances of the high range, report 200.0 percent of 
the current full-scale range as the hourly NO_X 
concentration for each hour of the full-scale exceedance and make 
appropriate adjustments to the MPC, span, and range to prevent 
future full-scale exceedances.
    (2) For units with two NO_X spans and ranges, if the 
low range is exceeded, no further action is required, provided that 
the high range is available and is not out-of-control or out-of-
service for any reason. However, if the high range is not able to 
provide quality assured data at the time of the low range exceedance 
or at any time during the continuation of the exceedance, report the 
MPC as the NO_X concentration until the readings return to 
the low range or until the high range is able to provide quality 
assured data (unless the reason that the high-scale range is not 
able to provide quality assured data is because the high-scale range 
has been exceeded; if the high-scale range is exceeded, follow the 
procedures in paragraph (b)(1) of this section).
    (c) Whenever changes are made to the MPC, MEC, full-scale range, 
or span value of the NO_X monitor as described in 
paragraphs (a) and (b) of this section, record and report (as 
applicable) the new full-scale range setting, the new MPC or MEC, 
maximum potential NO_X emission rate, and the adjusted 
span value in an updated monitoring plan for the unit. The 
monitoring plan update shall be made in the quarter in which the 
changes become effective. In addition, record and report the 
adjusted span as part of the records for the daily calibration error 
test and linearity check required by appendix B to this part. 
Whenever the span value is adjusted, use calibration gas 
concentrations that meet the requirements of section 5.1 of this 
appendix, based on the adjusted span value. When a span adjustment 
is significant enough that the calibration gases currently being 
used for daily calibration error tests and linearity checks are 
unsuitable for use with the new span value, a linearity test using 
the new calibration gases must be performed and passed. Data from 
the monitor are considered invalid from the hour in which the span 
is adjusted until the required linearity check is passed in 
accordance with section 6.2 of this appendix.

2.1.3  CO<INF>2</INF> and O<INF>2</INF> Monitors

    For an O<INF>2</INF> monitor (including O<INF>2</INF> monitors 
used to measure CO<INF>2</INF> emissions or percentage moisture), 
select a span value between 15.0 and 25.0 percent O<INF>2</INF>. For 
a CO<INF>2</INF> monitor installed on a boiler, select a span value 
between 14.0 and 20.0 percent CO<INF>2</INF>. For a CO<INF>2</INF> 
monitor installed on a combustion turbine, an alternative span value 
between 6.0 and 14.0 percent CO<INF>2</INF> may be used. An 
alternative O<INF>2</INF> span value below 15.0 percent 
O<INF>2</INF> may be used if an appropriate technical justification 
is included in the monitoring plan (e.g., O<INF>2</INF> 
concentrations above a certain level create an unsafe operating 
condition).

[[Page 28636]]

Select the full-scale range of the instrument to be consistent with 
section 2.1 of this appendix and to be greater than or equal to the 
span value. Select the calibration gas concentrations for the daily 
calibration error tests and linearity checks in accordance with 
section 5.1 of this appendix, as percentages of the span value. For 
O<INF>2</INF> monitors with span values <gr-thn-eq>21.0 percent 
O<INF>2</INF>, purified instrument air containing 20.9 percent 
O<INF>2</INF> may be used as the high-level calibration material.

2.1.3.1  Maximum Potential Concentration of CO<INF>2</INF>

    For CO<INF>2</INF> pollutant concentration monitors, the maximum 
potential concentration shall be 14.0 percent CO<INF>2</INF> for 
boilers and 6.0 percent CO<INF>2</INF> for combustion turbines. 
Alternatively, the owner or operator may determine the MPC based on 
a minimum of 720 hours of quality assured historical CEM data 
representing the full operating load range of the unit(s). Note that 
the MPC for CO<INF>2</INF> monitors shall only be used for the 
purpose of providing substitute data under this part. The 
CO<INF>2</INF> monitor span and range shall be determined according 
to section 2.1.3 of this appendix.

2.1.3.2  Minimum Potential Concentration of O<INF>2</INF>

    The owner or operator of a unit that uses a flow monitor and an 
O<INF>2</INF> diluent monitor to determine heat input in accordance 
with Equation F-17 or F-18 in appendix F to this part shall, for the 
purposes of providing substitute data under Sec. 75.36, determine 
the minimum potential O<INF>2</INF> concentration. The minimum 
potential O<INF>2</INF> concentration shall be based upon 720 hours 
or more of quality-assured CEM data, representing the full operating 
load range of the unit(s). The minimum potential O<INF>2</INF> 
concentration shall be the lowest quality-assured hourly average 
O<INF>2</INF> concentration recorded in the 720 (or more) hours of 
data used for the determination.

2.1.3.3  Adjustment of Span and Range

    Adjust the span value and range of a CO<INF>2</INF> or 
O<INF>2</INF> monitor in accordance with section 2.1.1.5 of this 
appendix (insofar as those provisions are applicable), with the term 
``CO<INF>2</INF> or O<INF>2</INF>'' applying instead of the term 
``SO<INF>2</INF>''. Set the new span and range in accordance with 
section 2.1.3 of this appendix and report the new span value in the 
monitoring plan.

2.1.4  Flow Monitors

    Select the full-scale range of the flow monitor so that it is 
consistent with section 2.1 of this appendix and can accurately 
measure all potential volumetric flow rates at the flow monitor 
installation site.

2.1.4.1  Maximum Potential Velocity and Flow Rate

    For this purpose, determine the span value of the flow monitor 
using the following procedure. Calculate the maximum potential 
velocity (MPV) using Equation A-3a or A-3b or determine the MPV (wet 
basis) from velocity traverse testing using Reference Method 2 (or 
its allowable alternatives) in appendix A to part 60 of this 
chapter. If using test values, use the highest average velocity 
(determined from the Method 2 traverses) measured at or near the 
maximum unit operating load. Express the MPV in units of wet 
standard feet per minute (fpm). For the purpose of providing 
substitute data during periods of missing flow rate data in 
accordance with Secs. 75.31 and 75.33 and as required elsewhere in 
this part, calculate the maximum potential stack gas flow rate (MPF) 
in units of standard cubic feet per hour (scfh), as the product of 
the MPV (in units of wet, standard fpm) times 60, times the cross-
sectional area of the stack or duct (in ft²) at the flow 
monitor location.
[GRAPHIC] [TIFF OMITTED] TR26MY99.003

    or
[GRAPHIC] [TIFF OMITTED] TR26MY99.004

Where:

MPV = maximum potential velocity (fpm, standard wet basis).
F<INF>d</INF> = dry-basis F factor (dscf/mmBtu) from Table 1, 
Appendix F to this part.
F<INF>c</INF> = carbon-based F factor (scf CO<INF>2</INF>/mmBtu) 
from Table 1, Appendix F to this part.
Hf = maximum heat input (mmBtu/minute) for all units, combined, 
exhausting to the stack or duct where the flow monitor is located.
A = inside cross sectional area (ft²) of the flue at the 
flow monitor location.
%O<INF>2d</INF> = maximum oxygen concentration, percent dry basis, 
under normal operating conditions.
%CO<INF>2d</INF> = minimum carbon dioxide concentration, percent dry 
basis, under normal operating conditions.
%H<INF>2</INF>O = maximum percent flue gas moisture content under 
normal operating conditions.

2.1.4.2  Span Values and Range

    Determine the span and range of the flow monitor as follows. 
Convert the MPV, as determined in section 2.1.4.1 of this appendix, 
to the same measurement units of flow rate that are used for daily 
calibration error tests (e.g., scfh, kscfh, kacfm, or differential 
pressure (inches of water)). Next, determine the ``calibration span 
value'' by multiplying the MPV (converted to equivalent daily 
calibration error units) by a factor no less than 1.00 and no 
greater than 1.25, and rounding up the result to at least two 
significant figures. For calibration span values in inches of water, 
retain at least two decimal places. Select appropriate reference 
signals for the daily calibration error tests as percentages of the 
calibration span value. Finally, calculate the ``flow rate span 
value'' (in scfh) as the product of the MPF, as determined in 
section 2.1.4.1 of this appendix, times the same factor (between 
1.00 and 1.25) that was used to calculate the calibration span 
value. Round off the flow rate span value to the nearest 1000 scfh. 
Select the full-scale range of the flow monitor so that it is 
greater than or equal to the span value and is consistent with 
section 2.1 of this appendix. Include in the monitoring plan for the 
unit: calculations of the MPV, MPF, calibration span value, flow 
rate span value, and full-scale range (expressed both in scfh and, 
if different, in the measurement units of calibration).

2.1.4.3  Adjustment of Span and Range

    For each affected unit or common stack, the owner or operator 
shall make a periodic evaluation of the MPV, MPF, span, and range 
values for each flow rate monitor (at a minimum, an annual 
evaluation is required) and shall make any necessary span and range 
adjustments with corresponding monitoring plan updates, as described 
in paragraphs (a) through (c) of this section 2.1.4.3. Span and 
range adjustments may be required, for example, as a result of 
changes in the fuel supply, changes in the stack or ductwork 
configuration, changes in the manner of operation of the unit, or 
installation or removal of emission controls. In implementing the 
provisions in paragraphs (a) and (b) of this section 2.1.4.3, note 
that flow rate data recorded during short-term, non-representative 
operating conditions (e.g., a trial burn of a different type of 
fuel) shall be excluded from consideration. The owner or operator 
shall keep the results of the most recent span and range evaluation 
on-site, in a format suitable for inspection. Make each required 
span or range adjustment no later than 45 days after the end of the 
quarter in which the need to adjust the span or range is identified.
    (a) If the fuel supply, stack or ductwork configuration, 
operating parameters, or other conditions change such that the 
maximum potential flow rate changes significantly, adjust the span 
and range to assure the continued accuracy of the flow monitor. A 
``significant'' change in the MPV or MPF means that the guidelines 
of section 2.1 of this appendix can no longer be met, as

[[Page 28637]]

determined by either a periodic evaluation by the owner or operator 
or from the results of an audit by the Administrator. The owner or 
operator should evaluate whether any planned changes in operation of 
the unit may affect the flow of the unit or stack and should plan 
any necessary span and range changes needed to account for these 
changes, so that they are made in as timely a manner as practicable 
to coordinate with the operational changes. Calculate the adjusted 
calibration span and flow rate span values using the procedures in 
section 2.1.4.2 of this appendix.
    (b) Whenever the full-scale range is exceeded during a quarter, 
provided that the exceedance is not caused by a monitor out-of-
control period, report 200.0 percent of the current full-scale range 
as the hourly flow rate for each hour of the full-scale exceedance. 
If the range is exceeded, make appropriate adjustments to the MPF, 
flow rate span, and range to prevent future full-scale exceedances. 
Calculate the new calibration span value by converting the new flow 
rate span value from units of scfh to units of daily calibration. A 
calibration error test must be performed and passed to validate data 
on the new range.
    (c) Whenever changes are made to the MPV, MPF, full-scale range, 
or span value of the flow monitor, as described in paragraphs (a) 
and (b) of this section, record and report (as applicable) the new 
full-scale range setting, calculations of the flow rate span value, 
calibration span value, MPV, and MPF in an updated monitoring plan 
for the unit. The monitoring plan update shall be made in the 
quarter in which the changes become effective. Record and report the 
adjusted calibration span and reference values as parts of the 
records for the calibration error test required by appendix B to 
this part. Whenever the calibration span value is adjusted, use 
reference values for the calibration error test that meet the 
requirements of section 2.2.2.1 of this appendix, based on the most 
recent adjusted calibration span value. Perform a calibration error 
test according to section 2.1.1 of appendix B to this part whenever 
making a change to the flow monitor span or range, unless the range 
change also triggers a recertification under Sec. 75.20(b).

2.1.5  Minimum Potential Moisture Percentage

    Except as provided in section 2.1.6 of this appendix, the owner 
or operator of a unit that uses a continuous moisture monitoring 
system to correct emission rates and heat inputs from a dry basis to 
a wet basis (or vice-versa) shall, for the purpose of providing 
substitute data under Sec. 75.37, use a default value of 3.0 percent 
H<INF>2</INF>O as the minimum potential moisture percentage. 
Alternatively, the minimum potential moisture percentage may be 
based upon 720 hours or more of quality-assured CEM data, 
representing the full operating load range of the unit(s). If this 
option is chosen, the minimum potential moisture percentage shall be 
the lowest quality-assured hourly average H<INF>2</INF>O 
concentration recorded in the 720 (or more) hours of data used for 
the determination.

2.1.6  Maximum Potential Moisture Percentage

    When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to 
part 60 of this chapter is used to determine NO_X emission 
rate, the owner or operator of a unit that uses a continuous 
moisture monitoring system shall, for the purpose of providing 
substitute data under Sec. 75.37, determine the maximum potential 
moisture percentage. The maximum potential moisture percentage shall 
be based upon 720 hours or more of quality-assured CEM data, 
representing the full operating load range of the unit(s). The 
maximum potential moisture percentage shall be the highest quality-
assured hourly average H<INF>2</INF>O concentration recorded in the 
720 (or more) hours of data used for the determination.
    55. Appendix A to part 75 is amended by revising section 3.1, 
the last sentence in the first paragraph of section 3.2, and section 
3.3.2; by adding section 3.3.6; and by revising sections 3.3.7, 
3.4.1 and 3.5 to read as follows:

3. Performance Specifications

3.1  Calibration Error

    (a) The calibration error performance specifications in this 
section apply only to 7-day calibration error tests under sections 
6.3.1 and 6.3.2 of this appendix and to the offline calibration 
demonstration described in section 2.1.1.2 of appendix B to this 
part. The calibration error limits for daily operation of the 
continuous monitoring systems required under this part are found in 
section 2.1.4(a) of appendix B to this part.
    (b) The calibration error of SO<INF>2</INF> and NO_X 
pollutant concentration monitors shall not deviate from the 
reference value of either the zero or upscale calibration gas by 
more than 2.5 percent of the span of the instrument, as calculated 
using Equation A-5 of this appendix. Alternatively, where the span 
value is less than 200 ppm, calibration error test results are also 
acceptable if the absolute value of the difference between the 
monitor response value and the reference value, |R-A- in Equation A-
5 of this appendix, is 
<ls-thn-eq>5 ppm. The calibration error of CO<INF>2</INF> or 
O<INF>2</INF> monitors (including O<INF>2</INF> monitors used to 
measure CO<INF>2</INF> emissions or percent moisture) shall not 
deviate from the reference value of the zero or upscale calibration 
gas by >0.5 percent O<INF>2</INF> or CO<INF>2</INF>, as calculated 
using the term -R-A| in the numerator of Equation A-5 of this 
appendix. The calibration error of flow monitors shall not exceed 
3.0 percent of the calibration span value of the instrument, as 
calculated using Equation A-6 of this appendix. For differential 
pressure-type flow monitors, the calibration error test results are 
also acceptable if |R-A|, the absolute value of the difference 
between the monitor response and the reference value in Equation A-
6, does not exceed 0.01 inches of water.

3.2  Linearity Check

    * * * For CO<INF>2</INF> or O<INF>2</INF> monitors (including 
O<INF>2</INF> monitors used to measure CO<INF>2</INF> emissions or 
percent moisture):
* * * * *
    3.3 * * *

3.3.2  Relative Accuracy for NO_X-Diluent Continuous Emission 
Monitoring Systems

    (a) The relative accuracy for NO_X-diluent continuous 
emission monitoring systems shall not exceed 10.0 percent.
    (b) For affected units where the average of the monitoring 
system measurements of NO_X emission rate during the 
relative accuracy test audit is less than or equal to 0.200 lb/
mmBtu, the mean value of the continuous emission monitoring system 
measurements shall not exceed <plus-minus>0.020 lb/mmBtu of the 
reference method mean value whenever the relative accuracy 
specification of 10.0 percent is not achieved.
* * * * *

3.3.6  Relative Accuracy for Moisture Monitoring Systems

    The relative accuracy of a moisture monitoring system shall not 
exceed 10.0 percent. The relative accuracy test results are also 
acceptable if the mean difference of the reference method 
measurements (in percent H<INF>2</INF>O) and the corresponding 
moisture monitoring system measurements (in percent H<INF>2</INF>O), 
calculated using Equation A-7 of this appendix, are within 
<plus-minus>1.5 percent H<INF>2</INF>O.

3.3.7  Relative Accuracy for NO_X Concentration Monitoring 
Systems

    (a) The following requirement applies only to NO_X 
concentration monitoring systems (i.e., NO_X pollutant 
concentration monitors) that are used to determine NO_X 
mass emissions, where the owner or operator elects to monitor and 
report NO_X mass emissions using a NO_X 
concentration monitoring system and a flow monitoring system.
    (b) The relative accuracy for NO_X concentration 
monitoring systems shall not exceed 10.0 percent. Alternatively, for 
affected units where the average of the monitoring system 
measurements of NO_X concentration during the relative 
accuracy test audit is less than or equal to 250.0 ppm, the mean 
value of the continuous emission monitoring system measurements 
shall not exceed <plus-minus>15.0 ppm of the reference method mean 
value.
    3.4 * * *

3.4.1  SO<INF>2</INF> Pollutant Concentration Monitors, NO_X 
Concentration Monitoring Systems and NO_X-Diluent Continuous 
Emission Monitoring Systems

    SO<INF>2</INF> pollutant concentration monitors, NO_X-
diluent continuous emission monitoring systems and NO_X 
concentration monitoring systems used to determine NO_X 
mass emissions, as defined in Sec. 75.71(a)(2), shall not be biased 
low as determined by the test procedure in section 7.6 of this 
appendix. The bias specification applies to all SO<INF>2</INF> 
pollutant concentration monitors and to all NO_X 
concentration monitoring systems, including those measuring an 
average SO<INF>2</INF> or NO_X concentration of 250.0 ppm 
or less, and to all NO_X-diluent continuous emission 
monitoring systems, including those measuring an average 
NO_X emission rate of 0.200 lb/mmBtu or less.
* * * * *

[[Page 28638]]

3.5  Cycle Time

    The cycle time for pollutant concentration monitors, oxygen 
monitors used to determine percent moisture, and any other 
continuous emission monitoring system(s) required to perform a cycle 
time test shall not exceed 15 minutes.
    56. Appendix A to part 75 is amended by revising the first 
sentence of the first paragraph of section 4 and paragraph (6) to 
read as follows:

4. Data Acquisition and Handling Systems

    Automated data acquisition and handling systems shall read and 
record the full range of pollutant concentrations and volumetric 
flow from zero through span and provide a continuous, permanent 
record of all measurements and required information as an ASCII flat 
file capable of transmission both by direct computer-to-computer 
electronic transfer via modem and EPA-provided software and by an 
IBM-compatible personal computer diskette.
* * * * *
    (6) Provide a continuous, permanent record of all measurements 
and required information as an ASCII flat file capable of 
transmission both by direct computer-to-computer electronic transfer 
via modem and EPA-provided software and by an IBM-compatible 
personal computer diskette.
    57. Appendix A to part 75 is amended by revising sections 5 
through 5.1.6, adding sections 5.1.7 through 5.1.8, and revising 
sections 5.2 through 5.2.4 to read as follows:

5. Calibration Gas

5.1  Reference Gases

    For the purposes of part 75, calibration gases include the 
following:

5.1.1  Standard Reference Materials (SRM)

    These calibration gases may be obtained from the National 
Institute of Standards and Technology (NIST) at the following 
address: Quince Orchard and Cloppers Road, Gaithersburg, MD 20899-
0001.

5.1.2  SRM-Equivalent Compressed Gas Primary Reference Material (PRM)

    Contact the Gas Metrology Team, Analytical Chemistry Division, 
Chemical Science and Technology Laboratory of NIST, at the address 
in section 5.1.1, for a list of vendors and cylinder gases.

5.1.3  NIST Traceable Reference Materials

    Contact the Gas Metrology Team, Analytical Chemistry Division, 
Chemical Science and Technology Laboratory of NIST, at the address 
in section 5.1.1, for a list of vendors and cylinder gases.

5.1.4  EPA Protocol Gases

    (a) EPA Protocol gases must be vendor-certified to be within 2.0 
percent of the concentration specified on the cylinder label (tag 
value), using the uncertainty calculation procedure in section 2.1.8 
of the ``EPA Traceability Protocol for Assay and Certification of 
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
    (b) A copy of EPA-600/R-97/121 is available from the National 
Technical Information Service, 5285 Port Royal Road, Springfield, 
VA, 703-487-4650 and from the Office of Research and Development, 
(MD-77B), U.S. Environmental Protection Agency, Research Triangle 
Park, NC 27711.

5.1.5  Research Gas Mixtures

    Research gas mixtures must be vendor-certified to be within 2.0 
percent of the concentration specified on the cylinder label (tag 
value), using the uncertainty calculation procedure in section 2.1.8 
of the ``EPA Traceability Protocol for Assay and Certification of 
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121. 
Inquiries about the RGM program should be directed to: National 
Institute of Standards and Technology, Analytical Chemistry 
Division, Chemical Science and Technology Laboratory, B-324 
Chemistry, Gaithersburg, MD 20899.

5.1.6  Zero Air Material

    Zero air material is defined in Sec. 72.2 of this chapter.

5.1.7  NIST/EPA-Approved Certified Reference Materials

    Existing certified reference materials (CRMs) that are still 
within their certification period may be used as calibration gas.

5.1.8  Gas Manufacturer's Intermediate Standards

    Gas manufacturer's intermediate standards is defined in 
Sec. 72.2 of this chapter.

5.2  Concentrations

    Four concentration levels are required as follows.

5.2.1  Zero-level Concentration

    0.0 to 20.0 percent of span, including span for high-scale or 
both low- and high-scale for SO<INF>2</INF>, NO_X, 
CO<INF>2</INF>, and O<INF>2</INF> monitors, as appropriate.

5.2.2  Low-level Concentration

    20.0 to 30.0 percent of span, including span for high-scale or 
both low- and high-scale for SO<INF>2</INF>, NO_X, 
CO<INF>2</INF>, and O<INF>2</INF> monitors, as appropriate.

5.2.3  Mid-level Concentration

    50.0 to 60.0 percent of span, including span for high-scale or 
both low- and high-scale for SO<INF>2</INF>, NO_X, 
CO<INF>2</INF>, and O<INF>2</INF> monitors, as appropriate.

5.2.4  High-level Concentration

    80.0 to 100.0 percent of span, including span for high-scale or 
both low-and high-scale for SO<INF>2</INF>, NO_X, 
CO<INF>2</INF>, and O<INF>2</INF> monitors, as appropriate.
    58. Appendix A to part 75 is amended by revising sections 6.2, 
6.3.1, 6.3.2, 6.4, 6.5, 6.5.1, 6.5.2, 6.5.6, 6.5.7, 6.5.9 and 
6.5.10, and adding sections 6.5.2.1, 6.5.2.2, 6.5.6.1, 6.5.6.2, and 
6.5.6.3 to read as follows:

6. Certification Tests and Procedures

* * * * *

6.2  Linearity Check (General Procedures)

    Check the linearity of each SO<INF>2</INF>, NO_X, 
CO<INF>2</INF>, and O<INF>2</INF> monitor while the unit, or group 
of units for a common stack, is combusting fuel at conditions of 
typical stack temperature and pressure; it is not necessary for the 
unit to be generating electricity during this test. Notwithstanding 
these requirements, if the SO<INF>2</INF> or NO_X span 
value for a particular monitor range is <ls-thn-eq>30 ppm, that 
range is exempted from the linearity test requirements of this part. 
For units using emission controls and other units using both a high 
and a low span, perform a linearity check on both the low- and high-
scales for initial certification. For on-going quality assurance of 
the CEMS, perform linearity checks, using the procedures in this 
section, on the range(s) and at the frequency specified in section 
2.2.1 of appendix B to this part. Challenge each monitor with 
calibration gas, as defined in section 5.1 of this appendix, at the 
low-, mid-, and high-range concentrations specified in section 5.2 
of this appendix. Introduce the calibration gas at the gas injection 
port, as specified in section 2.2.1 of this appendix. Operate each 
monitor at its normal operating temperature and conditions. For 
extractive and dilution type monitors, pass the calibration gas 
through all filters, scrubbers, conditioners, and other monitor 
components used during normal sampling and through as much of the 
sampling probe as is practical. For in-situ type monitors, perform 
calibration checking all active electronic and optical components, 
including the transmitter, receiver, and analyzer. Challenge the 
monitor three times with each reference gas (see example data sheet 
in Figure 1). Do not use the same gas twice in succession. To the 
extent practicable, the duration of each linearity test, from the 
hour of the first injection to the hour of the last injection, shall 
not exceed 24 unit operating hours. Record the monitor response from 
the data acquisition and handling system. For each concentration, 
use the average of the responses to determine the error in linearity 
using Equation A-4 in this appendix. Linearity checks are acceptable 
for monitor or monitoring system certification, recertification, or 
quality assurance if none of the test results exceed the applicable 
performance specifications in section 3.2 of this appendix. The 
status of emission data from a CEMS prior to and during a linearity 
test period shall be determined as follows:
    (a) For the initial certification of a CEMS, data from the 
monitoring system are considered invalid until all certification 
tests, including the linearity test, have been successfully 
completed, unless the data validation procedures in Sec. 75.20(b)(3) 
are used. When the procedures in Sec. 75.20(b)(3) are followed, the 
words ``initial certification'' apply instead of 
``recertification,'' and complete all of the initial certification 
tests by the applicable deadline in Sec. 75.4, rather than within 
the time periods specified in Sec. 75.20(b)(3)(iv) for the 
individual tests.
    (b) For the routine quality assurance linearity checks required 
by section 2.2.1 of appendix B to this part, use the data validation 
procedures in section 2.2.3 of appendix B to this part.
    (c) When a linearity test is required as a diagnostic test or 
for recertification, use the data validation procedures in 
Sec. 75.20(b)(3).
    (d) For linearity tests of non-redundant backup monitoring 
systems, use the data validation procedures in 
Sec. 75.20(d)(2)(iii).
    (e) For linearity tests performed during a grace period and 
after the expiration of a grace period, use the data validation 
procedures in sections 2.2.3 and 2.2.4, respectively, of appendix B 
to this part.

[[Page 28639]]

    (f) For all other linearity checks, use the data validation 
procedures in section 2.2.3 of appendix B to this part.

6.3 * * *

6.3.1  Gas Monitor 7-day Calibration Error Test

    Measure the calibration error of each SO<INF>2</INF> monitor, 
each NO_X monitor and each CO<INF>2</INF> or O<INF>2</INF> 
monitor while the unit is combusting fuel (but not necessarily 
generating electricity) once each day for 7 consecutive operating 
days according to the following procedures. (In the event that 
extended unit outages occur after the commencement of the test, the 
7 consecutive unit operating days need not be 7 consecutive calendar 
days.) Units using dual span monitors must perform the calibration 
error test on both high- and low-scales of the pollutant 
concentration monitor. The calibration error test procedures in this 
section and in section 6.3.2 of this appendix shall also be used to 
perform the daily assessments and additional calibration error tests 
required under sections 2.1.1 and 2.1.3 of appendix B to this part. 
Do not make manual or automatic adjustments to the monitor settings 
until after taking measurements at both zero and high concentration 
levels for that day during the 7-day test. If automatic adjustments 
are made following both injections, conduct the calibration error 
test such that the magnitude of the adjustments can be determined 
and recorded. Record and report test results for each day using the 
unadjusted concentration measured in the calibration error test 
prior to making any manual or automatic adjustments (i.e., resetting 
the calibration). The calibration error tests should be 
approximately 24 hours apart, (unless the 7-day test is performed 
over non-consecutive days). Perform calibration error tests at both 
the zero-level concentration and high-level concentration, as 
specified in section 5.2 of this appendix. Alternatively, a mid-
level concentration gas (50.0 to 60.0 percent of the span value) may 
be used in lieu of the high-level gas, provided that the mid-level 
gas is more representative of the actual stack gas concentrations. 
In addition, repeat the procedure for SO<INF>2</INF> and 
NO_X pollutant concentration monitors using the low-scale 
for units equipped with emission controls or other units with dual 
span monitors. Use only calibration gas, as specified in section 5.1 
of this appendix. Introduce the calibration gas at the gas injection 
port, as specified in section 2.2.1 of this appendix. Operate each 
monitor in its normal sampling mode. For extractive and dilution 
type monitors, pass the calibration gas through all filters, 
scrubbers, conditioners, and other monitor components used during 
normal sampling and through as much of the sampling probe as is 
practical. For in-situ type monitors, perform calibration, checking 
all active electronic and optical components, including the 
transmitter, receiver, and analyzer. Challenge the pollutant 
concentration monitors and CO<INF>2</INF> or O<INF>2</INF> monitors 
once with each calibration gas. Record the monitor response from the 
data acquisition and handling system. Using Equation A-5 of this 
appendix, determine the calibration error at each concentration once 
each day (at approximately 24-hour intervals) for 7 consecutive days 
according to the procedures given in this section. The results of a 
7-day calibration error test are acceptable for monitor or 
monitoring system certification, recertification or diagnostic 
testing if none of these daily calibration error test results exceed 
the applicable performance specifications in section 3.1 of this 
appendix.The status of emission data from a gas monitor prior to and 
during a 7-day calibration error test period shall be determined as 
follows:
    (a) For initial certification, data from the monitor are 
considered invalid until all certification tests, including the 7-
day calibration error test, have been successfully completed, unless 
the data validation procedures in Sec. 75.20(b)(3) are used. When 
the procedures in Sec. 75.20(b)(3) are followed, the words ``initial 
certification'' apply instead of ``recertification,'' and complete 
all of the initial certification tests by the applicable deadline in 
Sec. 75.4, rather than within the time periods specified in 
Sec. 75.20(b)(3)(iv) for the individual tests.
    (b) When a 7-day calibration error test is required as a 
diagnostic test or for recertification, use the data validation 
procedures in Sec. 75.20(b)(3).

6.3.2  Flow Monitor 7-day Calibration Error Test

    Perform the 7-day calibration error test of a flow monitor, when 
required for certification, recertification or diagnostic testing, 
according to the following procedures. Introduce the reference 
signal corresponding to the values specified in section 2.2.2.1 of 
this appendix to the probe tip (or equivalent), or to the 
transducer. During the 7-day certification test period, conduct the 
calibration error test while the unit is operating once each unit 
operating day (as close to 24-hour intervals as practicable). In the 
event that extended unit outages occur after the commencement of the 
test, the 7 consecutive operating days need not be 7 consecutive 
calendar days. Record the flow monitor responses by means of the 
data acquisition and handling system. Calculate the calibration 
error using Equation A-6 of this appendix. Do not perform any 
corrective maintenance, repair, or replacement upon the flow monitor 
during the 7-day test period other than that required in the quality 
assurance/quality control plan required by appendix B to this part. 
Do not make adjustments between the zero and high reference level 
measurements on any day during the 7-day test. If the flow monitor 
operates within the calibration error performance specification 
(i.e., less than or equal to 3.0 percent error each day and 
requiring no corrective maintenance, repair, or replacement during 
the 7-day test period), the flow monitor passes the calibration 
error test. Record all maintenance activities and the magnitude of 
any adjustments. Record output readings from the data acquisition 
and handling system before and after all adjustments. Record and 
report all calibration error test results using the unadjusted flow 
rate measured in the calibration error test prior to resetting the 
calibration. Record all adjustments made during the 7-day period at 
the time the adjustment is made, and report them in the 
certification or recertification application. The status of 
emissions data from a flow monitor prior to and during a 7-day 
calibration error test period shall be determined as follows:
    (a) For initial certification, data from the monitor are 
considered invalid until all certification tests, including the 7-
day calibration error test, have been successfully completed, unless 
the data validation procedures in Sec. 75.20(b)(3) are used. When 
the procedures in Sec. 75.20(b)(3) are followed, the words ``initial 
certification'' apply instead of ``recertification,'' and complete 
all of the initial certification tests by the applicable deadline in 
Sec. 75.4, rather than within the time periods specified in 
Sec. 75.20(b)(3)(iv) for the individual tests.
    (b) When a 7-day calibration error test is required as a 
diagnostic test or for recertification, use the data validation 
procedures in Sec. 75.20(b)(3).

6.4  Cycle Time Test

    Perform cycle time tests for each pollutant concentration 
monitor and continuous emission monitoring system while the unit is 
operating, according to the following procedures (see also Figure 6 
at the end of this appendix). Use a zero-level and a high-level 
calibration gas (as defined in section 5.2 of this appendix) 
alternately. To determine the upscale elapsed time, inject a zero-
level concentration calibration gas into the probe tip (or injection 
port leading to the calibration cell, for in situ systems with no 
probe). Record the stable starting gas value and start time, using 
the data acquisition and handling system (DAHS). Next, allow the 
monitor to measure the concentration of flue gas emissions until the 
response stabilizes. Record the stable ending stack emissions value 
and the end time of the test using the DAHS. Determine the upscale 
elapsed time as the time it takes for 95.0 percent of the step 
change to be achieved between the stable starting gas value and the 
stable ending stack emissions value. Then repeat the procedure, 
starting by injecting the high-level gas concentration to determine 
the downscale elapsed time, which is the time it takes for 95.0 
percent of the step change to be achieved between the stable 
starting gas value and the stable ending stack emissions value. End 
the downscale test by measuring the stable concentration of flue gas 
emissions. Record the stable starting and ending monitor values, the 
start and end times, and the downscale elapsed time for the monitor 
using the DAHS. A stable value is equivalent to a reading with a 
change of less than 2.0 percent of the span value for 2 minutes, or 
a reading with a change of less than 6.0 percent from the measured 
average concentration over 6 minutes. (Owners or operators of 
systems which do not record data in 1-minute or 3-minute intervals 
may petition the Administrator under Sec. 75.66 for alternative 
stabilization criteria). For monitors or monitoring systems that 
perform a series of operations (such as purge, sample, and analyze), 
time the injections of the calibration gases so they will produce 
the

[[Page 28640]]

longest possible cycle time. Report the slower of the two elapsed 
times (upscale or downscale) as the cycle time for the analyzer. 
(See Figure 5 at the end of this appendix.) For the NOx-diluent 
continuous emission monitoring system test and SO<INF>2</INF>-
diluent continuous emission monitoring system test, record and 
report the longer cycle time of the two component analyzers as the 
system cycle time. For time-shared systems, this procedure must be 
done at all probe locations that will be polled within the same 15-
minute period during monitoring system operations. To determine the 
cycle time for time-shared systems, add together the longest cycle 
time obtained at each of the probe locations. Report the sum of the 
longest cycle time at each of the probe locations plus the sum of 
the time required for all purge cycles (as determined by the 
continuous emission monitoring system manufacturer) at each of the 
probe locations as the cycle time for each of the time-shared 
systems. For monitors with dual ranges, report the test results from 
on the range giving the longer cycle time. Cycle time test results 
are acceptable for monitor or monitoring system certification, 
recertification or diagnostic testing if none of the cycle times 
exceed 15 minutes. The status of emissions data from a monitor prior 
to and during a cycle time test period shall be determined as 
follows:
    (a) For initial certification, data from the monitor are 
considered invalid until all certification tests, including the 
cycle time test, have been successfully completed, unless the data 
validation procedures in Sec. 75.20(b)(3) are used. When the 
procedures in Sec. 75.20(b)(3) are followed, the words ``initial 
certification'' apply instead of ``recertification,'' and complete 
all of the initial certification tests by the applicable deadline in 
Sec. 75.4, rather than within the time periods specified in 
Sec. 75.20(b)(3)(iv) for the individual tests.
    (b) When a cycle time test is required as a diagnostic test or 
for recertification, use the data validation procedures in 
Sec. 75.20(b)(3).

6.5  Relative Accuracy and Bias Tests (General Procedures)

    Perform the required relative accuracy test audits (RATAs) as 
follows for each CO<INF>2</INF> pollutant concentration monitor 
(including O<INF>2</INF> monitors used to determine CO<INF>2</INF> 
pollutant concentration), each SO<INF>2</INF> pollutant 
concentration monitor, each NO_X concentration monitoring 
system used to determine NO_X mass emissions, each flow 
monitor, each NO_X-diluent continuous emission monitoring 
system, each O<INF>2</INF> or CO<INF>2</INF> diluent monitor used to 
calculate heat input, each moisture monitoring system and each 
SO<INF>2</INF>-diluent continuous emission monitoring system. For 
NO_X concentration monitoring systems used to determine 
NO_X mass emissions, as defined in Sec. 75.71(a)(2), use 
the same general RATA procedures as for SO<INF>2</INF> pollutant 
concentration monitors; however, use the reference methods for 
NO_X concentration specified in section 6.5.10 of this 
appendix:
    (a) Except as provided in Sec. 75.21(a)(5), perform each RATA 
while the unit (or units, if more than one unit exhausts into the 
flue) is combusting the fuel that is normal for that unit (for some 
units, more than one type of fuel may be considered normal, e.g., a 
unit that combusts gas or oil on a seasonal basis). When relative 
accuracy test audits are performed on continuous emission monitoring 
systems or component(s) on bypass stacks/ducts, use the fuel 
normally combusted by the unit (or units, if more than one unit 
exhausts into the flue) when emissions exhaust through the bypass 
stack/ducts.
    (b) Perform each RATA at the load level(s) specified in section 
6.5.1 or 6.5.2 of this appendix or in section 2.3.1.3 of appendix B 
to this part, as applicable.
    (c) For monitoring systems with dual ranges, perform the 
relative accuracy test on the range normally used for measuring 
emissions. For units with add-on SO<INF>2</INF> or NO_X 
controls or for units that need a dual range to record high 
concentration ``spikes'' during startup conditions, the low range is 
considered normal. However, for some dual span units (e.g., for 
units that use fuel switching or for which the emission controls are 
operated seasonally), either of the two measurement ranges may be 
considered normal; in such cases, perform the RATA on the range that 
is in use at the time of the scheduled test.
    (d) Record monitor or monitoring system output from the data 
acquisition and handling system.
    (e) Complete each single-load relative accuracy test audit 
within a period of 168 consecutive unit operating hours, as defined 
in Sec. 72.2 of this chapter (or, for CEMS installed on common 
stacks or bypass stacks, 168 consecutive stack operating hours, as 
defined in Sec. 72.2 of this chapter). For 2-level and 3-level flow 
monitor RATAs, complete all of the RATAs at all levels, to the 
extent practicable, within a period of 168 consecutive unit (or 
stack) operating hours; however, if this is not possible, up to 720 
consecutive unit (or stack) operating hours may be taken to complete 
a multiple-load flow RATA.
    (f) The status of emission data from the CEMS prior to and 
during the RATA test period shall be determined as follows:
    (1) For the initial certification of a CEMS, data from the 
monitoring system are considered invalid until all certification 
tests, including the RATA, have been successfully completed, unless 
the data validation procedures in Sec. 75.20(b)(3) are used. When 
the procedures in Sec. 75.20(b)(3) are followed, the words ``initial 
certification'' apply instead of ``recertification,'' and complete 
all of the initial certification tests by the applicable deadline in 
Sec. 75.4, rather than within the time periods specified in 
Sec. 75.20(b)(3)(iv) for the individual tests.
    (2) For the routine quality assurance RATAs required by section 
2.3.1 of appendix B to this part, use the data validation procedures 
in section 2.3.2 of appendix B to this part.
    (3) For recertification RATAs, use the data validation 
procedures in Sec. 75.20(b)(3).
    (4) For quality assurance RATAs of non-redundant backup 
monitoring systems, use the data validation procedures in 
Secs. 75.20(d)(2)(v) and (vi).
    (5) For RATAs performed during and after the expiration of a 
grace period, use the data validation procedures in sections 2.3.2 
and 2.3.3, respectively, of appendix B to this part.
    (6) For all other RATAs, use the data validation procedures in 
section 2.3.2 of appendix B to this part.
    (g) For each SO<INF>2</INF> or CO<INF>2</INF> pollutant 
concentration monitor, each flow monitor, each CO<INF>2</INF> or 
O<INF>2</INF> diluent monitor used to determine heat input, each 
NO_X concentration monitoring system used to determine 
NO_X mass emissions, as defined in Sec. 75.71(a)(2), each 
moisture monitoring system and each NO_X-diluent 
continuous emission monitoring system, calculate the relative 
accuracy, in accordance with section 7.3 or 7.4 of this appendix, as 
applicable. In addition (except for CO<INF>2,</INF> O<INF>2</INF>, 
SO<INF>2</INF>-diluent or moisture monitors), test for bias and 
determine the appropriate bias adjustment factor, in accordance with 
sections 7.6.4 and 7.6.5 of this appendix, using the data from the 
relative accuracy test audits.

6.5.1  Gas Monitoring System RATAs (Special Considerations)

    (a) Perform the required relative accuracy test audits for each 
SO<INF>2</INF> or CO<INF>2</INF> pollutant concentration monitor, 
each CO<INF>2</INF> or O2 diluent monitor used to determine heat 
input, each NO_X-diluent continuous emission monitoring 
system, each NO_X concentration monitoring system used to 
determine NO_X mass emissions, as defined in 
Sec. 75.71(a)(2), and each SO<INF>2</INF>-diluent continuous 
emission monitoring system, at the normal load level for the unit 
(or combined units, if common stack), as defined in section 6.5.2.1 
of this appendix. If two load levels have been designated as normal, 
the RATAs may be done at either load level.
    (b) For the initial certification of a gas monitoring system and 
for recertifications in which, in addition to a RATA, one or more 
other tests are required (i.e., a linearity test, cycle time test, 
or 7-day calibration error test), EPA recommends that the RATA not 
be commenced until the other required tests of the CEMS have been 
passed.

6.5.2  Flow Monitor RATAs (Special Considerations)

    (a) Except for flow monitors on bypass stacks/ducts and peaking 
units, perform relative accuracy test audits for the initial 
certification of each flow monitor at three different exhaust gas 
velocities (low, mid, and high), corresponding to three different 
load levels within the range of operation, as defined in section 
6.5.2.1 of this appendix. For a common stack/duct, the three 
different exhaust gas velocities may be obtained from frequently 
used unit/load combinations for the units exhausting to the common 
stack. Select the three exhaust gas velocities such that the audit 
points at adjacent load levels (i.e., low and mid or mid and high), 
in megawatts (or in thousands of lb/hr of steam production), are 
separated by no less than 25.0 percent of the range of operation, as 
defined in section 6.5.2.1 of this appendix.
    (b) For flow monitors on bypass stacks/ducts and peaking units, 
the flow monitor relative accuracy test audits for initial 
certification and recertification shall be single-load tests, 
performed at the normal load, as defined in section 6.5.2.1 of this 
appendix.

[[Page 28641]]

    (c) Flow monitor recertification RATAs shall be done at three 
load level(s), unless otherwise specified in paragraph (b) of this 
section or unless otherwise specified or approved by the 
Administrator.
    (d) The semiannual and annual quality assurance flow monitor 
RATAs required under appendix B to this part shall be done at the 
load level(s) specified in section 2.3.1.3 of appendix B to this 
part.

6.5.2.1  Range of Operation and Normal Load Level(s)

    (a) The owner or operator shall determine the upper and lower 
boundaries of the ``range of operation'' for each unit (or 
combination of units, for common stack configurations) that uses 
CEMS to account for its emissions and for each unit that uses the 
optional fuel flow-to-load quality assurance test in section 2.1.7 
of appendix D to this part. The lower boundary of the range of 
operation of a unit shall be the minimum safe, stable load. For 
common stacks, the minimum safe, stable load shall be the lowest of 
the minimum safe, stable loads for any of the units discharging 
through the stack. Alternatively, for a group of frequently-operated 
units that serve a common stack, the sum of the minimum safe, stable 
loads for the individual units may be used as the lower boundary of 
the range of operation. The upper boundary of the range of operation 
of a unit shall be the maximum sustainable load. The ``maximum 
sustainable load'' is the higher of either: the nameplate or rated 
capacity of the unit, less any physical or regulatory limitations or 
other deratings; or the highest sustainable unit load, based on at 
least four quarters of representative historical operating data. For 
common stacks, the maximum sustainable load is the sum of all of the 
maximum sustainable loads of the individual units discharging 
through the stack, unless this load is unattainable in practice, in 
which case use the highest sustainable combined load for the units 
that discharge through the stack, based on at least four quarters of 
representative historical operating data. The load values for the 
unit(s) shall be expressed either in units of megawatts or thousands 
of lb/hr of steam load.
    (b) The operating levels for relative accuracy test audits 
shall, except for peaking units, be defined as follows: the ``low'' 
operating level shall be the first 30.0 percent of the range of 
operation; the ``mid'' operating level shall be the middle portion 
(30.0 to 60.0 percent) of the range of operation; and the ``high'' 
operating level shall be the upper end (60.0 to 100.0 percent) of 
the range of operation. For example, if the upper and lower 
boundaries of the range of operation are 100 and 1100 megawatts, 
respectively, then the low, mid, and high operating levels would be 
100 to 400 megawatts, 400 to 700 megawatts, and 700 to 1100 
megawatts, respectively.
    (c) The owner or operator shall identify, for each affected unit 
or common stack (except for peaking units), the ``normal'' load 
level or levels (low, mid or high), based on the operating history 
of the unit(s). This requirement becomes effective on April 1, 2000; 
however, the owner or operator may choose to comply with this 
requirement prior to April 1, 2000. To identify the normal load 
level(s), the owner or operator shall, at a minimum, determine the 
relative number of operating hours at each of the three load levels, 
low, mid and high over the past four representative operating 
quarters. The owner or operator shall determine, to the nearest 0.1 
percent, the percentage of the time that each load level (low, mid, 
high) has been used during that time period. A summary of the data 
used for this determination and the calculated results shall be kept 
on-site in a format suitable for inspection.
    (d) Based on the analysis of the historical load data the owner 
or operator shall designate the most frequently used load level as 
the normal load level for the unit (or combination of units, for 
common stacks). The owner or operator may also designate the second 
most frequently used load level as an additional normal load level 
for the unit or stack. For peaking units, normal load designations 
are unnecessary; the entire operating load range shall be considered 
normal. If the manner of operation of the unit changes 
significantly, such that the designated normal load(s) or the two 
most frequently used load levels change, the owner or operator shall 
repeat the historical load analysis and shall redesignate the normal 
load(s) and the two most frequently used load levels, as 
appropriate. A minimum of two representative quarters of historical 
load data are required to document that a change in the manner of 
unit operation has occurred.
    (e) Beginning on April 1, 2000, the owner or operator shall 
report the upper and lower boundaries of the range of operation for 
each unit (or combination of units, for common stacks), in units of 
megawatts or thousands of lb/hr of steam production, in the 
electronic quarterly report required under Sec. 75.64. Except for 
peaking units, the owner or operator shall indicate, in the 
electronic quarterly report (as part of the electronic monitoring 
plan) the load level (or levels) designated as normal under this 
section and shall also indicate the two most frequently used load 
levels..

6.5.2.2  Multi-Load Flow RATA Results

    For each multi-load flow RATA, calculate the flow monitor 
relative accuracy at each operating level. If a flow monitor 
relative accuracy test is failed or aborted due to a problem with 
the monitor on any level of a 2-level (or 3-level) relative accuracy 
test audit, the RATA must be repeated at that load level. However, 
the entire 2-level (or 3-level) relative accuracy test audit does 
not have to be repeated unless the flow monitor polynomial 
coefficients or K-factor(s) are changed, in which case a 3-level 
RATA is required.
* * * * *

6.5.6  Reference Method Traverse Point Selection

    Select traverse points that ensure acquisition of representative 
samples of pollutant and diluent concentrations, moisture content, 
temperature, and flue gas flow rate over the flue cross section. To 
achieve this, the reference method traverse points shall meet the 
requirements of section 3.2 of Performance Specification 2 (``PS No. 
2'') in appendix B to part 60 of this chapter (for SO<INF>2</INF>, 
NO_X, and moisture monitoring system RATAs), Performance 
Specification 3 in appendix B to part 60 of this chapter (for 
O<INF>2</INF> and CO<INF>2</INF> monitor RATAs), Method 1 (or 1A) 
(for volumetric flow rate monitor RATAs), Method 3 (for molecular 
weight), and Method 4 (for moisture determination) in appendix A to 
part 60 of this chapter. Unless otherwise specified, use only 
codified versions of PS No. 2 revised as of July 1, 1995, July 1, 
1996 or July 1, 1997. The following alternative reference method 
traverse point locations are permitted for moisture and gas monitor 
RATAs:
    (a) For moisture determinations where the moisture data are used 
only to determine stack gas molecular weight, a single reference 
method point, located at least 1.0 meter from the stack wall, may be 
used. For moisture monitoring system RATAs and for gas monitor RATAs 
in which moisture data are used to correct pollutant or diluent 
concentrations from a dry basis to a wet basis (or vice-versa), 
single-point moisture sampling may only be used if the 12-point 
stratification test described in section 6.5.6.1 of this appendix is 
performed prior to the RATA for at least one pollutant or diluent 
gas, and if the test is passed according to the acceptance criteria 
in section 6.5.6.3(b) of this appendix.
    (b) For gas monitoring system RATAs, the owner or operator may 
use any of the following options:
    (1) At any location (including locations where stratification is 
expected), use a minimum of six traverse points along a diameter, in 
the direction of any expected stratification. The points shall be 
located in accordance with Method 1 in appendix A to part 60 of this 
chapter.
    (2) At locations where section 3.2 of PS No. 2 allows the use of 
a short reference method measurement line (with three points located 
at 0.4, 1.0, and 2.0 meters from the stack wall), the owner or 
operator may use an alternative 3-point measurement line, locating 
the three points at 4.4, 14.6, and 29.6 percent of the way across 
the stack, in accordance with Method 1 in appendix A to part 60 of 
this chapter.
    (3) At locations where stratification is likely to occur (e.g., 
following a wet scrubber or when dissimilar gas streams are 
combined), the short measurement line from section 3.2 of PS No. 2 
(or the alternative line described in paragraph (b)(2) of this 
section) may be used in lieu of the prescribed ``long'' measurement 
line in section 3.2 of PS No. 2, provided that the 12-point 
stratification test described in section 6.5.6.1 of this appendix is 
performed and passed one time at the location (according to the 
acceptance criteria of section 6.5.6.3(a) of this appendix) and 
provided that either the 12-point stratification test or the 
alternative (abbreviated) stratification test in section 6.5.6.2 of 
this appendix is performed and passed prior to each subsequent RATA 
at the location (according to the acceptance criteria of section 
6.5.6.3(a) of this appendix).
    (4) A single reference method measurement point, located no less 
than 1.0 meter from the stack wall and situated along one of the 
measurement lines used for the stratification test, may be used at 
any sampling location if

[[Page 28642]]

the 12-point stratification test described in section 6.5.6.1 of 
this appendix is performed and passed prior to each RATA at the 
location (according to the acceptance criteria of section 6.5.6.3(b) 
of this appendix).

6.5.6.1  Stratification Test

    (a) With the unit(s) operating under steady-state conditions at 
normal load, as defined in section 6.5.2.1 of this appendix, use a 
traversing gas sampling probe to measure the pollutant 
(SO<INF>2</INF> or NO_X) and diluent (CO<INF>2</INF> or 
O<INF>2</INF>) concentrations at a minimum of twelve (12) points, 
located according to Method 1 in appendix A to part 60 of this 
chapter.
    (b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this 
chapter to make the measurements. Data from the reference method 
analyzers must be quality assured by performing analyzer calibration 
error and system bias checks before the series of measurements and 
by conducting system bias and calibration drift checks after the 
measurements, in accordance with the procedures of Methods 6C, 7E, 
and 3A.
    (c) Measure for a minimum of 2 minutes at each traverse point. 
To the extent practicable, complete the traverse within a 2-hour 
period.
    (d) If the load has remained constant (<plus-minus>3.0 percent) 
during the traverse and if the reference method analyzers have 
passed all of the required quality assurance checks, proceed with 
the data analysis.
    (e) Calculate the average NO_X, SO<INF>2</INF>, and 
CO<INF>2</INF> (or O<INF>2</INF>) concentrations at each of the 
individual traverse points. Then, calculate the arithmetic average 
NO_X, SO<INF>2</INF>, and CO<INF>2</INF> (or 
O<INF>2</INF>) concentrations for all traverse points.

6.5.6.2  Alternative (Abbreviated) Stratification Test

    (a) With the unit(s) operating under steady-state conditions at 
normal load, as defined in section 6.5.2.1 of this appendix, use a 
traversing gas sampling probe to measure the pollutant 
(SO<INF>2</INF> or NO_X) and diluent (CO<INF>2</INF> or 
O<INF>2</INF>) concentrations at three points. The points shall be 
located according to the specifications for the long measurement 
line in section 3.2 of PS No. 2 (i.e., locate the points 16.7 
percent, 50.0 percent, and 83.3 percent of the way across the 
stack). Alternatively, the concentration measurements may be made at 
six traverse points along a diameter. The six points shall be 
located in accordance with Method 1 in appendix A to part 60 of this 
chapter.
    (b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this 
chapter to make the measurements. Data from the reference method 
analyzers must be quality assured by performing analyzer calibration 
error and system bias checks before the series of measurements and 
by conducting system bias and calibration drift checks after the 
measurements, in accordance with the procedures of Methods 6C, 7E, 
and 3A.
    (c) Measure for a minimum of 2 minutes at each traverse point. 
To the extent practicable, complete the traverse within a 1-hour 
period.
    (d) If the load has remained constant (<plus-minus>3.0 percent) 
during the traverse and if the reference method analyzers have 
passed all of the required quality assurance checks, proceed with 
the data analysis.
    (e) Calculate the average NO_X, SO<INF>2</INF>, and 
CO<INF>2</INF> (or O<INF>2</INF>) concentrations at each of the 
individual traverse points. Then, calculate the arithmetic average 
NO_X, SO<INF>2</INF>, and CO<INF>2</INF> (or 
O<INF>2</INF>) concentrations for all traverse points.

6.5.6.3  Stratification Test Results and Acceptance Criteria

    (a) For each pollutant or diluent gas, the short reference 
method measurement line described in section 3.2 of PS No. 2 may be 
used in lieu of the long measurement line prescribed in section 3.2 
of PS No. 2 if the results of a stratification test, conducted in 
accordance with section 6.5.6.1 or 6.5.6.2 of this appendix (as 
appropriate; see section 6.5.6(b)(3) of this appendix), show that 
the concentration at each individual traverse point differs by no 
more than <plus-minus>10.0 percent from the arithmetic average 
concentration for all traverse points. The results are also 
acceptable if the concentration at each individual traverse point 
differs by no more than <plus-minus> 5ppm or <plus-minus>0.5 percent 
CO<INF>2</INF> (or O<INF>2</INF>) from the arithmetic average 
concentration for all traverse points.
    (b) For each pollutant or diluent gas, a single reference method 
measurement point, located at least 1.0 meter from the stack wall 
and situated along one of the measurement lines used for the 
stratification test, may be used for that pollutant or diluent gas 
if the results of a stratification test, conducted in accordance 
with section 6.5.6.1 of this appendix, show that the concentration 
at each individual traverse point differs by no more than 
<plus-minus>5.0 percent from the arithmetic average concentration 
for all traverse points. The results are also acceptable if the 
concentration at each individual traverse point differs by no more 
than <plus-minus>3 ppm or <plus-minus>0.3 percent CO<INF>2</INF> (or 
O<INF>2</INF>) from the arithmetic average concentration for all 
traverse points.
    (c) The owner or operator shall keep the results of all 
stratification tests on-site, in a format suitable for inspection, 
as part of the supplementary RATA records required under 
Sec. 75.56(a)(7) or Sec. 75.59(a)(7), as applicable.

6.5.7  Sampling Strategy

    (a) Conduct the reference method tests so they will yield 
results representative of the pollutant concentration, emission 
rate, moisture, temperature, and flue gas flow rate from the unit 
and can be correlated with the pollutant concentration monitor, 
CO<INF>2</INF> or O<INF>2</INF> monitor, flow monitor, and 
SO<INF>2</INF> or NO_X continuous emission monitoring 
system measurements. The minimum acceptable time for a gas 
monitoring system RATA run or for a moisture monitoring system RATA 
run is 21 minutes. For each run of a gas monitoring system RATA, all 
necessary pollutant concentration measurements, diluent 
concentration measurements, and moisture measurements (if 
applicable) must, to the extent practicable, be made within a 60-
minute period. For NO_X-diluent or SO<INF>2</INF>-diluent 
monitoring system RATAs, the pollutant and diluent concentration 
measurements must be made simultaneously. For flow monitor RATAs, 
the minimum time per run shall be 5 minutes. Flow rate reference 
method measurements may be made either sequentially from port to 
port or simultaneously at two or more sample ports. The velocity 
measurement probe may be moved from traverse point to traverse point 
either manually or automatically. If, during a flow RATA, 
significant pulsations in the reference method readings are 
observed, be sure to allow enough measurement time at each traverse 
point to obtain an accurate average reading when a manual readout 
method is used (e.g., a ``sight-weighted'' average from a 
manometer). A minimum of one set of auxiliary measurements for stack 
gas molecular weight determination (i.e., diluent gas data and 
moisture data) is required for every clock hour of a flow RATA or 
for every three test runs (whichever is less restrictive). 
Successive flow RATA runs may be performed without waiting in-
between runs. If an O<INF>2</INF>-diluent monitor is used as a 
CO<INF>2</INF> continuous emission monitoring system, perform a 
CO<INF>2</INF> system RATA (i.e., measure CO<INF>2</INF>, rather 
than O<INF>2</INF>, with the reference method). For moisture 
monitoring systems, an appropriate coefficient, ``K'' factor or 
other suitable mathematical algorithm may be developed prior to the 
RATA, to adjust the monitoring system readings with respect to the 
reference method. If such a coefficient, K-factor or algorithm is 
developed, it shall be applied to the CEMS readings during the RATA 
and (if the RATA is passed), to the subsequent CEMS data, by means 
of the automated data acquisition and handling system. The owner or 
operator shall keep records of the current coefficient, K factor or 
algorithm, as specified in Secs. 75.56(a)(5)(ix) and 
75.59(a)(5)(vii). Whenever the coefficient, K factor or algorithm is 
changed, a RATA of the moisture monitoring system is required.
    (b) To properly correlate individual SO<INF>2</INF> or 
NO_X continuous emission monitoring system data (in lb/
mmBtu) and volumetric flow rate data with the reference method data, 
annotate the beginning and end of each reference method test run 
(including the exact time of day) on the individual chart 
recorder(s) or other permanent recording device(s).
* * * * *

6.5.9  Number of Reference Method Tests

    Perform a minimum of nine sets of paired monitor (or monitoring 
system) and reference method test data for every required (i.e., 
certification, recertification, diagnostic, semiannual, or annual) 
relative accuracy test audit. For 2-level and 3-level relative 
accuracy test audits of flow monitors, perform a minimum of nine 
sets at each of the operating levels.

    Note: The tester may choose to perform more than nine sets of 
reference method tests. If this option is chosen, the tester may 
reject a maximum of three sets of the test results, as long as the 
total number of test results used to determine the relative accuracy 
or bias is greater than or equal to nine. Report all data, including 
the rejected CEMS data and corresponding reference method test 
results.

6.5.10  Reference Methods

    The following methods from appendix A to part 60 of this chapter 
or their approved alternatives are the reference methods for 
performing relative accuracy test audits: Method 1 or 1A for siting; 
Method 2 or its

[[Page 28643]]

allowable alternatives in appendix A to part 60 of this chapter 
(except for Methods 2B and 2E) for stack gas velocity and volumetric 
flow rate; Methods 3, 3A, or 3B for O<INF>2</INF> or CO<INF>2</INF>; 
Method 4 for moisture; Methods 6, 6A, or 6C for SO<INF>2</INF>; 
Methods 7, 7A, 7C, 7D or 7E for NO_X, excluding the 
exception in section 5.1.2 of Method 7E. When using Method 7E for 
measuring NO_X concentration, total NO_X, both 
NO and NO<INF>2</INF>, must be measured.
    59. Appendix A to part 75 is amended by revising in sections 
7.2.1, and 7.2.2, the text following each section's equation, 
beginning with the word ``where''; by revising sections 7.6, 7.6.4, 
and 7.6.5 and by adding new sections 7.7 and 7.8 (without revising 
the Figures for Appendix A that appear at the end of section 7 to 
Appendix A) to read as follows:

7. Calculations

* * * * *

7.2.1  Pollutant Concentration and Diluent Monitors

* * * * *
Where:

CE = Calibration error as a percentage of the span of the 
instrument.
R = Reference value of zero or upscale (high-level or mid-level, as 
applicable) calibration gas introduced into the monitoring system.
A = Actual monitoring system response to the calibration gas.
S = Span of the instrument, as specified in section 2 of this 
appendix.

7.2.2  Flow Monitor Calibration Error

* * * * *
Where:

CE = Calibration error as a percentage of span.
R = Low or high level reference value specified in section 2.2.2.1 
of this appendix.
A = Actual flow monitor response to the reference value.
S = Flow monitor calibration span value as determined under section 
2.1.4.2 of this appendix.
* * * * *

7.6  Bias Test and Adjustment Factor

    Test the following relative accuracy test audit data sets for 
bias: SO<INF>2</INF> pollutant concentration monitors; flow 
monitors; NO_X concentration monitoring systems used to 
determine NO_X mass emissions, as defined in 
Sec. 75.71(a)(2); and NO_X-diluent continuous emission 
monitoring systems, using the procedures outlined in section 7.6.1 
through 7.6.5 of this appendix. For multiple-load flow RATAs, 
perform a bias test at each load level designated as normal under 
section 6.5.2.1 of this appendix.
* * * * *

7.6.4  Bias Test

    If, for the relative accuracy test audit data set being tested, 
the mean difference, d, is less than or equal to the absolute value 
of the confidence coefficient, | cc |, the monitor or monitoring 
system has passed the bias test. If the mean difference, d, is 
greater than the absolute value of the confidence coefficient, | cc 
|, the monitor or monitoring system has failed to meet the bias test 
requirement.

7.6.5  Bias Adjustment

    (a) If the monitor or monitoring system fails to meet the bias 
test requirement, adjust the value obtained from the monitor using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.005

Where:

CEM<INF>i</INF> ^Monitor = Data (measurement) provided by 
the monitor at time i.
CEM<INF>i</INF> ^Adjusted = Data value, adjusted for bias, 
at time i.
BAF = Bias adjustment factor, defined by:
[GRAPHIC] [TIFF OMITTED] TR26MY99.006

Where:

BAF = Bias adjustment factor, calculated to the nearest thousandth.
d = Arithmetic mean of the difference obtained during the failed 
bias test using Equation A-7.
CEM<INF>avg</INF> = Mean of the data values provided by the monitor 
during the failed bias test.

    (b) For single-load RATAs of SO<INF>2</INF> pollutant 
concentration monitors, NO_X concentration monitoring 
systems, and NO_X-diluent monitoring systems and for the 
single-load flow RATAs required or allowed under section 6.5.2 of 
this appendix and sections 2.3.1.3(b) and 2.3.1.3(c) of appendix B 
to this part, the appropriate BAF is determined directly from the 
RATA results at normal load, using Equation A-12. Notwithstanding, 
when a NO_X concentration CEMS or an SO<INF>2</INF> CEMS 
or a NO_X-diluent CEMS installed on a low-emitting 
affected unit (i.e., average SO<INF>2</INF> or NO_X 
concentration during the RATA <plus-minus> 250 ppm or average 
NO_X emission rate <plus-minus> 0.200 lb/mmBtu) meets the 
normal 10.0 percent relative accuracy specification (as calculated 
using Equation A-10) or the alternate relative accuracy 
specification in section 3.3 of this appendix for low-emitters, but 
fails the bias test, the BAF may either be determined using Equation 
A-12, or a default BAF of 1.111 may be used.
    (c) For 2-load or 3-load flow RATAs, when only one load level 
(low, mid or high) has been designated as normal under section 
6.5.2.1 of this appendix and the bias test is passed at the normal 
load level, apply a BAF of 1.000 to the subsequent flow rate data. 
If the bias test is failed at the normal load level, use Equation A-
12 to calculate the normal load BAF and then perform an additional 
bias test at the second most frequently-used load level, as 
determined under section 6.5.2.1 of this appendix. If the bias test 
is passed at this second load level, apply the normal load BAF to 
the subsequent flow rate data. If the bias test is failed at this 
second load level, use Equation A-12 to calculate the BAF at the 
second load level and apply the higher of the two BAFs (either from 
the normal load level or from the second load level) to the 
subsequent flow rate data.
    (d) For 2-load or 3-load flow RATAs, when two load levels have 
been designated as normal under section 6.5.2.1 of this appendix and 
the bias test is passed at both normal load levels, apply a BAF of 
1.000 to the subsequent flow rate data. If the bias test is failed 
at one of the normal load levels but not at the other, use Equation 
A-12 to calculate the BAF for the normal load level at which the 
bias test was failed and apply that BAF to the subsequent flow rate 
data. If the bias test is failed at both designated normal load 
levels, use Equation A-12 to calculate the BAF at each normal load 
level and apply the higher of the two BAFs to the subsequent flow 
rate data.
    (e) Each time a RATA is passed and the appropriate bias 
adjustment factor has been determined, apply the BAF prospectively 
to all monitoring system data, beginning with the first clock hour 
following the hour in which the RATA was completed. For a 2-load 
flow RATA, the ``hour in which the RATA was completed'' refers to 
the hour in which the testing at both loads was completed; for a 3-
load RATA, it refers to the hour in which the testing at all three 
loads was completed.
    (f) Use the bias-adjusted values in computing substitution 
values in the missing data procedure, as specified in subpart D of 
this part, and in reporting the concentration of SO<INF>2</INF>, the 
flow rate, the average NO_X emission rate, the unit heat 
input, and the calculated mass emissions of SO<INF>2</INF> and 
CO<INF>2</INF> during the quarter and calendar year, as specified in 
subpart G of this part. In addition, when using a NO_X 
concentration monitoring system and a flow monitor to calculate 
NO_X mass emissions under subpart H of this part, use 
bias-adjusted values for NO_X concentration and flow rate 
in the mass emission calculations and use bias-adjusted 
NO_X concentrations to compute the appropriate 
substitution values for NO_X concentration in the missing 
data routines under subpart D of this part.
* * * * *

7.7  Reference Flow-to-Load Ratio or Gross Heat Rate

    (a) Except as provided in section 7.8 of this appendix, the 
owner or operator shall determine R<INF>ref</INF>, the reference 
value of the ratio of flow rate to unit load, each time that a 
passing flow RATA is performed at a load level designated as normal 
in section 6.5.2.1 of this appendix. The owner or operator shall 
report the current value of R<INF>ref</INF> in the electronic 
quarterly report required under Sec. 75.64 and shall also report the 
completion date of the associated RATA. If two load levels have been 
designated as normal under

[[Page 28644]]

section 6.5.2.1 of this appendix, the owner or operator shall 
determine a separate R<INF>ref</INF> value for each of the normal 
load levels. The requirements of this section shall become effective 
as of April 1, 2000. The reference flow-to-load ratio shall be 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.007

Where:

R<INF>ref</INF> = Reference value of the flow-to-load ratio, from 
the most recent normal-load flow RATA, scfh/megawatts or scfh/1000 
lb/hr of steam.
Q<INF>ref</INF> = Average stack gas volumetric flow rate measured by 
the reference method during the normal-load RATA, scfh.
L<INF>avg</INF> = Average unit load during the normal-load flow 
RATA, megawatts or 1000 lb/hr of steam.

    (b) In Equation A-13, for a common stack, L<INF>avg</INF> shall 
be the sum of the operating loads of all units that discharge 
through the stack. For a unit that discharges its emissions through 
multiple stacks (except for a discharge configuration consisting of 
a main stack and a bypass stack), Q<INF>ref</INF> will be the sum of 
the total volumetric flow rates that discharge through all of the 
stacks. For a unit with a multiple stack discharge configuration 
consisting of a main stack and a bypass stack (e.g., a unit with a 
wet SO<INF>2</INF> scrubber), determine Q<INF>ref</INF> separately 
for each stack at the time of the normal load flow RATA. Round off 
the value of R<INF>ref</INF> to two decimal places.
    (c) In addition to determining R<INF>ref</INF> or as an 
alternative to determining R<INF>ref</INF>, a reference value of the 
gross heat rate (GHR) may be determined. In order to use this 
option, quality assured diluent gas (CO<INF>2</INF> or 
O<INF>2</INF>) must be available for each hour of the most recent 
normal-load flow RATA. The reference value of the GHR shall be 
determined as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.008

Where:

(GHR)<INF>ref</INF> = Reference value of the gross heat rate at the 
time of the most recent normal-load flow RATA, Btu/kwh or Btu/lb 
steam load.
(Heat Input)<INF>avg</INF> = Average hourly heat input during the 
normal-load flow RATA, as determined using the applicable equation 
in appendix F to this part, mmBtu/hr.
L<INF>avg</INF> = Average unit load during the normal-load flow 
RATA, megawatts or 1000 lb/hr of steam.

    (d) In the calculation of (Heat Input)<INF>avg</INF>, use 
Q<INF>ref</INF>, the average volumetric flow rate measured by the 
reference method during the RATA, and use the average diluent gas 
concentration measured during the flow RATA.

7.8  Flow-to-Load Test Exemptions

    The requirements of this section apply beginning on April 1, 
2000. For complex stack configurations (e.g., when the effluent from 
a unit is divided and discharges through multiple stacks in such a 
manner that the flow rate in the individual stacks cannot be 
correlated with unit load), the owner or operator may petition the 
Administrator under Sec. 75.66 for an exemption from the 
requirements of section 7.7 of this appendix. The petition must 
include sufficient information and data to demonstrate that a flow-
to-load or gross heat rate evaluation is infeasible for the complex 
stack configuration.

Appendix B to Part 75--Quality Assurance and Quality Control Procedures

    60. Appendix B to part 75 is amended by revising sections 1 and 
1.1; adding sections 1.1.1 through 1.1.3; revising section 1.2; 
adding sections 1.2.1 through 1.2.4; revising section 1.3; adding 
sections 1.3.1 through 1.3.6; revising section 1.4; adding sections 
1.4.1 through 1.4.3; and removing sections 1.5 and 1.6 to read as 
follows:

1. Quality Assurance/Quality Control Program

    Develop and implement a quality assurance/quality control (QA/
QC) program for the continuous emission monitoring systems, excepted 
monitoring systems approved under appendix D or E to this part, and 
alternative monitoring systems under subpart E of this part, and 
their components. At a minimum, include in each QA/QC program a 
written plan that describes in detail (or that refers to separate 
documents containing) complete, step-by-step procedures and 
operations for each of the following activities. Upon request from 
regulatory authorities, the source shall make all procedures, 
maintenance records, and ancillary supporting documentation from the 
manufacturer (e.g., software coefficients and troubleshooting 
diagrams) available for review during an audit.

1.1  Requirements for All Monitoring Systems

1.1.1  Preventive Maintenance

    Keep a written record of procedures needed to maintain the 
monitoring system in proper operating condition and a schedule for 
those procedures. This shall, at a minimum, include procedures 
specified by the manufacturers of the equipment and, if applicable, 
additional or alternate procedures developed for the equipment.

1.1.2  Recordkeeping and Reporting

    Keep a written record describing procedures that will be used to 
implement the recordkeeping and reporting requirements in subparts 
E, F, and G and appendices D and E to this part, as applicable.

1.1.3  Maintenance Records

    Keep a record of all testing, maintenance, or repair activities 
performed on any monitoring system or component in a location and 
format suitable for inspection. A maintenance log may be used for 
this purpose. The following records should be maintained: date, 
time, and description of any testing, adjustment, repair, 
replacement, or preventive maintenance action performed on any 
monitoring system and records of any corrective actions associated 
with a monitor's outage period. Additionally, any adjustment that 
recharacterizes a system's ability to record and report emissions 
data must be recorded (e.g., changing of flow monitor or moisture 
monitoring system polynomial coefficients, K factors or mathematical 
algorithms, changing of temperature and pressure coefficients and 
dilution ratio settings), and a written explanation of the 
procedures used to make the adjustment(s) shall be kept.

1.2  Specific Requirements for Continuous Emissions Monitoring Systems

1.2.1   Calibration Error Test and Linearity Check Procedures

    Keep a written record of the procedures used for daily 
calibration error tests and linearity checks (e.g., how gases are to 
be injected, adjustments of flow rates and pressure, introduction of 
reference values, length of time for injection of calibration gases, 
steps for obtaining calibration error or error in linearity, 
determination of interferences, and when calibration adjustments 
should be made). Identify any calibration error test and linearity 
check procedures specific to the continuous emission monitoring 
system that vary from the procedures in appendix A to this part.

1.2.2  Calibration and Linearity Adjustments

    Explain how each component of the continuous emission monitoring 
system will be adjusted to provide correct responses to calibration 
gases, reference values, and/or indications of interference both 
initially and after repairs or corrective action. Identify 
equations, conversion factors and other factors affecting 
calibration of each continuous emission monitoring system.

1.2.3  Relative Accuracy Test Audit Procedures

    Keep a written record of procedures and details peculiar to the 
installed continuous emission monitoring systems that are to be used 
for relative accuracy test audits, such as sampling and analysis 
methods.

1.2.4  Parametric Monitoring for Units With Add-on Emission Controls

    The owner or operator shall keep a written (or electronic) 
record including a list of operating parameters for the add-on 
SO<INF>2</INF> or NO_X emission controls, including 
parameters in Sec. 75.55(b) or Sec. 75.58(b), as applicable, and the 
range of each operating parameter that

[[Page 28645]]

indicates the add-on emission controls are operating properly. The 
owner or operator shall keep a written (or electronic) record of the 
parametric monitoring data during each SO<INF>X</INF> or 
NO<INF>2</INF> missing data period.

1.3  Specific Requirements for Excepted Systems Approved Under 
Appendices D and E

1.3.1  Fuel Flowmeter Accuracy Test Procedures

    Keep a written record of the specific fuel flowmeter accuracy 
test procedures. These may include: standard methods or 
specifications listed in and section 2.1.5.1 of appendix D to this 
part and incorporated by reference under Sec. 75.6; the procedures 
of sections 2.1.5.2 or 2.1.7 of appendix D to this part; or other 
methods approved by the Administrator through the petition process 
of Sec. 75.66(c).

1.3.2  Transducer or Transmitter Accuracy Test Procedures

    Keep a written record of the procedures for testing the accuracy 
of transducers or transmitters of an orifice-, nozzle-, or venturi-
type fuel flowmeter under section 2.1.6 of appendix D to this part. 
These procedures should include a description of equipment used, 
steps in testing, and frequency of testing.

1.3.3  Fuel Flowmeter, Transducer, or Transmitter Calibration and 
Maintenance Records

    Keep a record of adjustments, maintenance, or repairs performed 
on the fuel flowmeter monitoring system. Keep records of the data 
and results for fuel flowmeter accuracy tests and transducer 
accuracy tests, consistent with appendix D to this part.

1.3.4  Primary Element Inspection Procedures

    Keep a written record of the standard operating procedures for 
inspection of the primary element (i.e., orifice, venturi, or 
nozzle) of an orifice-, venturi-, or nozzle-type fuel flowmeter. 
Examples of the types of information to be included are: what to 
examine on the primary element; how to identify if there is 
corrosion sufficient to affect the accuracy of the primary element; 
and what inspection tools (e.g., baroscope), if any, are used.

1.3.5  Fuel Sampling Method and Sample Retention

    Keep a written record of the standard procedures used to perform 
fuel sampling, either by utility personnel or by fuel supply company 
personnel. These procedures should specify the portion of the ASTM 
method used, as incorporated by reference under Sec. 75.6, or other 
methods approved by the Administrator through the petition process 
of Sec. 75.66(c). These procedures should describe safeguards for 
ensuring the availability of an oil sample (e.g., procedure and 
location for splitting samples, procedure for maintaining sample 
splits on site, and procedure for transmitting samples to an 
analytical laboratory). These procedures should identify the ASTM 
analytical methods used to analyze sulfur content, gross calorific 
value, and density, as incorporated by reference under Sec. 75.6, or 
other methods approved by the Administrator through the petition 
process of Sec. 75.66(c).

1.3.6  Appendix E Monitoring System Quality Assurance Information

    Identify the unit manufacturer's recommended range of quality 
assurance- and quality control-related operating parameters. Keep 
records of these operating parameters for each hour of unit 
operation (i.e., fuel combustion). Keep a written record of the 
procedures used to perform NO_X emission rate testing. 
Keep a copy of all data and results from the initial and from the 
most recent NO_X emission rate testing, including the 
values of quality assurance parameters specified in section 2.3 of 
appendix E to this part.

1.4  Requirements for Alternative Systems Approved Under Subpart E

1.4.1  Daily Quality Assurance Tests

    Explain how the daily assessment procedures specific to the 
alternative monitoring system are to be performed.

1.4.2  Daily Quality Assurance Test Adjustments

    Explain how each component of the alternative monitoring system 
will be adjusted in response to the results of the daily 
assessments.

1.4.3  Relative Accuracy Test Audit Procedures

    Keep a written record of procedures and details peculiar to the 
installed alternative monitoring system that are to be used for 
relative accuracy test audits, such as sampling and analysis 
methods.
    61. Appendix B to part 75 is amended by:
    a. Revising the first paragraph of section 2.1.1, revising 
sections 2.1.3 and 2.1.4; revising paragraph (1) of section 2.1.5.1; 
revising sections 2.2 through 2.2.3; adding sections 2.2.4 through 
2.2.5.3; revising sections 2.3 and 2.3.1; adding sections 2.3.1.1 
through 2.3.1.4; revising sections 2.3.2 and 2.3.3; and adding 
section 2.3.4;
    b. Redesignating existing section 2.4 as section 2.5;
    c. Adding new section 2.4; and
    d. Revising Figures 1 and 2 at the end of appendix B to read as 
follows:

2. Frequency of Testing

* * * * *
    2.1 * * *

2.1.1  Calibration Error Test

    Except as provided in section 2.1.1.2 of this appendix, perform 
the daily calibration error test of each gas monitoring system 
(including moisture monitoring systems consisting of wet- and dry-
basis O<INF>2</INF> analyzers) according to the procedures in 
section 6.3.1 of appendix A to this part, and perform the daily 
calibration error test of each flow monitoring system according to 
the procedure in section 6.3.2 of appendix A to this part.
* * * * *

2.1.3  Additional Calibration Error Tests and Calibration Adjustments

    (a) In addition to the daily calibration error tests required 
under section 2.1.1 of this appendix, a calibration error test of a 
monitor shall be performed in accordance with section 2.1.1 of this 
appendix, as follows: whenever a daily calibration error test is 
failed; whenever a monitoring system is returned to service 
following repair or corrective maintenance that could affect the 
monitor's ability to accurately measure and record emissions data; 
or after making certain calibration adjustments, as described in 
this section. Except in the case of the routine calibration 
adjustments described in this section, data from the monitor are 
considered invalid until the required additional calibration error 
test has been successfully completed.
    (b) Routine calibration adjustments of a monitor are permitted 
after any successful calibration error test. These routine 
adjustments shall be made so as to bring the monitor readings as 
close as practicable to the known tag values of the calibration 
gases or to the actual value of the flow monitor reference signals. 
An additional calibration error test is required following routine 
calibration adjustments where the monitor's calibration has been 
physically adjusted (e.g., by turning a potentiometer) to verify 
that the adjustments have been made properly. An additional 
calibration error test is not required, however, if the routine 
calibration adjustments are made by means of a mathematical 
algorithm programmed into the data acquisition and handling system. 
The EPA recommends that routine calibration adjustments be made, at 
a minimum, whenever the daily calibration error exceeds the limits 
of the applicable performance specification in appendix A to this 
part for the pollutant concentration monitor, CO<INF>2</INF> or 
O<INF>2</INF> monitor, or flow monitor.
    (c) Additional (non-routine) calibration adjustments of a 
monitor are permitted prior to (but not during) linearity checks and 
RATAs and at other times, provided that an appropriate technical 
justification is included in the quality control program required 
under section 1 of this appendix. The allowable non-routine 
adjustments are as follows. The owner or operator may physically 
adjust the calibration of a monitor (e.g., by means of a 
potentiometer), provided that the post-adjustment zero and upscale 
responses of the monitor are within the performance specifications 
of the instrument given in section 3.1 of appendix A to this part. 
An additional calibration error test is required following such 
adjustments to verify that the monitor is operating within the 
performance specifications at both the zero and upscale calibration 
levels.

2.1.4  Data Validation

    (a) An out-of-control period occurs when the calibration error 
of an SO<INF>2</INF> or NO_X pollutant concentration 
monitor exceeds 5.0 percent of the span value (or exceeds 10 ppm, 
for span values <200 ppm), when the calibration error of a 
CO<INF>2</INF> or O<INF>2</INF> monitor (including O<INF>2</INF> 
monitors used to measure CO<INF>2</INF> emissions or percent 
moisture) exceeds 1.0 percent O<INF>2</INF> or CO<INF>2</INF>, or 
when the calibration

[[Page 28646]]

error of a flow monitor or a moisture sensor exceeds 6.0 percent of 
the span value, which is twice the applicable specification of 
appendix A to this part. Notwithstanding, a differential pressure-
type flow monitor for which the calibration error exceeds 6.0 
percent of the span value shall not be considered out-of-control if 
<rm-bond>R-A<rm-bond>, the absolute value of the difference between 
the monitor response and the reference value in Equation A-6, is 
<ls-thn-eq>0.02 inches of water. The out-of-control period begins 
upon failure of the calibration error test and ends upon completion 
of a successful calibration error test. Note, that if a failed 
calibration, corrective action, and successful calibration error 
test occur within the same hour, emission data for that hour 
recorded by the monitor after the successful calibration error test 
may be used for reporting purposes, provided that two or more valid 
readings are obtained as required by Sec. 75.10. A NO_X-
diluent continuous emission monitoring system is considered out-of-
control if the calibration error of either component monitor exceeds 
twice the applicable performance specification in appendix A to this 
part. Emission data shall not be reported from an out-of-control 
monitor.
    (b) An out-of-control period also occurs whenever interference 
of a flow monitor is identified. The out-of-control period begins 
with the hour of completion of the failed interference check and 
ends with the hour of completion of an interference check that is 
passed.

2.1.5  * * *

2.1.5.1  * * *

    (1) Data from a monitoring system are invalid, beginning with 
the first hour following the expiration of a 26-hour data validation 
period or beginning with the first hour following the expiration of 
an 8-hour start-up grace period (as provided under section 2.1.5.2 
of this appendix), if the required subsequent daily assessment has 
not been conducted.
* * * * *

2.2  Quarterly Assessments

    For each primary and redundant backup monitor or monitoring 
system, perform the following quarterly assessments. This 
requirement is applies as of the calendar quarter following the 
calendar quarter in which the monitor or continuous emission 
monitoring system is provisionally certified.

2.2.1  Linearity Check

    Perform a linearity check, in accordance with the procedures in 
section 6.2 of appendix A to this part, for each primary and 
redundant backup SO<INF>2</INF> and NO_X pollutant 
concentration monitor and each primary and redundant backup 
CO<INF>2</INF> or O<INF>2</INF> monitor (including O<INF>2</INF> 
monitors used to measure CO<INF>2</INF> emissions or to continuously 
monitor moisture) at least once during each QA operating quarter, as 
defined in Sec. 72.2 of this chapter. For units using both a low and 
high span value, a linearity check is required only on the range(s) 
used to record and report emission data during the QA operating 
quarter. Conduct the linearity checks no less than 30 days apart, to 
the extent practicable. The data validation procedures in section 
2.2.3(e) of this appendix shall be followed.

2.2.2  Leak Check

    For differential pressure flow monitors, perform a leak check of 
all sample lines (a manual check is acceptable) at least once during 
each QA operating quarter. For this test, the unit does not have to 
be in operation. Conduct the leak checks no less than 30 days apart, 
to the extent practicable. If a leak check is failed, follow the 
applicable data validation procedures in section 2.2.3(f) of this 
appendix.

2.2.3  Data Validation

    (a) A linearity check shall not be commenced if the monitoring 
system is operating out-of-control with respect to any of the daily 
or semiannual quality assurance assessments required by sections 2.1 
and 2.3 of this appendix or with respect to the additional 
calibration error test requirements in section 2.1.3 of this 
appendix.
    (b) Each required linearity check shall be done according to 
paragraph (b)(1), (b)(2) or (b)(3) of this section:
    (1) The linearity check may be done ``cold,'' i.e., with no 
corrective maintenance, repair, calibration adjustments, re-
linearization or reprogramming of the monitor prior to the test.
    (2) The linearity check may be done after performing only the 
routine or non-routine calibration adjustments described in section 
2.1.3 of this appendix at the various calibration gas levels (zero, 
low, mid or high), but no other corrective maintenance, repair, re-
linearization or reprogramming of the monitor. Trial gas injection 
runs may be performed after the calibration adjustments and 
additional adjustments within the allowable limits in section 2.1.3 
of this appendix may be made prior to the linearity check, as 
necessary, to optimize the performance of the monitor. The trial gas 
injections need not be reported, provided that they meet the 
specification for trial gas injections in 
Sec. 75.20(b)(3)(vii)(E)(1). However, if, for any trial injection, 
the specification in Sec. 75.20(b)(3)(vii)(E)(1) is not met, the 
trial injection shall be counted as an aborted linearity check.
    (3) The linearity check may be done after repair, corrective 
maintenance or reprogramming of the monitor. In this case, the 
monitor shall be considered out-of-control from the hour in which 
the repair, corrective maintenance or reprogramming is commenced 
until the linearity check has been passed. Alternatively, the data 
validation procedures and associated timelines in 
Secs. 75.20(b)(3)(ii) through (ix) may be followed upon completion 
of the necessary repair, corrective maintenance, or reprogramming. 
If the procedures in Sec. 75.20(b)(3) are used, the words ``quality 
assurance'' apply instead of the word ``recertification''.
    (c) Once a linearity check has been commenced, the test shall be 
done hands-off. That is, no adjustments of the monitor are permitted 
during the linearity test period, other than the routine calibration 
adjustments following daily calibration error tests, as described in 
section 2.1.3 of this appendix.
    (d) If a daily calibration error test is failed during a 
linearity test period, prior to completing the test, the linearity 
test must be repeated. Data from the monitor are invalidated 
prospectively from the hour of the failed calibration error test 
until the hour of completion of a subsequent successful calibration 
error test. The linearity test shall not be commenced until the 
monitor has successfully completed a calibration error test.
    (e) An out-of-control period occurs when a linearity test is 
failed (i.e., when the error in linearity at any of the three 
concentrations in the quarterly linearity check (or any of the six 
concentrations, when both ranges of a single analyzer with a dual 
range are tested) exceeds the applicable specification in section 
3.2 of appendix A to this part) or when a linearity test is aborted 
due to a problem with the monitor or monitoring system. For a 
NO_X-diluent or SO<INF>2</INF>-diluent continuous emission 
monitoring system, the system is considered out-of-control if either 
of the component monitors exceeds the applicable specification in 
section 3.2 of appendix A to this part or if the linearity test of 
either component is aborted due to a problem with the monitor. The 
out-of-control period begins with the hour of the failed or aborted 
linearity check and ends with the hour of completion of a 
satisfactory linearity check following corrective action and/or 
monitor repair, unless the option in paragraph (b)(3) of this 
section to use the data validation procedures and associated 
timelines in Sec. 75.20(b)(3)(ii) through (ix) has been selected, in 
which case the beginning and end of the out-of-control period shall 
be determined in accordance with Secs. 75.20(b)(3)(vii)(A) and (B). 
Note that a monitor shall not be considered out-of-control when a 
linearity test is aborted for a reason unrelated to the monitor's 
performance (e.g., a forced unit outage).
    (f) No more than four successive calendar quarters shall elapse 
after the quarter in which a linearity check of a monitor or 
monitoring system (or range of a monitor or monitoring system) was 
last performed without a subsequent linearity test having been 
conducted. If a linearity test has not been completed by the end of 
the fourth calendar quarter since the last linearity test, then the 
linearity test must be completed within a 168 unit operating hour or 
stack operating hour ``grace period'' (as provided in section 2.2.4 
of this appendix) following the end of the fourth successive elapsed 
calendar quarter, or data from the CEMS (or range) will become 
invalid.
    (g) An out-of-control period also occurs when a flow monitor 
sample line leak is detected. The out-of-control period begins with 
the hour of the failed leak check and ends with the hour of a 
satisfactory leak check following corrective action.
    (h) For each monitoring system, report the results of all 
completed and partial linearity tests that affect data validation 
(i.e., all completed, passed linearity checks; all completed, failed 
linearity checks; and all linearity checks aborted due to a problem 
with the monitor, including trial gas injections counted as failed 
test attempts under paragraph (b)(2) of this section or

[[Page 28647]]

under Sec. 75.20(b)(3)(vii)(F)), in the quarterly report required 
under Sec. 75.64. Note that linearity attempts which are aborted or 
invalidated due to problems with the reference calibration gases or 
due to operational problems with the affected unit(s) need not be 
reported. Such partial tests do not affect the validation status of 
emission data recorded by the monitor. A record of all linearity 
tests, trial gas injections and test attempts (whether reported or 
not) must be kept on-site as part of the official test log for each 
monitoring system.

2.2.4  Linearity and Leak Check Grace Period

    (a) When a required linearity test or flow monitor leak check 
has not been completed by the end of the QA operating quarter in 
which it is due or if, due to infrequent operation of a unit or 
infrequent use of a required high range of a monitor or monitoring 
system, four successive calendar quarters have elapsed after the 
quarter in which a linearity check of a monitor or monitoring system 
(or range) was last performed without a subsequent linearity test 
having been done, the owner or operator has a grace period of 168 
consecutive unit operating hours, as defined in Sec. 72.2 of this 
chapter (or, for monitors installed on common stacks or bypass 
stacks, 168 consecutive stack operating hours, as defined in 
Sec. 72.2 of this chapter) in which to perform a linearity test or 
leak check of that monitor or monitoring system (or range). The 
grace period begins with the first unit or stack operating hour 
following the calendar quarter in which the linearity test was due. 
Data validation during a linearity or leak check grace period shall 
be done in accordance with the applicable provisions in section 
2.2.3 of this appendix.
    (b) If, at the end of the 168 unit (or stack) operating hour 
grace period, the required linearity test or leak check has not been 
completed, data from the monitoring system (or range) shall be 
invalid, beginning with the hour following the expiration of the 
grace period. Data from the monitoring system (or range) remain 
invalid until the hour of completion of a subsequent successful 
hands-off linearity test or leak check of the monitor or monitoring 
system (or range). Note that when a linearity test or a leak check 
is conducted within a grace period for the purpose of satisfying the 
linearity test or leak check requirement from a previous QA 
operating quarter, the results of that linearity test or leak check 
may only be used to meet the linearity check or leak check 
requirement of the previous quarter, not the quarter in which the 
missed linearity test or leak check is completed.

2.2.5  Flow-to-Load Ratio or Gross Heat Rate Evaluation

    (a) Applicability and methodology. The provisions of this 
section apply beginning on April 1, 2000. Unless exempted by an 
approved petition in accordance with section 7.8 of appendix A to 
this part, the owner or operator shall, for each flow rate 
monitoring system installed on each unit, common stack or multiple 
stack, evaluate the flow-to-load ratio quarterly, i.e., for each QA 
operating quarter (as defined in Sec. 72.2 of this chapter). At the 
end of each QA operating quarter, the owner or operator shall use 
Equation B-1 to calculate the flow-to-load ratio for every hour 
during the quarter in which: the unit (or combination of units, for 
a common stack) operated within <plus-minus>10.0 percent of 
L<INF>avg</INF>, the average load during the most recent normal-load 
flow RATA; and a quality assured hourly average flow rate was 
obtained with a certified flow rate monitor.
[GRAPHIC] [TIFF OMITTED] TR26MY99.009

Where:

R<INF>h</INF> = Hourly value of the flow-to-load ratio, scfh/
megawatts or scfh/1000 lb/hr of steam load.
Q<INF>h</INF> = Hourly stack gas volumetric flow rate, as measured 
by the flow rate monitor, scfh.
L<INF>h</INF> = Hourly unit load, megawatts or 1000 lb/hr of steam; 
must be within <plus-minus>10.0 percent of L<INF>avg</INF> during 
the most recent normal-load flow RATA.

    (1) In Equation B-1, the owner or operator may use either bias-
adjusted flow rates or unadjusted flow rates, provided that all of 
the ratios are calculated the same way. For a common stack, 
L<INF>h</INF> shall be the sum of the hourly operating loads of all 
units that discharge through the stack. For a unit that discharges 
its emissions through multiple stacks (except when one of the stacks 
is a bypass stack) or that monitors its emissions in multiple 
breechings, Q<INF>h</INF> will be the combined hourly volumetric 
flow rate for all of the stacks or ducts. For a unit with a multiple 
stack discharge configuration consisting of a main stack and a 
bypass stack, each of which has a certified flow monitor (e.g., a 
unit with a wet SO<INF>2</INF> scrubber), calculate the hourly flow-
to-load ratios separately for each stack. Round off each value of 
R<INF>h</INF> to two decimal places.
    (2) Alternatively, the owner or operator may calculate the 
hourly gross heat rates (GHR) in lieu of the hourly flow-to-load 
ratios. The hourly GHR shall be determined only for those hours in 
which quality assured flow rate data and diluent gas (CO<INF>2</INF> 
or O<INF>2</INF>) concentration data are both available from a 
certified monitor or monitoring system or reference method. If this 
option is selected, calculate each hourly GHR value as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.010

where:

(GHR)<INF>h</INF> = Hourly value of the gross heat rate, Btu/kwh or 
Btu/lb steam load.
(Heat Input)<INF>h</INF> = Hourly heat input, as determined from the 
quality assured flow rate and diluent data, using the applicable 
equation in appendix F to this part, mmBtu/hr.
L<INF>h</INF> = Hourly unit load, megawatts or 1000 lb/hr of steam; 
must be within <plus-minus> 10.0 percent of L<INF>avg</INF> during 
the most recent normal-load flow RATA.

    (3) In Equation B-1a, the owner or operator may either use bias-
adjusted flow rates or unadjusted flow rates in the calculation of 
(Heat Input)<INF>h</INF>, provided that all of the heat input values 
are determined in the same manner.
    (4) The owner or operator shall evaluate the calculated hourly 
flow-to-load ratios (or gross heat rates) as follows. A separate 
data analysis shall be performed for each primary and each redundant 
backup flow rate monitor used to record and report data during the 
quarter. Each analysis shall be based on a minimum of 168 recorded 
hourly average flow rates. When two RATA load levels are designated 
as normal, the analysis shall be performed at the higher load level, 
unless there are fewer than 168 data points available at that load 
level, in which case the analysis shall be performed at the lower 
load level. If, for a particular flow monitor, fewer than 168 hourly 
flow-to-load ratios (or GHR values) are available at any of the load 
levels designated as normal, a flow-to-load (or GHR) evaluation is 
not required for that monitor for that calendar quarter.
    (5) For each flow monitor, use Equation B-2 in this appendix to 
calculate E<INF>h</INF>, the absolute percentage difference between 
each hourly R<INF>h</INF> value and R<INF>ref</INF>, the reference 
value of the flow-to-load ratio, as determined in accordance with 
section 7.7 of appendix A to this part. Note that R<INF>ref</INF> 
shall always be based upon the most recent normal-load RATA, even if 
that RATA was performed in the calendar quarter being evaluated.

[[Page 28648]]

[GRAPHIC] [TIFF OMITTED] TR26MY99.011


where:

E<INF>h</INF> = Absolute percentage difference between the hourly 
average flow-to-load ratio and the reference value of the flow-to-
load ratio at normal load.
R<INF>h</INF> = The hourly average flow-to-load ratio, for each flow 
rate recorded at a load level within <INF>#</INF> 10.0 percent of 
L<INF>avg</INF>.
R<INF>ref</INF> = The reference value of the flow-to-load ratio from 
the most recent normal-load flow RATA, determined in accordance with 
section 7.7 of appendix A to this part.

    (6) Equation B-2 shall be used in a consistent manner. That is, 
use R<INF>ref</INF> and R<INF>h</INF> if the flow-to-load ratio is 
being evaluated, and use (GHR)<INF>ref</INF> and (GHR)<INF>h</INF> 
if the gross heat rate is being evaluated. Finally, calculate 
E<INF>f</INF>, the arithmetic average of all of the hourly 
E<INF>h</INF> values. The owner or operator shall report the results 
of each quarterly flow-to-load (or gross heat rate) evaluation, as 
determined from Equation B-2, in the electronic quarterly report 
required under Sec. 75.64.
    (b) Acceptable results. The results of a quarterly flow-to-load 
(or gross heat rate) evaluation are acceptable, and no further 
action is required, if the calculated value of E<INF>f</INF> is less 
than or equal to: (1) 15.0 percent, if L<INF>avg</INF> for the most 
recent normal-load flow RATA is <gr-thn-eq>60 megawatts (or 
<gr-thn-eq>500 klb/hr of steam) and if unadjusted flow rates were 
used in the calculations; or (2) 10.0 percent, if L<INF>avg</INF> 
for the most recent normal-load flow RATA is <gr-thn-eq>60 megawatts 
(or <gr-thn-eq>500 klb/hr of steam) and if bias-adjusted flow rates 
were used in the calculations; or (3) 20.0 percent, if 
L<INF>avg</INF> for the most recent normal-load flow RATA is <60 
megawatts (or <500 klb/hr of steam) and if unadjusted flow rates 
were used in the calculations; or (4) 15.0 percent, if 
L<INF>avg</INF> for the most recent normal-load flow RATA is <60 
megawatts (or <500 klb/hr of steam) and if bias-adjusted flow rates 
were used in the calculations. If E<INF>f</INF> is above these 
limits, the owner or operator shall either: implement Option 1 in 
section 2.2.5.1 of this appendix; or perform a RATA in accordance 
with Option 2 in section 2.2.5.2 of this appendix; or re-examine the 
hourly data used for the flow-to-load or GHR analysis and 
recalculate E<INF>f</INF>, after excluding all non-representative 
hourly flow rates.
    (c) Recalculation of E<INF>f</INF>. If the owner or operator 
chooses to recalculate E<INF>f</INF>, the flow rates for the 
following hours are considered non-representative and may be 
excluded from the data analysis:
    (1) Any hour in which the type of fuel combusted was different 
from the fuel burned during the most recent normal-load RATA. For 
purposes of this determination, the type of fuel is different if the 
fuel is in a different state of matter (i.e., solid, liquid, or gas) 
than is the fuel burned during the RATA or if the fuel is a 
different classification of coal (e.g., bituminous versus sub-
bituminous);
    (2) For a unit that is equipped with an SO<INF>2</INF> scrubber 
and which always discharges its flue gases to the atmosphere through 
a single stack, any hour in which the SO<INF>2</INF> scrubber was 
bypassed;
    (3) Any hour in which ``ramping'' occurred, i.e., the hourly 
load differed by more than <plus-minus>15.0 percent from the load 
during the preceding hour or the subsequent hour;
    (4) For a unit with a multiple stack discharge configuration 
consisting of a main stack and a bypass stack, any hour in which the 
flue gases were discharged through both stacks;
    (5) If a normal-load flow RATA was performed and passed during 
the quarter being analyzed, any hour prior to completion of that 
RATA; and
    (6) If a problem with the accuracy of the flow monitor was 
discovered during the quarter and was corrected (as evidenced by 
passing the abbreviated flow-to-load test in section 2.2.5.3 of this 
appendix), any hour prior to completion of the abbreviated flow-to-
load test.
    (7) After identifying and excluding all non-representative 
hourly data in accordance with paragraphs (c)(1) through (6) of this 
section, the owner or operator may analyze the remaining data a 
second time. At least 168 representative hourly ratios or GHR values 
must be available to perform the analysis; otherwise, the flow-to-
load (or GHR) analysis is not required for that monitor for that 
calendar quarter.
    (8) If, after re-analyzing the data, E<INF>f</INF> meets the 
applicable limit in paragraph (b)(1), (b)(2), (b)(3), or (b)(4) of 
this section, no further action is required. If, however, 
E<INF>f</INF> is still above the applicable limit, the monitor shall 
be declared out-of-control, beginning with the first hour of the 
quarter following the quarter in which E<INF>f</INF> exceeded the 
applicable limit. The owner or operator shall then either implement 
Option 1 in section 2.2.5.1 of this appendix or Option 2 in section 
2.2.5.2 of this appendix.

2.2.5.1  Option 1

    Within two weeks of the end of the calendar quarter for which 
the E<INF>f</INF> value is above the applicable limit, investigate 
and troubleshoot the applicable flow monitor(s). Evaluate the 
results of each investigation as follows:
    (a) If the investigation fails to uncover a problem with the 
flow monitor, a RATA shall be performed in accordance with Option 2 
in section 2.2.5.2 of this appendix.
    (b) If a problem with the flow monitor is identified through the 
investigation (including the need to re-linearize the monitor by 
changing the polynomial coefficients or K factor(s)), corrective 
actions shall be taken. All corrective actions (e.g., non-routine 
maintenance, repairs, major component replacements, re-linearization 
of the monitor, etc.) shall be documented in the operation and 
maintenance records for the monitor. Data from the monitor shall 
remain invalid until a probationary calibration error test of the 
monitor is passed following completion of all corrective actions, at 
which point data from the monitor are conditionally valid. The owner 
or operator then either may complete the abbreviated flow-to-load 
test in section 2.2.5.3 of this appendix, or, if the corrective 
action taken has required relinearization of the flow monitor, shall 
perform a 3-level RATA.

2.2.5.2  Option 2

    Perform a single-load RATA (at a load designated as normal under 
section 6.5.2.1 of appendix A to this part) of each flow monitor for 
which E<INF>f</INF> is outside of the applicable limit. Data from 
the monitor remain invalid until the required RATA has been passed.

2.2.5.3  Abbreviated Flow-to-Load Test

    (a) The following abbreviated flow-to-load test may be performed 
after any documented repair, component replacement, or other 
corrective maintenance to a flow monitor (except for changes 
affecting the linearity of the flow monitor, such as adjusting the 
flow monitor coefficients or K factor(s)) to demonstrate that the 
repair, replacement, or other maintenance has not significantly 
affected the monitor's ability to accurately measure the stack gas 
volumetric flow rate. Data from the monitoring system are considered 
invalid from the hour of commencement of the repair, replacement, or 
maintenance until the hour in which a probationary calibration error 
test is passed following completion of the repair, replacement, or 
maintenance and any associated adjustments to the monitor. The 
abbreviated flow-to-load test shall be completed within 168 unit 
operating hours of the probationary calibration error test (or, for 
peaking units, within 30 unit operating days, if that is less 
restrictive). Data from the monitor are considered to be 
conditionally valid (as defined in Sec. 72.2 of this chapter), 
beginning with the hour of the probationary calibration error test.
    (b) Operate the unit(s) in such a way as to reproduce, as 
closely as practicable, the exact conditions at the time of the most 
recent normal-load flow RATA. To achieve this, it is recommended 
that the load be held constant to within <plus-minus>5.0 percent of 
the average load during the RATA and that the diluent gas 
(CO<INF>2</INF> or O<INF>2</INF>) concentration be maintained within 
<plus-minus>0.5 percent CO<INF>2</INF> or O<INF>2</INF> of the 
average diluent concentration during the RATA. For common stacks, to 
the extent practicable, use the same combination of units and load 
levels that were used during the RATA. When the process parameters 
have been set, record a minimum of six and a maximum of 12 
consecutive hourly average flow rates, using the flow monitor(s) for 
which E<INF>f</INF> was outside the applicable limit. For peaking 
units, a minimum of three and a maximum of 12 consecutive hourly 
average flow rates are required. Also record the corresponding 
hourly load values and, if applicable, the hourly diluent gas 
concentrations. Calculate the flow-to-load ratio (or GHR) for each 
hour in the test hour period, using Equation B-1 or B-1a. Determine 
E<INF>h</INF> for each hourly flow-

[[Page 28649]]

to-load ratio (or GHR), using Equation B-2 of this appendix and then 
calculate E<INF>f</INF>, the arithmetic average of the E<INF>h</INF> 
values.
    (c) The results of the abbreviated flow-to-load test shall be 
considered acceptable, and no further action is required if the 
value of E<INF>f</INF> does not exceed the applicable limit 
specified in section 2.2.5 of this appendix. All conditionally valid 
data recorded by the flow monitor shall be considered quality 
assured, beginning with the hour of the probationary calibration 
error test that preceded the abbreviated flow-to-load test. However, 
if E<INF>f</INF> is outside the applicable limit, all conditionally 
valid data recorded by the flow monitor shall be considered invalid 
back to the hour of the probationary calibration error test that 
preceded the abbreviated flow-to-load test, and a single-load RATA 
is required in accordance with section 2.2.5.2 of this appendix. If 
the flow monitor must be re-linearized, however, a 3-load RATA is 
required.

2.3  Semiannual and Annual Assessments

    For each primary and redundant backup monitoring system, perform 
relative accuracy assessments either semiannually or annually, as 
specified in section 2.3.1.1 or 2.3.1.2 of this appendix, for the 
type of test and the performance achieved. This requirement applies 
as of the calendar quarter following the calendar quarter in which 
the monitoring system is provisionally certified. A summary chart 
showing the frequency with which a relative accuracy test audit must 
be performed, depending on the accuracy achieved, is located at the 
end of this appendix in Figure 2.

2.3.1  Relative Accuracy Test Audit (RATA)

2.3.1.1  Standard RATA Frequencies

    (a) Except as otherwise specified in Sec. 75.21(a)(6) or (a)(7) 
or in section 2.3.1.2 of this appendix, perform relative accuracy 
test audits semiannually, i.e., once every two successive QA 
operating quarters (as defined in Sec. 72.2 of this chapter) for 
each primary and redundant backup SO<INF>2</INF> pollutant 
concentration monitor, flow monitor, CO<INF>2</INF> pollutant 
concentration monitor (including O<INF>2</INF> monitors used to 
determine CO<INF>2</INF> emissions), CO<INF>2</INF> or O<INF>2</INF> 
diluent monitor used to determine heat input, moisture monitoring 
system, NO_X concentration monitoring system, 
NO_X-diluent continuous emission monitoring system, or 
SO<INF>2</INF>-diluent continuous emission monitoring system. A 
calendar quarter that does not qualify as a QA operating quarter 
shall be excluded in determining the deadline for the next RATA. No 
more than eight successive calendar quarters shall elapse after the 
quarter in which a RATA was last performed without a subsequent RATA 
having been conducted. If a RATA has not been completed by the end 
of the eighth calendar quarter since the quarter of the last RATA, 
then the RATA must be completed within a 720 unit (or stack) 
operating hour grace period (as provided in section 2.3.3 of this 
appendix) following the end of the eighth successive elapsed 
calendar quarter, or data from the CEMS will become invalid.
    (b) The relative accuracy test audit frequency of a CEMS may be 
reduced, as specified in section 2.3.1.2 of this appendix, for primary 
or redundant backup monitoring systems which qualify for less frequent 
testing. Perform all required RATAs in accordance with the applicable 
procedures and provisions in sections 6.5 through 6.5.2.2 of appendix A 
to this part and sections 2.3.1.3 and 2.3.1.4 of this appendix.

2.3.1.2  Reduced RATA Frequencies

    Relative accuracy test audits of primary and redundant backup 
SO<INF>2</INF> pollutant concentration monitors, CO<INF>2</INF> 
pollutant concentration monitors (including O<INF>2</INF> monitors 
used to determine CO<INF>2</INF> emissions), CO<INF>2</INF> or 
O<INF>2</INF> diluent monitors used to determine heat input, 
moisture monitoring systems, NO_X concentration monitoring 
systems, flow monitors, NO_X-diluent monitoring systems or 
SO<INF>2</INF>-diluent monitoring systems may be performed annually 
(i.e., once every four successive QA operating quarters, rather than 
once every two successive QA operating quarters) if any of the 
following conditions are met for the specific monitoring system 
involved:
    (a) The relative accuracy during the audit of an SO<INF>2</INF> 
or CO<INF>2</INF> pollutant concentration monitor (including an 
O<INF>2</INF> pollutant monitor used to measure CO<INF>2</INF> using 
the procedures in appendix F to this part), or of a CO<INF>2</INF> 
or O<INF>2</INF> diluent monitor used to determine heat input, or of 
a NO_X concentration monitoring system, or of a 
NO_X-diluent monitoring system, or of an SO<INF>2</INF>-
diluent continuous emissions monitoring system is <ls-thn-eq> 7.5 
percent;
    (b) Prior to January 1, 2000, the relative accuracy during the 
audit of a flow monitor is <ls-thn-eq> 10.0 percent at each 
operating level tested;
    (c) On and after January 1, 2000, the relative accuracy during 
the audit of a flow monitor is <ls-thn-eq> 7.5 percent at each 
operating level tested;
    (d) For low flow (<ls-thn-eq> 10.0 fps) stacks/ducts, when the 
flow monitor fails to achieve a relative accuracy <ls-thn-eq> 7.5 
percent (10.0 percent if prior to January 1, 2000) during the audit, 
but the monitor mean value, calculated using Equation A-7 in 
appendix A to this part and converted back to an equivalent velocity 
in standard feet per second (fps), is within <plus-minus> 1.5 fps of 
the reference method mean value, converted to an equivalent velocity 
in fps;
    (e) For low SO<INF>2</INF> or NO_X emitting units 
(average SO<INF>2</INF> or NO_X concentrations <ls-thn-eq> 
250 ppm, when an SO<INF>2</INF> pollutant concentration monitor or 
NO_X concentration monitoring system fails to achieve a 
relative accuracy <ls-thn-eq> 7.5 percent during the audit, but the 
monitor mean value from the RATA is within <plus-minus> 12 ppm of 
the reference method mean value;
    (f) For units with low NO_X emission rates (average 
NO_X emission rate <ls-thn-eq> 0.200 lb/mmBtu), when a 
NO_X-diluent continuous emission monitoring system fails 
to achieve a relative accuracy <ls-thn-eq> 7.5 percent, but the 
monitoring system mean value from the RATA, calculated using 
Equation A-7 in appendix A to this part, is within <plus-minus> 
0.015 lb/mmBtu of the reference method mean value;
    (g) For units with low SO<INF>2</INF> emission rates (average 
SO<INF>2</INF> emission rate <ls-thn-eq> 0.500 lb/mmBtu), when an 
SO<INF>2</INF>-diluent continuous emission monitoring system fails 
to achieve a relative accuracy <ls-thn-eq> 7.5 percent, but the 
monitoring system mean value from the RATA, calculated using 
Equation A-7 in appendix A to this part, is within <plus-minus> 
0.025 lb/mmBtu of the reference method mean value;
    (h) For a CO<INF>2</INF> or O<INF>2</INF> monitor, when the mean 
difference between the reference method values from the RATA and the 
corresponding monitor values is within <plus-minus> 0.7 percent 
CO<INF>2</INF> or O<INF>2</INF>; and
    (i) When the relative accuracy of a continuous moisture 
monitoring system is <ls-thn-eq> 7.5 percent or when the mean 
difference between the reference method values from the RATA and the 
corresponding monitoring system values is within <plus-minus> 1.0 
percent H<INF>2</INF>O.
2.3.1.3  RATA Load Levels and Additional RATA Requirements
    (a) For SO<INF>2</INF> pollutant concentration monitors, 
CO<INF>2</INF> pollutant concentration monitors (including 
O<INF>2</INF> monitors used to determine CO<INF>2</INF> emissions), 
CO<INF>2</INF> or O<INF>2</INF> diluent monitors used to determine 
heat input, NO_X concentration monitoring systems, 
moisture monitoring systems, SO<INF>2</INF>-diluent monitoring 
systems and NO_X-diluent monitoring systems, the required 
semiannual or annual RATA tests shall be done at the load level 
designated as normal under section 6.5.2.1 of appendix A to this 
part. If two load levels are designated as normal, the required 
RATA(s) may be done at either load level.
    (b) For flow monitors installed on peaking units and bypass 
stacks, all required semiannual or annual relative accuracy test 
audits shall be single-load audits at the normal load, as defined in 
section 6.5.2.1 of appendix A to this part.
    (c) For all other flow monitors, the RATAs shall be performed as 
follows:
    (1) An annual 2-load flow RATA shall be done at the two most 
frequently used load levels, as determined under section 6.5.2.1 of 
appendix A to this part.
    (2) If the flow monitor is on a semiannual RATA frequency, 2-
load flow RATAs and single-load flow RATAs at normal load may be 
performed alternately.
    (3) A single-load annual flow RATA, at the most frequently used 
load level, may be performed in lieu of the 2-load RATA if the 
results of an historical load data analysis show that in the time 
period extending from the ending date of the last annual flow RATA 
to a date that is no more than 7 days prior to the date of the 
current annual flow RATA, the unit has operated at a single load 
level (low, mid or high) for <gr-thn-eq> 85.0 percent of the time. * 
* *
    (4) A 3-load RATA, at the low-, mid-, and high-load levels, 
determined under section 6.5.2.1 of appendix A to this part, shall 
be performed at least once in every period of five consecutive 
calendar years.
    (5) A 3-load RATA is required whenever a flow monitor is re-
linearized, i.e., when its polynomial coefficients or K factor(s) 
are changed.
    (6) For all multi-level flow audits, the audit points at 
adjacent load levels (e.g., mid and high) shall be separated by no 
less than 25.0 percent of the ``range of operation,'' as defined in 
section 6.5.2.1 of appendix A to this part.

[[Page 28650]]

    (d) A RATA of a moisture monitoring system shall be performed 
whenever the coefficient, K factor or mathematical algorithm 
determined under section 6.5.7 of appendix A to this part is 
changed.

2.3.1.4  Number of RATA Attempts

    The owner or operator may perform as many RATA attempts as are 
necessary to achieve the desired relative accuracy test audit 
frequencies and/or bias adjustment factors. However, the data 
validation procedures in section 2.3.2 of this appendix must be 
followed.

2.3.2  Data Validation

    (a) A RATA shall not commence if the monitoring system is 
operating out-of-control with respect to any of the daily and 
quarterly quality assurance assessments required by sections 2.1 and 
2.2 of this appendix or with respect to the additional calibration 
error test requirements in section 2.1.3 of this appendix.
    (b) Each required RATA shall be done according to paragraphs 
(b)(1), (b)(2) or (b)(3) of this section:
    (1) The RATA may be done ``cold,'' i.e., with no corrective 
maintenance, repair, calibration adjustments, re-linearization or 
reprogramming of the monitoring system prior to the test.
    (2) The RATA may be done after performing only the routine or 
non-routine calibration adjustments described in section 2.1.3 of 
this appendix at the zero and/or upscale calibration gas levels, but 
no other corrective maintenance, repair, re-linearization or 
reprogramming of the monitoring system. Trial RATA runs may be 
performed after the calibration adjustments and additional 
adjustments within the allowable limits in section 2.1.3 of this 
appendix may be made prior to the RATA, as necessary, to optimize 
the performance of the CEMS. The trial RATA runs need not be 
reported, provided that they meet the specification for trial RATA 
runs in Sec. 75.20(b)(3)(vii)(E)(2). However, if, for any trial run, 
the specification in Sec. 75.20(b)(3)(vii)(E)(2) is not met, the 
trial run shall be counted as an aborted RATA attempt.
    (3) The RATA may be done after repair, corrective maintenance, 
re-linearization or reprogramming of the monitoring system. In this 
case, the monitoring system shall be considered out-of-control from 
the hour in which the repair, corrective maintenance, re-
linearization or reprogramming is commenced until the RATA has been 
passed. Alternatively, the data validation procedures and associated 
timelines in Secs. 75.20(b)(3)(ii) through (ix) may be followed upon 
completion of the necessary repair, corrective maintenance, re-
linearization or reprogramming. If the procedures in 
Sec. 75.20(b)(3) are used, the words ``quality assurance'' apply 
instead of the word ``recertification.''
    (c) Once a RATA is commenced, the test must be done hands-off. 
No adjustment of the monitor's calibration is permitted during the 
RATA test period, other than the routine calibration adjustments 
following daily calibration error tests, as described in section 
2.1.3 of this appendix. For 2-level and 3-level flow monitor audits, 
no linearization or reprogramming of the monitor is permitted in 
between load levels.
    (d) For single-load RATAs, if a daily calibration error test is 
failed during a RATA test period, prior to completing the test, the 
RATA must be repeated. Data from the monitor are invalidated 
prospectively from the hour of the failed calibration error test 
until the hour of completion of a subsequent successful calibration 
error test. The subsequent RATA shall not be commenced until the 
monitor has successfully passed a calibration error test in 
accordance with section 2.1.3 of this appendix. For multiple-load 
flow RATAs, each load level is treated as a separate RATA (i.e., 
when a calibration error test is failed prior to completing the RATA 
at a particular load level, only the RATA at that load level must be 
repeated; the results of any previously-passed RATA(s) at the other 
load level(s) are unaffected, unless re-linearization of the monitor 
is required to correct the problem that caused the calibration 
failure, in which case a subsequent 3-load RATA is required).
    (e) If a RATA is failed (that is, if the relative accuracy 
exceeds the applicable specification in section 3.3 of appendix A to 
this part) or if the RATA is aborted prior to completion due to a 
problem with the CEMS, then the CEMS is out-of-control and all 
emission data from the CEMS are invalidated prospectively from the 
hour in which the RATA is failed or aborted. Data from the CEMS 
remain invalid until the hour of completion of a subsequent RATA 
that meets the applicable specification in section 3.3 of appendix A 
to this part, unless the option in paragraph (b)(3) of this section 
to use the data validation procedures and associated timelines in 
Secs. 75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in which 
case the beginning and end of the out-of-control period shall be 
determined in accordance with Sec. 75.20(b)(3)(vii)(A) and (B). Note 
that a monitoring system shall not be considered out-of-control when 
a RATA is aborted for a reason other than monitoring system 
malfunction (see paragraph (h) of this section).
    (f) For a 2-level or 3-level flow RATA, if, at any load level, a 
RATA is failed or aborted due to a problem with the flow monitor, 
the RATA at that load level must be repeated. The flow monitor is 
considered out-of-control and data from the monitor are invalidated 
from the hour in which the test is failed or aborted and remain 
invalid until the passing of a RATA at the failed load level, unless 
the option in paragraph (b)(3) of this section to use the data 
validation procedures and associated timelines in 
Sec. 75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in which 
case the beginning and end of the out-of-control period shall be 
determined in accordance with Sec. 75.20(b)(3)(vii)(A) and (B). Flow 
RATA(s) that were previously passed at the other load level(s) do 
not have to be repeated unless the flow monitor must be re-
linearized following the failed or aborted test. If the flow monitor 
is re-linearized, a subsequent 3-load RATA is required.
    (g) For a CO<INF>2</INF> pollutant concentration monitor (or an 
O<INF>2</INF> monitor used to measure CO<INF>2</INF> emissions) 
which also serves as the diluent component in a NO_X-
diluent (or SO<INF>2</INF>-diluent) monitoring system, if the 
CO<INF>2</INF> (or O<INF>2</INF>) RATA is failed, then both the 
CO<INF>2</INF> (or O<INF>2</INF>) monitor and the associated 
NO_X-diluent (or SO<INF>2</INF>-diluent) system are 
considered out-of-control, beginning with the hour of completion of 
the failed CO<INF>2</INF> (or O<INF>2</INF>) monitor RATA, and 
continuing until the hour of completion of subsequent hands-off 
RATAs which demonstrate that both systems have met the applicable 
relative accuracy specifications in sections 3.3.2 and 3.3.3 of 
appendix A to this part, unless the option in paragraph (b)(3) of 
this section to use the data validation procedures and associated 
timelines in Secs. 75.20(b)(3)(ii) through (b)(3)(ix) has been 
selected, in which case the beginning and end of the out-of-control 
period shall be determined in accordance with Secs. 75.20(b)(3)(vii) 
(A) and (B).
    (h) For each monitoring system, report the results of all 
completed and partial RATAs that affect data validation (i.e., all 
completed, passed RATAs; all completed, failed RATAs; and all RATAs 
aborted due to a problem with the CEMS, including trial RATA runs 
counted as failed test attempts under paragraph (b)(2) of this 
section or under Sec. 75.20(b)(3)(vii)(F)) in the quarterly report 
required under Sec. 75.64. Note that RATA attempts that are aborted 
or invalidated due to problems with the reference method or due to 
operational problems with the affected unit(s) need not be reported. 
Such runs do not affect the validation status of emission data 
recorded by the CEMS. However, a record of all RATAs, trial RATA 
runs and RATA attempts (whether reported or not) must be kept on-
site as part of the official test log for each monitoring system.
    (i) Each time that a hands-off RATA of an SO<INF>2</INF> 
pollutant concentration monitor, a NO_X-diluent monitoring 
system, a NO_X concentration monitoring system or a flow 
monitor is passed, perform a bias test in accordance with section 
7.6.4 of appendix A to this part. Apply the appropriate bias 
adjustment factor to the reported SO<INF>2</INF>, NO_X, or 
flow rate data, in accordance with section 7.6.5 of appendix A to 
this part.
    (j) Failure of the bias test does not result in the monitoring 
system being out-of-control.

2.3.3 RATA Grace Period

    (a) The owner or operator has a grace period of 720 consecutive 
unit operating hours, as defined in Sec. 72.2 of this chapter (or, 
for CEMS installed on common stacks or bypass stacks, 720 
consecutive stack operating hours, as defined in Sec. 72.2 of this 
chapter), in which to complete the required RATA for a particular 
CEMS whenever: a required RATA has not been performed by the end of 
the QA operating quarter in which it is due; or five consecutive 
calendar years have elapsed without a required 3-load flow RATA 
having been conducted; or for a unit which is conditionally exempted 
under Sec. 75.21(a)(7) from the SO<INF>2</INF> RATA requirements of 
this part, an SO<INF>2</INF> RATA has not been completed by the end 
of the calendar quarter in which the annual usage of fuel(s) with a 
sulfur content higher than very low sulfur fuel(as defined in 
Sec. 72.2 of this chapter) exceeds 480 hours; or eight

[[Page 28651]]

successive calendar quarters have elapsed, following the quarter in 
which a RATA was last performed, without a subsequent RATA having 
been done, due either to infrequent operation of the unit(s) or 
frequent combustion of very low sulfur fuel, as defined in Sec. 72.2 
of this chapter (SO<INF>2</INF> monitors, only), or a combination of 
these factors.
    (b) Except for SO<INF>2</INF> monitoring system RATAs, the grace 
period shall begin with the first unit (or stack) operating hour 
following the calendar quarter in which the required RATA was due. 
For SO<INF>2</INF> monitor RATAs, the grace period shall begin with 
the first unit (or stack) operating hour in which fuel with a total 
sulfur content higher than that of very low sulfur fuel (as defined 
in Sec. 72.2 of this chapter) is burned in the unit(s), following 
the quarter in which the required RATA is due. Data validation 
during a RATA grace period shall be done in accordance with the 
applicable provisions in section 2.3.2 of this appendix.
    (c) If, at the end of the 720 unit (or stack) operating hour 
grace period, the RATA has not been completed, data from the 
monitoring system shall be invalid, beginning with the first unit 
operating hour following the expiration of the grace period. Data 
from the CEMS remain invalid until the hour of completion of a 
subsequent hands-off RATA. Note that when a RATA (or RATAs, if more 
than one attempt is made) is done during a grace period in order to 
satisfy a RATA requirement from a previous quarter, the deadline for 
the next RATA shall be determined from the quarter in which the RATA 
was due, not from the quarter in which the RATA is actually 
completed. However, if a RATA deadline determined in this manner is 
less than two QA operating quarters from the quarter in which the 
missed RATA is completed , the RATA deadline shall be re-set at two 
QA operating quarters from the quarter in which the missed RATA is 
completed .

2.3.4  Bias Adjustment Factor

    Except as otherwise specified in section 7.6.5 of appendix A to 
this part, if an SO<INF>2</INF> pollutant concentration monitor, 
flow monitor, NO_X continuous emission monitoring system, 
or NO_X concentration monitoring system used to calculate 
NO_X mass emissions fails the bias test specified in 
section 7.6 of appendix A to this part, use the bias adjustment 
factor given in Equations A-11 and A-12 of appendix A to this part 
to adjust the monitored data.

2.4  Recertification, Quality Assurance, RATA Frequency and Bias 
Adjustment Factors (Special Considerations)

    (a) When a significant change is made to a monitoring system 
such that recertification of the monitoring system is required in 
accordance with Sec. 75.20(b), a recertification test (or tests) 
must be performed to ensure that the CEMS continues to generate 
valid data. In all recertifications, a RATA will be one of the 
required tests; for some recertifications, other tests will also be 
required. A recertification test may be used to satisfy the quality 
assurance test requirement of this appendix. For example, if, for a 
particular change made to a CEMS, one of the required 
recertification tests is a linearity check and the linearity check 
is successful, then, unless another such recertification event 
occurs in that same QA operating quarter, it would not be necessary 
to perform an additional linearity test of the CEMS in that quarter 
to meet the quality assurance requirement of section 2.2.1 of this 
appendix. For this reason, EPA recommends that owners or operators 
coordinate component replacements, system upgrades, and other events 
that may require recertification, to the extent practicable, with 
the periodic quality assurance testing required by this appendix. 
When a quality assurance test is done for the dual purpose of 
recertification and routine quality assurance, the applicable data 
validation procedures in Sec. 75.20(b)(3) shall be followed.
    (b) Except as provided in section 2.3.3 of this appendix, 
whenever a passing RATA of a gas monitor or a passing 2-load or 3-
load RATA of a flow monitor is performed (irrespective of whether 
the RATA is done to satisfy a recertification requirement or to meet 
the quality assurance requirements of this appendix, or both), the 
RATA frequency (semi-annual or annual) shall be established based 
upon the date and time of completion of the RATA and the relative 
accuracy percentage obtained. For 2-load and 3-load flow RATAs, use 
the highest percentage relative accuracy at any of the loads to 
determine the RATA frequency. The results of a single-load flow RATA 
may be used to establish the RATA frequency when the single-load 
flow RATA is specifically required under section 2.3.1.3(b) of this 
appendix (for flow monitors installed on peaking units and bypass 
stacks) or when the single-load RATA is allowed under section 
2.3.1.3(c) of this appendix for a unit that has operated at the most 
frequently used load level for <gr-thn-eq>85.0 percent of the time 
since the last annual flow RATA. No other single-load flow RATA may 
be used to establish an annual RATA frequency; however, a 2-load or 
3-load flow RATA may be performed at any time or in place of any 
required single-load RATA, in order to establish an annual RATA 
frequency.

2.5  Other Audits

* * * * *

                     Figure 1 to Appendix B of Part 75--Quality Assurance Test Requirements.
----------------------------------------------------------------------------------------------------------------
                                                                         QA test frequency requirements
                             Test                             --------------------------------------------------
                                                                    Daily*         Quarterly*      Semiannual*
----------------------------------------------------------------------------------------------------------------
Calibration Error (2 pt.)....................................  ...............  ...............  ...............
Interference (flow)..........................................  ...............  ...............  ...............
Flow-to-Load Ratio...........................................  ...............  ...............  ...............
Leak Check (DP flow monitors)................................  ...............  ...............  ...............
Linearity (3 pt.)............................................  ...............  ...............  ...............
RATA (SO<INF>2</INF>, NO_X, CO<INF>2</INF>, H<INF>2</INF>O)¹...................................  ...............  ...............  ...............
RATA (flow)^1,2...............................................  ...............  ...............  ...............
----------------------------------------------------------------------------------------------------------------
-For monitors on bypass stack/duct, ``daily'' means bypass operating days, only. ``Quarterly'' means once every
  QA operating quarter. ``Semiannual'' means once every two QA operating quarters.
\1\ Conduct RATA annually (i.e., once every four QA operating quarters), if monitor meets accuracy requirements
  to qualify for less frequent testing.
\2\ For flow monitors installed on peaking units and bypass stacks, conduct all RATAs at a single, normal load.
  For other flow monitors, conduct annual RATAs at the two load levels used most frequently since the last
  annual RATA. Alternating single-load and 2-load RATAs may be done if a monitor is on a semiannual frequency. A
  single-load RATA may be done in lieu of a 2-load RATA if, since the last annual flow RATA, the unit has
  operated at one load level for <gr-thn-eq>85.0 percent of the time. A 3-load RATA is required at least once in
  every period of five consecutive calendar years and whenever a flitor is re-linearized.


             Figure 2 to Appendix B of Part 75--Relative Accuracy Test Frequency Incentive System .
----------------------------------------------------------------------------------------------------------------
            RATA                       Semiannual ¹ (percent)                           Annual ¹
----------------------------------------------------------------------------------------------------------------
SO<INF>2</INF> or NO<INF>X^</INF>3.................  7.5% <RA <ls-thn-eq> 10.0% or <plus-      RA <ls-thn-eq> 7.5% or <plus-minus> 12.0
                               minus> 15.0 ppm².                         ppm²
SO<INF>2</INF>-diluent.................  7.5% < RA <ls-thn-eq> 10.0% or <plus-     RA <ls-thn-eq> 7.5% or <plus-minus>
                               minus> 0.030.                             0.025.
                              lb/mmBtu ²..............................  lb/mmBtu ²
NO_X-diluent.................  7.5% < RA <ls-thn-eq> 10.0% or <plus-     RA <ls-thn-eq> 7.5% or <plus-minus>
                               minus> 0.020.                             0.015.

[[Page 28652]]


                              lb/mmBtu ²..............................  lb/mmBtu ².
Flow (Phase I)..............  10.0% < RA <ls-thn-eq> 15.0% or <plus-    RA <ls-thn-eq> 10.0%.
                               minus> 1.5 fps ².
Flow (Phase II).............  7.5% < RA <ls-thn-eq> 10.0% or <plus-     RA <ls-thn-eq> 7.5%.
                               minus> 1.5 fps ².
CO<INF>2</INF> or O<INF>2</INF>...................  7.5% < RA <ls-thn-eq> 10.0% or <plus-     RA <ls-thn-eq> 7.5% or <plus-minus> 0.7%
                               minus> 1.0% CO<INF>2</INF>/O<INF>2^</INF>2.                      CO<INF>2</INF>/O<INF>2^</INF>2.
Moisture....................  7.5% < RA <ls-thn-eq> 10.0% or <plus-     RA <ls-thn-eq> 7.5% or <plus-minus> 1.0%
                               minus> 1.5% H<INF>2</INF>O<INF>2</INF>.                         H<INF>2</INF>O².
----------------------------------------------------------------------------------------------------------------
\1\ The deadline for the next RATA is the end of the second (if semiannual) or fourth (if annual) successive QA
  operating quarter following the quarter in which the CEMS was last tested. Exclude calendar quarters with
  fewer than 168 unit operating hours (or, for common stacks and bypass stacks, exclude quarters with fewer than
  168 stack operating hours) in determining the RATA deadline. For SO<INF>2</INF> monitors, QA operating quarters in which
  only very low sulfur fuel as defined in Sec.  72.2, is combusted may also be excluded. However, the exclusion
  of calendar quarters is limited as follows: the deadline for the next RATA shall be no more than 8 calendar
  quarters after the quarter in which a RATA was last performed.
\2\ The difference between monitor and reference method mean values applies to moisture monitors, CO<INF>2</INF>, and O<INF>2</INF>
  monitors, low emitters, or low flow, only.
\3\ A NO_X concentration monitoring system used to determine NO<INF>2</INF> mass emissions under Sec.  75.71.

Appendix C To Part 75--Missing Data Statistical Estimation Procedures

    62.-63. Appendix C to part 75 is amended by revising sections 
2.1, 2.2.1, 2.2.2, 2.2.3, and 2.2.5, and by revising section 2.2.3.9 
to read as follows:

2. Load-Based Procedure for Missing Flow Rate and NO_X 
Emission Rate Data

2.1  Applicability

    This procedure is applicable for data from all affected units 
for use in accordance with the provisions of this part to provide 
substitute data for volumetric flow rate (scfh), NO_X 
emission rate (in lb/mmBtu) from NO_X-diluent continuous 
emission monitoring systems, and NO_X concentration data 
(in ppm) from NOx concentration monitoring systems used to determine 
NO_X mass emissions.
    2.2 * * *
    2.2.1  For a single unit, establish ten operating load ranges 
defined in terms of percent of the maximum hourly average gross load 
of the unit, in gross megawatts (MWge), as shown in Table C-1. (Do 
not use integrated hourly gross load in MW-hr.) For units sharing a 
common stack monitored with a single flow monitor, the load ranges 
for flow (but not for NO_X) may be broken down into 20 
operating load ranges in increments of 5.0 percent of the combined 
maximum hourly average gross load of all units utilizing the common 
stack. If this option is selected, the twentieth (uppermost) 
operating load range shall include all values greater than 95.0 
percent of the maximum hourly average gross load. For a cogenerating 
unit or other unit at which some portion of the heat input is not 
used to produce electricity or for a unit for which hourly average 
gross load in MWge is not recorded separately, use the hourly gross 
steam load of the unit, in pounds of steam per hour at the measured 
temperature ( deg.F) and pressure (psia) instead of MWge. Indicate a 
change in the number of load ranges or the units of loads to be used 
in the precertification section of the monitoring plan.

     Table C-1.--Definition of Operating Load Ranges for Load-based
                      Substitution Data Procedures
------------------------------------------------------------------------
                                                             Percent of
                                                               maximum
                                                            hourly gross
                                                               load or
                   Operating load range                        maximum
                                                            hourly gross
                                                             steam load
                                                              (percent)
------------------------------------------------------------------------
1.........................................................       0-10
2.........................................................     >10-20
3.........................................................     >20-30
4.........................................................     >30-40
5.........................................................     >40-50
6.........................................................     >50-60
7.........................................................     >60-70
8.........................................................     >70-80
9.........................................................     >80-90
10........................................................        >90
------------------------------------------------------------------------

    2.2.2  Beginning with the first hour of unit operation after 
installation and certification of the flow monitor or the 
NO_X-diluent continuous emission monitoring system (or a 
NO_X concentration monitoring system used to determine 
NO_X mass emissions, as defined in Sec. 75.71(a)(2)), for 
each hour of unit operation record a number, 1 through 10, (or 1 
through 20 for flow at common stacks) that identifies the operating 
load range corresponding to the integrated hourly gross load of the 
unit(s) recorded for each unit operating hour.
    2.2.3  Beginning with the first hour of unit operation after 
installation and certification of the flow monitor or the 
NO_X-diluent continuous emission monitoring system (or a 
NO_X concentration monitoring system used to determine 
NO_X mass emissions, as defined in Sec. 75.71(a)(2)) and 
continuing thereafter, the data acquisition and handling system must 
be capable of calculating and recording the following information 
for each unit operating hour of missing flow or NO_X data 
within each identified load range during the shorter of: (a) the 
previous 2,160 quality assured monitor operating hours (on a rolling 
basis), or (b) all previous quality assured monitor operating hours.
* * * * *
    2.2.3.9  Average of the hourly NO_X pollutant 
concentrations, in ppm, reported by a NO_X concentration 
monitoring system used to determine NO_X mass emissions, 
as defined in Sec. 75.71(a)(2).
* * * * *
    2.2.5  When a bias adjustment is necessary for the flow monitor 
and/or the NO_X-diluent continuous emission monitoring 
system (and/or the NO_X concentration monitoring system 
used to determine NO_X mass emissions, as defined in 
Sec. 75.71(a)(2)), apply the adjustment factor to all monitor or 
continuous emission monitoring system data values placed in the load 
ranges.
* * * * *

Appendix D To Part 75--Optional SO<INF>2</INF> Emissions Data Protocol 
for Gas-Fired and Oil-Fired Units

    64. Appendix D to part 75 is amended by revising section 1.1 to 
read as follows:

1. Applicability

    1.1  This protocol may be used in lieu of continuous 
SO<INF>2</INF> pollutant concentration and flow monitors for the 
purpose of determining hourly SO<INF>2</INF> mass emissions and heat 
input from: gas-fired units, as defined in Sec. 72.2 of this 
chapter, or oil-fired units, as defined in Sec. 72.2 of this 
chapter. Section 2.1 of this appendix provides procedures for 
measuring oil or gaseous fuel flow using a fuel flowmeter, section 
2.2 of this appendix provides procedures for conducting oil sampling 
and analysis to determine sulfur content and gross calorific value 
(GCV) of fuel oil, and section 2.3 of this appendix provides 
procedures for determining the sulfur content and GCV of gaseous 
fuels.
* * * * *
    65. Appendix D to part 75 is further amended by:
    a. Revising sections 2.1 and 2.1.1;
    b. Addding sections 2.1.1.1 through 2.1.1.3;
    c. Revising sections 2.1.2 through 2.1.4;
    d. Adding sections 2.1.4.1 through 2.1.4.3;
    e. Revising sections 2.1.5 through 2.1.5.2;
    f. Adding sections 2.1.5.3 through 2.1.5.4;
    g. Revising sections 2.1.6 through 2.1.6.2;
    h. Adding sections 2.1.6.3 through 2.1.7.5;
    i. Revising sections 2.2 and 2.2.1;
    j. Removing sections 2.2.1.1 and 2.2.1.2;
    k. Removing and reserving section 2.2.2;
    l. Revising sections 2.2.3 and 2.2.4;
    m. Adding sections 2.2.4.1 through 2.2.4.3;

[[Page 28653]]

    n. Revising the first sentence of section 2.2.6;
    o. Revising sections 2.2.8 and 2.3 through 2.3.2.1;
    p. Adding sections 2.3.2.1.1 and 2.3.2.1.2;
    q. Revising section 2.3.2.2;
    r. Adding sections 2.3.2.3 through 2.3.6;
    s. Revising section 2.4.1;
    t. Removing section 2.4.2, and redesignating sections 2.4.3, 
2.4.3.1, 2.4.3.2, 2.4.3.3 and 2.4.4 as sections 2.4.2, 2.4.2.1, 
2.4.2.2, 2.4.2.3 and 2.4.3, respectively; and
    u. Revising newly redesignated sections 2.4.2, 2.4.2.1, and 
2.4.2.3 to read as follows:

2. Procedure

2.1  Fuel Flowmeter Measurements

    For each hour when the unit is combusting fuel, measure and 
record the flow rate of fuel combusted by the unit, except as 
provided in section 2.1.4 of this appendix. Measure the flow rate of 
fuel with an in-line fuel flowmeter, and automatically record the 
data with a data acquisition and handling system, except as provided 
in section 2.1.4 of this appendix.
    2.1.1  Measure the flow rate of each fuel entering and being 
combusted by the unit. If, on an annual basis, more than 5.0 percent 
of the fuel from the main pipe is diverted from the unit without 
being burned and that diversion occurs downstream of the fuel 
flowmeter, an additional in-line fuel flowmeter is required to 
account for the unburned fuel. In this case, record the flow rate of 
each fuel combusted by the unit as the difference between the flow 
measured in the pipe leading to the unit and the flow in the pipe 
diverting fuel away from the unit. However, the additional fuel 
flowmeter is not required if, on an annual basis, the total amount 
of fuel diverted away from the unit, expressed as a percentage of 
the total annual fuel usage by the unit is demonstrated to be less 
than or equal to 5.0 percent. The owner or operator may make this 
demonstration in the following manner:
    2.1.1.1  For existing units with fuel usage data from fuel 
flowmeters, if data are submitted from a previous year demonstrating 
that the total diverted yearly fuel does not exceed 5% of the total 
fuel used; or
    2.1.1.2  For new units which do not have historical data, if a 
letter is submitted signed by the designated representative 
certifying that, in the future, the diverted fuel will not exceed 
5.0% of the total annual fuel usage ; or
    2.1.1.3  By using a method approved by the Administrator under 
Sec. 75.66(d).
    2.1.2  Install and use fuel flowmeters meeting the requirements 
of this appendix in a pipe going to each unit, or install and use a 
fuel flowmeter in a common pipe header (i.e., a pipe carrying fuel 
for multiple units). However, the use of a fuel flowmeter in a 
common pipe header and the provisions of sections 2.1.2.1 and 
2.1.2.2 of this appendix are not applicable to any unit that is 
using the provisions of subpart H of this part to monitor, record, 
and report NO_X mass emissions under a state or federal 
NO_X mass emission reduction program. For all other units, 
if the fuel flowmeter is installed in a common pipe header, do one 
of the following:
    2.1.2.1  Measure the fuel flow rate in the common pipe, and 
combine SO<INF>2</INF> mass emissions for the affected units for 
recordkeeping and compliance purposes; or
    2.1.2.2  Provide information satisfactory to the Administrator 
on methods for apportioning SO<INF>2</INF> mass emissions and heat 
input to each of the affected units demonstrating that the method 
ensures complete and accurate accounting of the actual emissions 
from each of the affected units included in the apportionment and 
all emissions regulated under this part. The information shall be 
provided to the Administrator through a petition submitted by the 
designated representative under Sec. 75.66. Satisfactory information 
includes: the proposed apportionment, using fuel flow measurements; 
the ratio of hourly integrated gross load (in MWe-hr) in each unit 
to the total load for all units receiving fuel from the common pipe 
header, or the ratio of hourly steam flow (in 1000 lb) at each unit 
to the total steam flow for all units receiving fuel from the common 
pipe header (see section 3.4.3 of this appendix); and documentation 
that shows the provisions of sections 2.1.5 and 2.1.6 of this 
appendix have been met for the fuel flowmeter used in the 
apportionment.
    2.1.3  For a gas-fired unit or an oil-fired unit that 
continuously or frequently combusts a supplemental fuel for flame 
stabilization or safety purposes, measure the flow rate of the 
supplemental fuel with a fuel flowmeter meeting the requirements of 
this appendix.

2.1.4  Situations in Which Certified Flowmeter is Not Required

2.1.4.1  Start-up or Ignition Fuel

    For an oil-fired unit that uses gas solely for start-up or 
burner ignition or a gas-fired unit that uses oil solely for start-
up or burner ignition, a flowmeter for the start-up fuel is not 
required. Estimate the volume of oil combusted for each start-up or 
ignition either by using a fuel flowmeter or by using the dimensions 
of the storage container and measuring the depth of the fuel in the 
storage container before and after each start-up or ignition. A fuel 
flowmeter used solely for start-up or ignition fuel is not subject 
to the calibration requirements of sections 2.1.5 and 2.1.6 of this 
appendix. Gas combusted solely for start-up or burner ignition does 
not need to be measured separately.

2.1.4.2  Gas or Oil Flowmeter Used for Commercial Billing

    A gas or oil flowmeter used for commercial billing of natural 
gas or oil may be used to measure, record, and report hourly fuel 
flow rate. A gas or oil flowmeter used for commercial billing of 
natural gas or oil is not required to meet the certification 
requirements of section 2.1.5 of this appendix or the quality 
assurance requirements of section 2.1.6 of this appendix under the 
following circumstances:
    (a) The gas or oil flowmeter is used for commercial billing 
under a contract, provided that the company providing the gas or oil 
under the contract and each unit combusting the gas or oil do not 
have any common owners and are not owned by subsidiaries or 
affiliates of the same company;
    (b) The designated representative reports hourly records of gas 
or oil flow rate, heat input rate, and emissions due to combustion 
of natural gas or oil;
    (c) The designated representative also reports hourly records of 
heat input rate for each unit, if the gas or oil flowmeter is on a 
common pipe header, consistent with section 2.1.2 of this appendix;
    (d) The designated representative reports hourly records 
directly from the gas or oil flowmeter used for commercial billing 
if these records are the values used, without adjustment, for 
commercial billing, or reports hourly records using the missing data 
procedures of section 2.4 of this appendix if these records are not 
the values used, without adjustment, for commercial billing; and
    (e) The designated representative identifies the gas or oil 
flowmeter in the unit's monitoring plan.

2.1.4.3 Emergency Fuel

    The designated representative of a unit that is restricted by 
its Federal, State or local permit to combusting a particular fuel 
only during emergencies where the primary fuel is not available is 
exempt from certifying a fuel flowmeter for use during combustion of 
the emergency fuel. During any hour in which the emergency fuel is 
combusted, report the hourly heat input to be the maximum rated heat 
input of the unit for the fuel. Additionally, begin sampling the 
emergency fuel for sulfur content only using the procedures under 
section 2.2 (for oil) or 2.3 (for gas) of this appendix. The 
designated representative shall also provide notice under 
Sec. 75.61(a)(6)(ii) for each period when the emergency fuel is 
combusted.

2.1.5  Initial Certification Requirement for all Fuel Flowmeters

    For the purposes of initial certification, each fuel flowmeter 
used to meet the requirements of this protocol shall meet a 
flowmeter accuracy of 2.0 percent of the upper range value (i.e. 
maximum calibrated fuel flow rate) across the range of fuel flow 
rate to be measured at the unit. Flowmeter accuracy may be 
determined under section 2.1.5.1 of this appendix for initial 
certification in any of the following ways (as applicable): by 
design or by measurement under laboratory conditions; by the 
manufacturer; by an independent laboratory; or by the owner or 
operator. Flowmeter accuracy may also be determined under section 
2.1.5.2 of this appendix by measurement against a NIST traceable 
reference method.
    2.1.5.1  Use the procedures in the following standards to verify 
flowmeter accuracy or design, as appropriate to the type of 
flowmeter: ASME MFC-3M-1989 with September 1990 Errata 
(``Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and 
Venturi''); ASME MFC-4M-1986 (Reaffirmed 1990), ``Measurement of Gas 
Flow by Turbine Meters;'' American Gas Association Report No. 3, 
``Orifice Metering of Natural Gas and Other Related Hydrocarbon 
Fluids Part 1: General Equations and Uncertainty Guidelines''

[[Page 28654]]

(October 1990 Edition), Part 2: ``Specification and Installation 
Requirements'' (February 1991 Edition), and Part 3: ``Natural Gas 
Applications'' (August 1992 edition) (excluding the modified flow-
calculation method in part 3); Section 8, Calibration from American 
Gas Association Transmission Measurement Committee Report No. 7: 
Measurement of Gas by Turbine Meters (Second Revision, April, 1996); 
ASME MFC-5M-1985 (``Measurement of Liquid Flow in Closed Conduits 
Using Transit-Time Ultrasonic Flowmeters''); ASME MFC-6M-1987 with 
June 1987 Errata (``Measurement of Fluid Flow in Pipes Using Vortex 
Flow Meters''); ASME MFC-7M-1987 (Reaffirmed 1992), ``Measurement of 
Gas Flow by Means of Critical Flow Venturi Nozzles;'' ISO 8316: 
1987(E) ``Measurement of Liquid Flow in Closed Conduits--Method by 
Collection of the Liquid in a Volumetric Tank;'' American Petroleum 
Institute (API) Section 2, ``Conventional Pipe Provers'', Section 3, 
``Small Volume Provers'', and Section 5, ``Master-Meter Provers'', 
from Chapter 4 of the Manual of Petroleum Measurement Standards, 
October 1988 (Reaffirmed 1993); or ASME MFC-9M-1988 with December 
1989 Errata (``Measurement of Liquid Flow in Closed Conduits by 
Weighing Method''), for all other flowmeter types (incorporated by 
reference under Sec. 75.6). The Administrator may also approve other 
procedures that use equipment traceable to National Institute of 
Standards and Technology standards. Document such procedures, the 
equipment used, and the accuracy of the procedures in the monitoring 
plan for the unit, and submit a petition signed by the designated 
representative under Sec. 75.66(c). If the flowmeter accuracy 
exceeds 2.0 percent of the upper range value, the flowmeter does not 
qualify for use under this part.
    2.1.5.2  (a) Alternatively, determine the flowmeter accuracy of 
a fuel flowmeter used for the purposes of this part by comparing it 
to the measured flow from a reference flowmeter which has been 
either designed according to the specifications of American Gas 
Association Report No. 3 or ASME MFC-3M-1989, as cited in section 
2.1.5.1 of this appendix, or tested for accuracy during the previous 
365 days, using a standard listed in section 2.1.5.1 of this 
appendix or other procedure approved by the Administrator under 
Sec. 75.66 (all standards incorporated by reference under 
Sec. 75.6). Any secondary elements, such as pressure and temperature 
transmitters, must be calibrated immediately prior to the 
comparison. Perform the comparison over a period of no more than 
seven consecutive unit operating days. Compare the average of three 
fuel flow rate readings over 20 minutes or longer for each meter at 
each of three different flow rate levels. The three flow rate levels 
shall correspond to:
    (1) Normal full unit operating load,
    (2) Normal minimum unit operating load,
    (3) A load point approximately equally spaced between the full 
and minimum unit operating loads, and
    (4) Calculate the flowmeter accuracy at each of the three flow 
levels using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.012

Where:
ACC=Flowmeter accuracy at a particular load level, as a percentage 
of the upper range value.
R=Average of the three flow measurements of the reference flowmeter.
A=Average of the three measurements of the flowmeter being tested.
URV=Upper range value of fuel flowmeter being tested (i.e. maximum 
measurable flow).
    (c) Notwithstanding the requirement for calibration of the 
reference flowmeter within 365 days prior to an accuracy test, when 
an in-place reference meter or prover is used for quality assurance 
under section 2.1.6 of this appendix, the reference meter 
calibration requirement may be waived if, during the previous in-
place accuracy test with that reference meter, the reference 
flowmeter and the flowmeter being tested agreed to within 
<plus-minus>1.0 percent of each other at all levels tested. This 
exception to calibration and flowmeter accuracy testing requirements 
for the reference flowmeter shall apply for periods of no longer 
than five consecutive years (i.e., 20 consecutive calendar 
quarters).
    2.1.5.3  If the flowmeter accuracy exceeds the specification in 
section 2.1.5 of this appendix, the flowmeter does not qualify for 
use for this appendix. Either recalibrate the flowmeter until the 
flowmeter accuracy is within the performance specification, or 
replace the flowmeter with another one that is demonstrated to meet 
the performance specification. Substitute for fuel flow rate using 
the missing data procedures in section 2.4.2 of this appendix until 
quality assured fuel flow data become available.
    2.1.5.4  For purposes of initial certification, when a flowmeter 
is tested against a reference fuel flow rate (i.e., fuel flow rate 
from another fuel flowmeter under section 2.1.5.2 of this appendix 
or flow rate from a procedure performed according to a standard 
incorporated by reference under section 2.1.5.1 of this appendix), 
report the results of flowmeter accuracy tests using the following 
Table D-1.

             Table D-1.--Table of Flowmeter Accuracy Results
------------------------------------------------------------------------

-------------------------------------------------------------------------
Test number:________ Test completion date \1\:____________________ Test
 completion time \1\:____________
Reinstallation date \2\ (for testing under 2.1.5.1
 only):____________________ Reinstallation time \2\:____________
Unit or pipe ID:            Component/System ID:
Flowmeter serial number:            Upper range value:
Units of measure for flowmeter and reference flow readings:
------------------------------------------------------------------------



                                                                                                       Percent
                                                              Time of run   Candidate    Reference     accuracy
 Measurement level (percent of URV)          Run No.             (HHMM)     flowmeter       flow     (percent of
                                                                             reading      reading        URV)
----------------------------------------------------------------------------------------------------------------
Low (Minimum) level................  1                        ...........  ...........  ...........  ...........
____ percent \3\ of URV............  2                        ...........  ...........  ...........  ...........
                                     3                        ...........  ...........  ...........  ...........
                                     Average                  ...........  ...........  ...........  ...........
Mid-level..........................  1                        ...........  ...........  ...........  ...........
____ percent \3\ of URV............  2                        ...........  ...........  ...........  ...........
                                     3                        ...........  ...........  ...........  ...........
                                     Average                  ...........  ...........  ...........  ...........
High (Maximum) level...............  1                        ...........  ...........  ...........  ...........
____ percent \3\ of URV............  2                        ...........  ...........  ...........  ...........
                                     3                        ...........  ...........  ...........  ...........
                                     Average                  ...........  ...........  ...........  ...........
----------------------------------------------------------------------------------------------------------------
\1\ Report the date, hour, and minute that all test runs were completed.
\2\ For laboratory tests not performed inline, report the date and hour that the fuel flowmeter was reinstalled
  following the test.
\3\ It is required to test at least at three different levels: (1) normal full unit operating load, (2) normal
  minimum unit operating load, and (3) a load point approximately equally spaced between the full and minimum
  unit operating loads.


[[Page 28655]]

2.1.6   Quality Assurance

    (a) Test the accuracy of each fuel flowmeter prior to use under 
this part and at least once every four fuel flowmeter QA operating 
quarters, as defined in Sec. 72.2 of this chapter, thereafter. 
Notwithstanding these requirements, no more than 20 successive 
calendar quarters shall elapse after the quarter in which a fuel 
flowmeter was last tested for accuracy without a subsequent 
flowmeter accuracy test having been conducted. Test the flowmeter 
accuracy more frequently if required by manufacturer specifications.
    (b) Except for orifice-, nozzle-, and venturi-type flowmeters, 
perform the required flowmeter accuracy testing using the procedures 
in either section 2.1.5.1 or section 2.1.5.2 of this appendix. Each 
fuel flowmeter must meet the accuracy specification in section 2.1.5 
of this appendix.
    (c) For orifice-, nozzle-, and venturi-type flowmeters, either 
perform the required flowmeter accuracy testing using the procedures 
in section 2.1.5.1 or 2.1.5.2 of this appendix or perform a 
transmitter accuracy test once every four fuel flowmeter QA 
operating quarters and a primary element visual inspection once 
every 12 calendar quarters, according to the procedures in sections 
2.1.6.1 through 2.1.6.4 of this appendix for periodic quality 
assurance.
    (d) Notwithstanding the requirements of this section, if the 
procedures of section 2.1.7 (fuel flow-to-load test) of this 
appendix are performed during each fuel flowmeter QA operating 
quarter, subsequent to a required flowmeter accuracy test or 
transmitter accuracy test and primary element inspection, where 
applicable, those procedures may be used to meet the requirement for 
periodic quality assurance testing for a period of up to 20 calendar 
quarters from the previous accuracy test or transmitter accuracy 
test and primary element inspection, where applicable.

2.1.6.1  Transmitter or Transducer Accuracy Test for Orifice-, Nozzle-, 
and Venturi-Type Flowmeters

    (a) Calibrate the differential pressure transmitter or 
transducer, static pressure transmitter or transducer, and 
temperature transmitter or transducer, as applicable, using 
equipment that has a current certificate of traceability to NIST 
standards. Check the calibration of each transmitter or transducer 
by comparing its readings to that of the NIST traceable equipment at 
least once at each of the following levels: the zero-level and at 
least two other levels (e.g., ``mid'' and ``high''), such that the 
full range of transmitter or transducer readings corresponding to 
normal unit operation is represented.
    (b) Calculate the accuracy of each transmitter or transducer at 
each level tested, using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.013

Where:

ACC = Accuracy of the transmitter or transducer as a percentage of 
full-scale.
R = Reading of the NIST traceable reference value (in milliamperes, 
inches of water, psi, or degrees).
T = Reading of the transmitter or transducer being tested (in 
milliamperes, inches of water, psi, or degrees, consistent with the 
units of measure of the NIST traceable reference value).
FS = Full-scale range of the transmitter or transducer being tested 
(in milliamperes, inches of water, psi, or degrees, consistent with 
the units of measure of the NIST traceable reference value).

    (c) If each transmitter or transducer meets an accuracy of 
<plus-minus> 1.0 percent of its full-scale range at each level 
tested, the fuel flowmeter accuracy of 2.0 percent is considered to 
be met at all levels. If, however, one or more of the transmitters 
or transducers does not meet an accuracy of <plus-minus> 1.0 percent 
of full-scale at a particular level, then the owner or operator may 
demonstrate that the fuel flowmeter meets the total accuracy 
specification of 2.0 percent at that level by using one of the 
following alternative methods. If, at a particular level, the sum of 
the individual accuracies of the three transducers is less than or 
equal to 4.0 percent, the fuel flowmeter accuracy specification of 
2.0 percent is considered to be met for that level. Or, if at a 
particular level, the total fuel flowmeter accuracy is 2.0 percent 
or less, when calculated in accordance with Part 1 of American Gas 
Association Report No. 3, General Equations and Uncertainty 
Guidelines, the flowmeter accuracy requirement is considered to be 
met for that level.

2.1.6.2   Recordkeeping and Reporting of Transmitter or Transducer 
Accuracy Results

    (a) Record the accuracy of the orifice, nozzle, or venturi meter 
or its individual transmitters or transducers and keep this 
information in a file at the site or other location suitable for 
inspection. When testing individual orifice, nozzle, or venturi 
meter transmitters or transducers for accuracy, include the 
information displayed in the following Table D-2. At a minimum, 
record results for each transmitter or transducer at the zero-level 
and at least two other levels across the range of the transmitter or 
transducer readings that correspond to normal unit operation.

    Table D-2.--Table of Flowmeter Transmitter or Transducer Accuracy
                                 Results
Test number:________ Test completion date: ____________________ Unit or
 pipe ID: ____________
Flowmeter serial number:            Component/System ID:
Full-scale value:          Units of measure: \3\
Transducer/Transmitter Type (check one):
    ____ Differential Pressure
    ____ Static Pressure
    ____ Temperature
------------------------------------------------------------------------



                                                                           Expected
                                  Run number               Transmitter/  transmitter/     Actual       Percent
 Measurement level (percent of       (if        Run time    transducer    transducer   transmitter/    accuracy
          full-scale)              multiple      (HHMM)     input (pre-     output      transducer   (percent of
                                  runs) \2\                calibration)   (reference)   output \3\   full-scale)
----------------------------------------------------------------------------------------------------------------
Low (Minimum) level
    ____ percent \1\ of full-    ...........
     scale
Mid-level
    ____ percent\1\ of full-     ...........
     scale
(If tested at more than 3
 levels)
2nd Mid-level
    ____ percent \1\ of full-    ...........
     scale
(If tested at more than 3
 levels)
3rd Mid-level
    ____ percent \1\ of full-    ...........
     scale
High (Maximum) level
    ____ percent \1\ of full-    ...........
     scale
----------------------------------------------------------------------------------------------------------------
\1\ At a minimum, it is required to test at zero-level and at least two other levels across the range of the
  transmitter or transducer readings corresponding to normal unit operation.
\2\ It is required to test at least once at each level.
\3\ Use the same units of measure for all readings (e.g., use degrees ( deg.), inches of water (in H<INF>2</INF>O), pounds
  per square inch (psi), or milliamperes (ma) for both transmitter or transducer readings and reference
  readings).


[[Page 28656]]

    (b) When accuracy testing of the orifice, nozzle, or venturi 
meter is performed according to section 2.1.5.2 of this appendix, 
record the information displayed in Table D-1 in this section. At a 
minimum, record the overall flowmeter accuracy results for the fuel 
flowmeter at the three flow rate levels specified in section 2.1.5.2 
of this appendix.
    (c) Report the results of all fuel flowmeter accuracy tests, 
transmitter or transducer accuracy tests, and primary element 
inspections, as applicable, in the emissions report for the quarter 
in which the quality assurance tests are performed, using the 
electronic format specified by the Administrator under Sec. 75.64.

2.1.6.3  Failure of Transducer(s) or Transmitter(s)

    If, during a transmitter or transducer accuracy test conducted 
according to section 2.1.6.1 of this appendix, the flowmeter 
accuracy specification of 2.0 percent is not met at any of the 
levels tested, repair or replace transmitter(s) or transducer(s) as 
necessary until the flowmeter accuracy specification has been 
achieved at all levels. (Note that only transmitters or transducers 
which are repaired or replaced need to be re-tested; however, the 
re-testing is required at all three measurement levels, to ensure 
that the flowmeter accuracy specification is met at each level). The 
fuel flowmeter is ``out-of-control'' and data from the flowmeter are 
considered invalid, beginning with the date and hour of the failed 
accuracy test and continuing until the date and hour of completion 
of a successful transmitter or transducer accuracy test at all 
levels. In addition, if, during normal operation of the fuel 
flowmeter, one or more transmitters or transducers malfunction, data 
from the fuel flowmeter shall be considered invalid from the hour of 
the transmitter or transducer failure until the hour of completion 
of a successful 3-level transmitter or transducer accuracy test. 
During fuel flowmeter out-of-control periods, provide data from 
another fuel flowmeter that meets the requirements of Sec. 75.20(d) 
and section 2.1.5 of this appendix, or substitute for fuel flow rate 
using the missing data procedures in section 2.4.2 of this appendix. 
Record and report test data and results, consistent with sections 
2.1.6.1 and 2.1.6.2 of this appendix and Sec. 75.56 or Sec. 75.59, 
as applicable.

2.1.6.4  Primary Element Inspection

    (a) Conduct a visual inspection of the orifice, nozzle, or 
venturi meter at least once every twelve calendar quarters. 
Notwithstanding this requirement, the procedures of section 2.1.7 of 
this appendix may be used to reduce the inspection frequency of the 
orifice, nozzle, or venturi meter to at least once every twenty 
calendar quarters. The inspection may be performed using a 
baroscope. If the visual inspection indicates that the orifice, 
nozzle, or venturi meter has become damaged or corroded, then:
    (1) Replace the primary element with another primary element 
meeting the requirements of American Gas Association Report No. 3 or 
ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both 
standards incorporated by reference under Sec. 75.6);
    (2) Replace the primary element with another primary element, 
and demonstrate that the overall flowmeter accuracy meets the 
accuracy specification in section 2.1.5 of this appendix under the 
procedures of section 2.1.5.2 of this appendix; or
    (3) Restore the damaged or corroded primary element to ``as 
new'' condition; determine the overall accuracy of the flowmeter, 
using either the specifications of American Gas Association Report 
No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this 
appendix (both standards incorporated by reference under Sec. 75.6); 
and retest the transmitters or transducers prior to providing 
quality assured data from the flowmeter.
    (b) If the primary element size is changed, calibrate the 
transmitter or transducers consistent with the new primary element 
size. Data from the fuel flowmeter are considered invalid, beginning 
with the date and hour of a failed visual inspection and continuing 
until the date and hour when:
    (1) The damaged or corroded primary element is replaced with 
another primary element meeting the requirements of American Gas 
Association Report No. 3 or ASME MFC-3M-1989, as cited in section 
2.1.5.1 of this appendix (both standards incorporated by reference 
under Sec. 75.6);
    (2) The damaged or corroded primary element is replaced, and the 
overall accuracy of the flowmeter is demonstrated to meet the 
accuracy specification in section 2.1.5 of this appendix under the 
procedures of section 2.1.5.2 of this appendix; or
    (3) The restored primary element is installed to meet the 
requirements of American Gas Association Report No. 3 or ASME MFC-
3M-1989, as cited in section 2.1.5.1 of this appendix (both 
standards incorporated by reference under Sec. 75.6) and its 
transmitters or transducers are retested to meet the accuracy 
specification in section 2.1.6.1 of this appendix.
    (c) During this period, provide data from another fuel flowmeter 
that meets the requirements of Sec. 75.20(d) and section 2.1.5 of 
this appendix, or substitute for fuel flow rate using the missing 
data procedures in section 2.4.2 of this appendix.
    2.1.7  Fuel Flow-to-Load Quality Assurance Testing for Certified 
Fuel Flowmeters
    The procedures of this section may be used as an optional 
supplement to the quality assurance procedures in section 2.1.5.1, 
2.1.5.2, 2.1.6.1, or 2.1.6.4 of this appendix when conducting 
periodic quality assurance testing of a certified fuel flowmeter. 
Note, however, that these procedures may not be used unless the 168-
hour baseline data requirement of section 2.1.7.1 of this appendix 
has been met. If, following a flowmeter accuracy test or flowmeter 
transmitter test and primary element inspection, where applicable, 
the procedures of this section are performed during each subsequent 
fuel flowmeter QA operating quarter, as defined in Sec. 72.2 of this 
chapter (excluding the quarter(s) in which the baseline data are 
collected), then these procedures may be used to meet the 
requirement for periodic quality assurance for a period of up to 20 
calendar quarters from the previous periodic quality assurance 
procedure(s) performed according to sections 2.1.5.1, 2.1.5.2, or 
2.1.6.1 through 2.1.6.4 of this appendix. The procedures of this 
section are not required for any quarter in which a flowmeter 
accuracy test or a transmitter accuracy test and a primary element 
inspection, where applicable, are conducted. Notwithstanding the 
requirements of Sec. 75.54(a) or Sec. 75.57(a), as applicable, when 
using the procedures of this section, keep records of the test data 
and results from the previous flowmeter accuracy test under section 
2.1.5.1 or 2.1.5.2 of this appendix, records of the test data and 
results from the previous transmitter or transducer accuracy test 
under section 2.1.6.1 of this appendix for orifice-, nozzle-, and 
venturi-type fuel flowmeters, and records of the previous visual 
inspection of the primary element required under section 2.1.6.4 of 
this appendix for orifice-, nozzle-, and venturi-type fuel 
flowmeters until the next flowmeter accuracy test, transmitter 
accuracy test, or visual inspection is performed, even if the 
previous flowmeter accuracy test, transmitter accuracy test, or 
visual inspection was performed more than three years previously.

2.1.7.1  Baseline Flow Rate-to-Load Ratio or Heat Input-to-Load Ratio

    (a) Determine R<INF>base</INF>, the baseline value of the ratio 
of fuel flow rate to unit load, following each successful periodic 
quality assurance procedure performed according to sections 2.1.5.1, 
2.1.5.2, or 2.1.6.1 and 2.1.6.4 of this appendix. Establish a 
baseline period of data consisting, at a minimum, of 168 hours of 
quality assured fuel flowmeter data. Baseline data collection shall 
begin with the first hour of fuel flowmeter operation following 
completion of the most recent quality assurance procedure(s), during 
which only the fuel measured by the fuel flowmeter is combusted 
(i.e., only gas, only residual oil, or only diesel fuel is combusted 
by the unit). During the baseline data collection period, the owner 
or operator may exclude as non-representative any hour in which the 
unit is ``ramping'' up or down, (i.e., the load during the hour 
differs by more than 15.0 percent from the load in the previous or 
subsequent hour) and may exclude any hour in which the unit load is 
in the lower 25.0 percent of the range of operation, as defined in 
section 6.5.2.1 of appendix A to this part (unless operation in this 
lower 25.0 percent of the range is considered normal for the unit). 
The baseline data must be obtained no later than the end of the 
fourth calendar quarter following the calendar quarter of the most 
recent quality assurance procedure for that fuel flowmeter. For 
orifice-, nozzle-, and venturi-type fuel flowmeters, if the fuel 
flow-

[[Page 28657]]

to-load ratio is to be used as a supplement both to the transmitter 
accuracy test under section 2.1.6.1 of this appendix and to primary 
element inspections under section 2.1.6.4 of this appendix, then the 
baseline data must be obtained after both procedures are completed 
and no later than the end of the fourth calendar quarter following 
the calendar quarter of both the most recent transmitter or 
transducer test and the most recent primary element inspection for 
that fuel flowmeter. From these 168 (or more) hours of baseline 
data, calculate the baseline fuel flow rate-to-load ratio as 
follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.014

where:

R<INF>base</INF> = Value of the fuel flow rate-to-load ratio during 
the baseline period; 100 scfh/MWe or 100 scfh/klb per hour steam 
load for gas-firing; (lb/hr)/MWe or (lb/hr)/klb per hour steam load 
for oil-firing.
Q<INF>base</INF> = Average fuel flow rate measured by the fuel 
flowmeter during the baseline period, 100 scfh for gas-firing and 
lb/hr for oil-firing.
L<INF>avg</INF> = Average unit load during the baseline period, 
megawatts or 1000 lb/hr of steam.

    (b) In Equation D-1b, for a common pipe header, L<INF>avg</INF> 
is the sum of the operating loads of all units that receive fuel 
through the common pipe header. For a unit that receives its fuel 
through multiple pipes, Q<INF>base</INF> is the sum of the fuel flow 
rates for a particular fuel (i.e., gas, diesel fuel, or residual 
oil) from each of the pipes. Round off the value of R<INF>base</INF> 
to the nearest tenth.
    (c) Alternatively, a baseline value of the gross heat rate (GHR) 
may be determined in lieu of R<INF>base</INF>. The baseline value of 
the GHR, GHR<INF>base</INF>, shall be determined as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.015

Where:

(GHR)<INF>base</INF> = Baseline value of the gross heat rate during 
the baseline period, Btu/kwh or Btu/lb steam load.
(Heat Input)<INF>avg</INF> = Average (mean) hourly heat input rate 
recorded by the fuel flowmeter during the baseline period, as 
determined using the applicable equation in appendix F to this part, 
mmBtu/hr.
L<INF>avg</INF> = Average (mean) unit load during the baseline 
period, megawatts or 1000 lb/hr of steam.

    (d) Report the current value of R<INF>base</INF> (or 
GHR<INF>base</INF>) and the completion date of the associated 
quality assurance procedure in each electronic quarterly report 
required under Sec. 75.64.

2.1.7.2  Data Preparation and Analysis

    (a) Evaluate the fuel flow rate-to-load ratio (or GHR) for each 
fuel flowmeter QA operating quarter, as defined in Sec. 72.2 of this 
chapter. At the end of each fuel flowmeter QA operating quarter, use 
Equation D-1d in this appendix to calculate R<INF>h</INF>, the 
hourly fuel flow-to-load ratio, for every quality assured hourly 
average fuel flow rate obtained with a certified fuel flowmeter.
[GRAPHIC] [TIFF OMITTED] TR26MY99.016

where:

R<INF>h</INF> = Hourly value of the fuel flow rate-to-load ratio; 
100 scfh/MWe, (lb/hr)/MWe, 100 scfh/1000 lb/hr of steam load, or 
(lb/hr)/1000 lb/hr of steam load.
Q<INF>h</INF> = Hourly fuel flow rate, as measured by the fuel 
flowmeter, 100 scfh for gas-firing or lb/hr for oil-firing.
L<INF>h</INF> = Hourly unit load, megawatts or 1000 
lb/hr of steam.

    (b) For a common pipe header, L<INF>h</INF> shall be the sum of 
the hourly operating loads of all units that receive fuel through 
the common pipe header. For a unit that receives its fuel through 
multiple pipes, Q<INF>h</INF> will be the sum of the fuel flow rates 
for a particular fuel (i.e., gas, diesel fuel, or residual oil) from 
each of the pipes. Round off each value of R<INF>h</INF> to the 
nearest tenth.
    (c) Alternatively, calculate the hourly gross heat rates (GHR) 
in lieu of the hourly flow-to-load ratios. If this option is 
selected, calculate each hourly GHR value as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.017

Where:

(GHR)<INF>h</INF> = Hourly value of the gross heat rate, Btu/kwh or 
Btu/lb steam load.
(Heat Input)<INF>h</INF> = Hourly heat input rate, as determined 
using the applicable equation in appendix F to this part, mmBtu/hr.
L<INF>h</INF> = Hourly unit load, megawatts or 1000 
lb/hr of steam.

    (d) Evaluate the calculated flow rate-to-load ratios (or gross 
heat rates) as follows. Perform a separate data analysis for each 
fuel flowmeter following the procedures of this section. Base each 
analysis on a minimum of 168 hours of data. If, for a particular 
fuel flowmeter, fewer than 168 hourly flow-to-load ratios (or GHR 
values) are available, a flow-to-load (or GHR) evaluation is not 
required for that flowmeter for that calendar quarter.
    (e) For each hourly flow-to-load ratio or GHR value, calculate 
the percentage difference (percent D<INF>h</INF>) from the baseline 
fuel flow-to-load ratio using Equation D-1f.
[GRAPHIC] [TIFF OMITTED] TR26MY99.018

Where:

%D<INF>h</INF> = Absolute value of the percentage difference between 
the hourly fuel flow rate-to-load ratio and the baseline value of 
the fuel flow rate-to-load ratio (or hourly and baseline GHR).
R<INF>h</INF> = The hourly fuel flow rate-to-load ratio (or GHR).
R<INF>base</INF> = The value of the fuel flow rate-to-load ratio (or 
GHR) from the baseline period, determined in accordance with section 
2.1.7.1 of this appendix.

    (f) Consistently use R<INF>base</INF> and R<INF>h</INF> in 
Equation D-1f if the fuel flow-to-load ratio is being evaluated, and 
consistently use (GHR)<INF>base</INF> and (GHR)<INF>h</INF> in 
Equation D-1f if the gross heat rate is being evaluated.
    (g) Next, determine the arithmetic average of all of the hourly 
percent difference (percent D<INF>h</INF>) values using Equation D-
1g, as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.019

Where:

E<INF>f</INF> = Quarterly average percentage difference between 
hourly flow rate-to-load ratios and the baseline value of the fuel 
flow rate-to-load ratio (or hourly and baseline GHR).
%D<INF>h</INF> = Percentage difference between the hourly fuel flow 
rate-to-load ratio and the baseline value of the fuel flow rate-to-
load ratio (or hourly and baseline GHR).
q = Number of hours used in fuel flow-to-load (or GHR) evaluation.

    (h) When the quarterly average load value used in the data 
analysis is greater than 50 MWe (or 500 klb steam per hour), the 
results of a quarterly fuel flow rate-to-load (or GHR) evaluation 
are acceptable and no further action is required if the quarterly 
average percentage difference (E<INF>f</INF>) is no greater than 
10.0 percent. When the arithmetic average of the hourly load values 
used in the data analysis is <ls-thn-eq>50 MWe (or 500 klb steam per 
hour), the results of the analysis are

[[Page 28658]]

acceptable if the value of E<INF>f</INF> is no greater than 15.0 
percent.

2.1.7.3  Optional Data Exclusions

    (a) If E<INF>f</INF> is outside the limits in section 2.1.7.2 of 
this appendix, the owner or operator may re-examine the hourly fuel 
flow rate-to-load ratios (or GHRs) that were used for the data 
analysis and identify and exclude fuel flow-to-load ratios or GHR 
values for any non-representative fuel flow-to-load ratios or GHR 
values. Specifically, the R<INF>h</INF> or (GHR)<INF>h</INF> values 
for the following hours may be considered non-representative: any 
hour in which the unit combusted another fuel in addition to the 
fuel measured by the fuel flowmeter being tested; or any hour for 
which the load differed by more than <plus-minus>15.0 percent from 
the load during either the preceding hour or the subsequent hour; or 
any hour for which the unit load was in the lower 25.0 percent of 
the range of operation, as defined in section 6.5.2.1 of appendix A 
to this part (unless operation in the lower 25.0 percent of the 
range is considered normal for the unit).
    (b) After identifying and excluding all non-representative 
hourly fuel flow-to-load ratios or GHR values, analyze the quarterly 
fuel flow rate-to-load data a second time.

2.1.7.4  Consequences of Failed Fuel Flow-to-Load Ratio Test

    (a) If E<INF>f</INF> is outside the applicable limit in section 
2.1.7.2 of this appendix (after analysis using any optional data 
exclusions under section 2.1.7.3 of this appendix), perform 
transmitter accuracy tests according to section 2.1.6.1 of this 
appendix for orifice-, nozzle-, and venturi-type flowmeters, or 
perform a fuel flowmeter accuracy test, in accordance with section 
2.1.5.1 or 2.1.5.2 of this appendix, for each fuel flowmeter for 
which E<INF>f</INF> is outside of the applicable limit. In addition, 
for an orifice-, nozzle-, or venturi-type fuel flowmeter, repeat the 
fuel flow-to-load ratio comparison of section 2.1.7.2 of this 
appendix using six to twelve hours of data following a passed 
transmitter accuracy test in order to verify that no significant 
corrosion has affected the primary element. If, for the abbreviated 
6-to-12 hour test, the orifice-, nozzle-, or venturi-type fuel 
flowmeter is not able to meet the limit in section 2.1.7.2 of this 
appendix, then perform a visual inspection of the primary element 
according to section 2.1.6.4 of this appendix, and repair or replace 
the primary element, as necessary.
    (b) Substitute for fuel flow rate, for any hour when that fuel 
is combusted, using the missing data procedures in section 2.4.2 of 
this appendix, beginning with the first hour of the calendar quarter 
following the quarter for which E<INF>f</INF> was found to be 
outside the applicable limit and continuing until quality assured 
fuel flow data become available. Following a failed flow rate-to-
load or GHR evaluation, data from the flowmeter shall not be 
considered quality assured until the hour in which all required 
flowmeter accuracy tests, transmitter accuracy tests, visual 
inspections and diagnostic tests have been passed. Additionally, a 
new value of R<INF>base</INF> or (GHR)<INF>base</INF> shall be 
established no later than two flowmeter QA operating quarters after 
the quarter in which the required quality assurance tests are 
completed (note that for orifice-, nozzle-, or venturi-type fuel 
flowmeters, establish a new value of R<INF>base</INF> or 
(GHR)<INF>base</INF> only if both a transmitter accuracy test and a 
primary element inspection have been performed).

2.1.7.5  Test Results

    Report the results of each quarterly flow rate-to-load (or GHR) 
evaluation, as determined from Equation D-1g, in the electronic 
quarterly report required under Sec. 75.64. Table D-3 is provided as 
a reference on the type of information to be recorded under 
Sec. 75.59 and reported under Sec. 75.64.

 Table D-3.--Baseline Information and Test Results for Fuel Flow-to-Load
                                  Test
------------------------------------------------------------------------

-------------------------------------------------------------------------
Plant name:____________________State:______ORIS
 code:____________________
Unit/pipe ID #:____________Fuel flowmeter component and system ID
 #s:________-________Calendar quarter (1st, 2nd, 3rd, 4th) and
 year:____________
Range of operation:____________ to ____________ MWe or klb steam/hr
 (indicate units)
------------------------------------------------------------------------



                               Time period
-------------------------------------------------------------------------
               Baseline period                          Quarter
------------------------------------------------------------------------
Completion date and time of most recent        Number of hours excluded
 primary element inspection (orifice-, nozzle-  from quarterly average
 , and venturi-type flowmeters only).           due to co-firing
                                                different fuels:________
                                                hrs.
    ____/____/____ ____:____
Completion date and time of the most recent    Number of hours excluded
 flowmeter or transmitter accuracy test.        from quarterly average
                                                due to ramping load:
                                                ________ hrs.
    ____/____/____ ____:____
Beginning date and time of baseline period...  Number of hours in the
                                                lower 25.0 percent of
                                                the range of operation
                                                excluded from quarterly
                                                average: ________ hrs.
    ____/____/____ ____:____
End date and time of baseline period.........  Number of hours included
                                                in quarterly average:
                                                ________ hrs.
    ____/____/____ ____:____
Average fuel flow rate____________________     Quarterly percentage
 (100 scfh for gas and lb/hr for oil).          difference between
                                                hourly ratios and
                                                baseline ratio: ________
                                                percent.
Average load;____________________ (MWe or      Test result: pass, fail.
 1000 lb steam/hr).
Baseline fuel flow-to-load
 ratio____________________
Units of fuel flow-to-
 load:____________________
Baseline GHR: ____________________
Units of fuel flow-to-
 load:____________________
Number of hours excluded from baseline ratio
 or GHR due to ramping load:________
Number of hours in the lower 25.0 percent of
 the range of operation excluded from
 baseline ration or GHR: ________ hrs.
------------------------------------------------------------------------

2.2 Oil Sampling and Analysis

    Perform sampling and analysis of oil to determine the following 
fuel properties for each type of oil combusted by a unit: percentage 
of sulfur by weight in the oil; gross calorific value (GCV) of the 
oil; and, if necessary, the density of the oil. Use the sulfur 
content, density, and gross calorific value, determined under the 
provisions of this section, to calculate SO<INF>2</INF> mass 
emission rate and heat input rate for each fuel using the applicable 
procedures of section 3 of this appendix. The designated 
representative may petition for reduced GCV and or density sampling 
under Sec. 75.66 if the fuel combusted

[[Page 28659]]

has a consistent and relatively non-variable GCV or density.

       Table D-4.--Oil Sampling Methods and Sulfur, Density and Gross Calorific Value Used in Calculations
----------------------------------------------------------------------------------------------------------------
               Parameter                 Sampling technique/frequency          Value used in calculations
----------------------------------------------------------------------------------------------------------------
Oil Sulfur Content....................  Daily manual sampling.........  1. Highest sulfur content from previous
                                                                         30 daily samples; or
                                                                        2. Actual daily value.
                                        Flow proportional/weekly        Actual measured value.
                                         composite.
                                        In storage tank (after          1. Actual measured value; or
                                         addition of fuel to tank).     2. Highest of all sampled values in
                                                                         previous calendar year; or
                                                                        3. Maximum value allowed by contract.\1\
                                        As delivered (in delivery       1. Highest of all sampled values in
                                         truck or barge).\1\.            previous calendar year; or
                                                                        2. Maximum value allowed by contract.\1\
Oil Density...........................  Daily manual sampling.........  1. Use the highest density from the
                                                                         previous 30 daily samples; or
                                                                        2. Actual measured value.
                                        Flow proportional/weekly        Actual measured value.
                                         composite.
                                        In storage tank (after          1. Actual measured value; or
                                         addition of fuel to tank).     2. Highest of all sampled values in
                                                                         previous calendar year; or
                                                                        3. Maximum value allowed by contract.\1\
                                        As delivered (in delivery       1. Highest of all sampled values in
                                         truck or barge).\1\.            previous calendar year; or
                                                                        2. Maximum value allowed by contract.\1\
Oil GCV...............................  Daily manual sampling.........  1. Highest fuel GCV from the previous 30
                                                                         daily samples; or
                                                                        2. Actual measured value.
                                        Flow proportional/weekly        Actual measured value.
                                         composite.
                                        In storage tank (after          1. Actual measured value; or
                                         addition of fuel to tank).     2. Highest of all sampled values in
                                                                         previous calendar year; or
                                                                        3. Maximum value allowed by contract.\1\
                                        As delivered (in delivery       1. Highest of all sampled values in
                                         truck or barge).\1\.            previous calendar year; or
                                                                        2. Maximum value allowed by contract.\1\

----------------------------------------------------------------------------------------------------------------
\1\ Assumed values may only be used if sulfur content, gross calorific value, or density of each sample is no
  greater than the assumed value used to calculate emissions or heat input.

    2.2.1  When combusting oil, use one of the following methods to 
sample the oil (see Table D-4): sample from the storage tank for the 
unit after each addition of oil to the storage tank, in accordance 
with section 2.2.4.2 of this appendix; or sample from the fuel lot 
in the shipment tank or container upon receipt of each oil delivery 
or from the fuel lot in the oil supplier's storage container, in 
accordance with section 2.2.4.3 of this appendix; or use the flow 
proportional sampling methodology in section 2.2.3 of this appendix; 
or use the daily manual sampling methodology in section 2.2.4.1 of 
this appendix. For purposes of this appendix, a fuel lot of oil is 
the mass or volume of product oil from one source (supplier or 
pretreatment facility), intended as one shipment or delivery (e.g., 
ship load, barge load, group of trucks, discrete purchase of diesel 
fuel through pipeline, etc.). A storage tank is a container at a 
plant holding oil that is actually combusted by the unit, such that 
no blending of any other fuel with the fuel in the storage tank 
occurs from the time that the fuel lot is transferred to the storage 
tank to the time when the fuel is combusted in the unit.
    2.2.2  [Reserved]

2.2.3  Flow Proportional Sampling

    Conduct flow proportional oil sampling or continuous drip oil 
sampling in accordance with ASTM D4177-82 (Reapproved 1990), 
``Standard Practice for Automatic Sampling of Petroleum and 
Petroleum Products'' (incorporated by reference under Sec. 75.6), 
every day the unit is combusting oil. Extract oil at least once 
every hour and blend into a composite sample. The sample compositing 
period may not exceed 7 calendar days (168 hrs). Use the actual 
sulfur content (and where density data are required, the actual 
density) from the composite sample to calculate the hourly 
SO<INF>2</INF> mass emission rates for each operating day 
represented by the composite sample. Calculate the hourly heat input 
rates for each operating day represented by the composite sample, 
using the actual gross calorific value from the composite sample.

2.2.4  Manual Sampling

2.2.4.1  Daily Samples

    Representative oil samples may be taken from the storage tank or 
fuel flow line manually every day that the unit combusts oil 
according to ASTM D4057-88, ``Standard Practice for Manual Sampling 
of Petroleum and Petroleum Products'' (incorporated by reference 
under Sec. 75.6). Use either the actual daily sulfur content or the 
highest fuel sulfur content recorded at that unit from the most 
recent 30 daily samples for the purpose of calculating 
SO<INF>2</INF> emissions under section 3 of this appendix. Use 
either the gross calorific value measured from that day's sample or 
the highest GCV from the previous 30 days' samples to calculate heat 
input. If oil supplies with different sulfur contents are combusted 
on the same day, sample the highest sulfur fuel combusted that day.

2.2.4.2  Sampling From a Unit's Storage Tank

    Take a manual sample after each addition of oil to the storage 
tank. Do not blend additional fuel with the sampled fuel prior to 
combustion. Sample according to the single tank composite sampling 
procedure or all-levels sampling procedure in ASTM D4057-88, 
``Standard Practice for Manual Sampling of Petroleum and Petroleum 
Products'' (incorporated by reference under Sec. 75.6). Use the 
sulfur content (and where required, the density) of either the most 
recent sample or one of the conservative assumed values described in 
section 2.2.4.3 of this appendix to calculate SO<INF>2</INF> mass 
emission rate. Calculate heat input rate using the gross calorific 
value from either:
    (a) The most recent oil sample taken or
    (b) One of the conservative assumed values described in section 
2.2.4.3 of this appendix.

2.2.4.3  Sampling From Each Delivery

    (a) Alternatively, an oil sample may be taken from--
    (1) The shipment tank or container upon receipt of each lot of 
fuel oil or
    (2) The supplier's storage container which holds the lot of fuel 
oil. (Note: a supplier need only sample the storage container once 
for sulfur content, GCV and, where required, the density so long as 
the fuel sulfur content and GCV do not change and no fuel is added 
to the supplier's storage container.)
    (b) For the purpose of this section, a lot is defined as a 
shipment or delivery (e.g., ship load, barge load, group of trucks, 
discrete purchase of diesel fuel through a pipeline, etc.) of a 
single fuel.
    (c) Oil sampling may be performed either by the owner or 
operator of an affected unit, an outside laboratory, or a fuel 
supplier, provided that samples are representative and that sampling 
is performed according to either the single tank composite sampling 
procedure or the all-levels sampling procedure in ASTM D4057-88, 
``Standard Practice for Manual Sampling of Petroleum and Petroleum 
Products'' (incorporated by reference under Sec. 75.6). Except as 
otherwise provided in this section, calculate SO<INF>2</INF> mass

[[Page 28660]]

emission rate using the sulfur content (and where required, the 
density) from one of the two following values, and calculate heat 
input using the gross calorific value from one of the two following 
values:
    (1) The highest value sampled during the previous calendar year 
(this option is allowed for any consistent fuel which comes from a 
single source whether or not the fuel is supplied under a 
contractual agreement) or
    (2) The maximum value indicated in the contract with the fuel 
supplier. Continue to use this assumed contract value unless and 
until the actual sampled sulfur content, density, or gross calorific 
value of a delivery exceeds the assumed value.
    (d) If the actual sampled sulfur content, gross calorific value, 
or density of an oil sample is greater than the assumed value for 
that parameter, then use the actual sampled value for sulfur 
content, gross calorific value, or density of fuel to calculate 
SO<INF>2</INF> mass emission rate or heat input rate as the new 
assumed sulfur content, gross calorific value, or density. Continue 
to use this new assumed value to calculate SO<INF>2</INF> mass 
emission rate or heat input rate unless and until: it is superseded 
by a higher value from an oil sample; or it is superseded by a new 
contract in which case the new contract value becomes the assumed 
value at the time the fuel specified under the new contract begins 
to be combusted in the unit; or (if applicable) both the calendar 
year in which the sampled value exceeded the assumed value and the 
subsequent calendar year have elapsed.
* * * * *
    2.2.6  Where the flowmeter records volumetric flow rate rather 
than mass flow rate, analyze oil samples to determine the density or 
specific gravity of the oil. * * *
* * * * *
    2.2.8  Results from the oil sample analysis must be available no 
later than thirty calendar days after the sample is composited or 
taken. However, during an audit, the Administrator may require that 
the results of the analysis be available as soon as practicable, and 
no later than 5 business days after receipt of a request from the 
Administrator.

2.3  SO<INF>2</INF> Emissions From Combustion of Gaseous Fuels

    (a) Account for the hourly SO<INF>2</INF> mass emissions due to 
combustion of gaseous fuels for each hour when gaseous fuels are 
combusted by the unit using the procedures in this section.
    (b) The procedures in sections 2.3.1 and 2.3.2 of this appendix, 
respectively, may be used to determine SO<INF>2</INF> mass emissions 
from combustion of pipeline natural gas and natural gas, as defined 
in Sec. 72.2 of this chapter. The procedures in section 2.3.3 of 
this appendix may be used to account for SO<INF>2</INF> mass 
emissions from any gaseous fuel combusted by a unit. For each type 
of gaseous fuel, the appropriate sampling frequency and the sulfur 
content and GCV values used for calculations of SO<INF>2</INF> mass 
emission rates are summarized in the following Table D-5.

 Table D-5.--Gas Sulfur and GCV Values Used in Calculations for Various
                               Fuel Types
------------------------------------------------------------------------
                                  Fuel type and         Value used in
          Parameter            sampling frequency       calculations
------------------------------------------------------------------------
                              Pipeline Natural Gas  0.0006 lb/mmBtu.
                               with H<INF>2</INF>S content
                               less than or equal
                               to 0.3 grains/
                               100scf when using
                               the provisions of
                               section 2.3.1 to
                               determine SO<INF>2</INF> mass
                               emissions.
Gas Sulfur Content..........  Natural Gas with H<INF>2</INF>S  Default SO<INF>2</INF> emission
                               content less than     rate calculated
                               or equal to 1.0       from Eq. D-1h,
                               grain/100scf when     using either the
                               using the             fuel contract
                               provisions of         maximum H<INF>2</INF>S or the
                               section 2.3.2 to      maximum H<INF>2</INF>S from
                               determine SO<INF>2</INF> mass    historical sampling
                               emissions.            data.
                              Any gaseous fuel      Actual % sulfur from
                               delivered in          most recent
                               shipments or lots--   shipment or
                               Sample each lot or   1. Highest % sulfur
                               shipment.             from previous
                                                     year's samples \1\;
                                                     or
                                                    2. Maximum % sulfur
                                                     value allowed by
                                                     contract \1\.
                              Any gaseous fuel      Actual % sulfur from
                               transmitted by        daily sample; or
                               pipeline and having   Highest % sulfur
                               a demonstrated        from previous 30
                               ``low sulfur          daily samples.
                               variability'' using
                               the provisions of
                               section 2.3.6--
                               Sample daily.
                              Any gaseous fuel--    Actual hourly sulfur
                               Sample hourly.        content of the gas.
Gas GCV.....................  Pipeline Natural      1. GCV from most
                               Gas--Sample monthly.  recent monthly
                                                     sample (with <gr-
                                                     thn-eq> 48
                                                     operating hours in
                                                     the month); or
                                                    2. Maximum GCV from
                                                     contract \1\; or
                                                    3. Highest GCV from
                                                     previous year's
                                                     samples.\1\
                               Natural Gas--Sample  1. GCV from most
                               monthly.              recent monthly
                                                     sample (with <gr-
                                                     thn-eq> 48
                                                     operating hours in
                                                     the month); or
                                                    2. Maximum GCV from
                                                     contract \1\; or
                                                    3. Highest GCV from
                                                     previous year's
                                                     samples.\1\
                              Any gaseous fuel      Actual GCV from most
                               delivered in          recent shipment or
                               shipments or lots--   lot or
                               Sample each lot or   1. Highest GCV from
                               shipment.             previous year's
                                                     samples1; or
                                                    2. Maximum GCV value
                                                     allowed by
                                                     contract.\1\
                              Any gaseous fuel      1. GCV from most
                               transmitted by        recent monthly
                               pipeline and having   sample (with <gr-
                               a demonstrated        thn-eq> 48
                               ``low GCV             operating hours in
                               variability'' using   the month); or
                               the provisions of    2. Highest GCV from
                               section 2.3.5--       previous year's
                               Sample monthly.       samples.\1\
                              Any other gaseous     Actual daily or
                               fuel not having a     hourly GCV of the
                               ``low GCV             gas.
                               variability''--Samp
                               le at least daily.
                               (Note that the use
                               of an on-line GCV
                               calorimeter or gas
                               chromatograph is
                               allowed).
------------------------------------------------------------------------
\1\ Assumed sulfur content and GCV values (i.e., contract values or
  highest values from previous year) may only continue to be used if the
  sulfur content or GCV of each sample is no greater than the assumed
  value used to calculate SO<INF>2</INF> emissions or heat input.

2.3.1  Pipeline Natural Gas Combustion

    The owner or operator may determine the SO<INF>2</INF> mass 
emissions from the combustion of a fuel that meets the definition of 
pipeline natural gas, in Sec. 72.2 of this chapter, using the 
procedures of this section.

2.3.1.1  SO<INF>2</INF> Emission Rate

    For a fuel that meets the definition of pipeline natural gas 
under Sec. 72.2 of this chapter, the owner or operator may determine 
the SO<INF>2</INF> mass emissions using either a default 
SO<INF>2</INF> emission rate of 0.0006 lb/mmBtu and the procedures 
of this section, the procedures in section 2.3.2 for natural

[[Page 28661]]

gas, or the procedures of section 2.3.3 for any gaseous fuel. For 
each affected unit using the default rate of 0.0006 lb/mmBtu, the 
owner or operator must document that the fuel combusted is actually 
pipeline natural gas, using the procedures in section 2.3.1.4 of 
this appendix.

2.3.1.2  Hourly Heat Input Rate

    Calculate hourly heat input rate, in mmBtu/hr, for a unit 
combusting pipeline natural gas, using the procedures of section 
3.4.1 of this appendix. Use the measured fuel flow rate from section 
2.1 of this appendix and the gross calorific value from section 
2.3.4.1 of this appendix in the calculations.

2.3.1.3  SO<INF>2</INF> Hourly Mass Emission Rate and Hourly Mass 
Emissions

    For pipeline natural gas combustion, calculate the SO2 mass 
emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this 
appendix (when the default SO<INF>2</INF> emission rate is used). 
Then, use the calculated SO<INF>2</INF> mass emission rate and the 
unit operating time to determine the hourly SO<INF>2</INF> mass 
emissions from pipeline natural gas combustion, in lb, using 
Equation D-12 in section 3.5.1 of this appendix.

2.3.1.4  Documentation That a Fuel Is Pipeline Natural Gas

    (a) For pipeline natural gas, provide information in the 
monitoring plan required under Sec. 75.53, demonstrating that the 
definition of pipeline natural gas in Sec. 72.2 of this chapter has 
been met. The information must demonstrate that the fuel has a 
hydrogen sulfide content of less than 0.3 grain/100scf. The 
demonstration must be made using one of the following sources of 
information:
    (1) The gas quality characteristics specified by a purchase 
contract or by a pipeline transportation contract;
    (2) A certification of the gas vendor, based on routine vendor 
sampling and analysis (minimum of one year of data with samples 
taken monthly or more frequently);
    (3) At least one year's worth of analytical data on the fuel 
hydrogen sulfide content from samples taken monthly or more 
frequently;
    (4) For fuels delivered in shipments or lots, the sulfur content 
from all shipments or lots received in a one year period; or
    (5) Data from a 720-hour demonstration conducted using the 
procedures of section 2.3.6 of this appendix.
    (b) When a 720-hour test is used for initial qualification as 
pipeline natural gas, the owner or operator is required to continue 
sampling the fuel for hydrogen sulfide at least once per month for 
one year after the initial qualification period. The use of the 
default natural gas SO<INF>2</INF> emission rate under 2.3.1.1 is 
not allowed if any sample during the one year period has a hydrogen 
sulfide content greater than 0.3 gr/100 scf.

2.3.2  Natural Gas Combustion

    The owner or operator may determine the SO<INF>2</INF> mass 
emissions from the combustion of a fuel that meets the definition of 
natural gas, in Sec. 72.2 of this chapter, using the procedures of 
this section.

2.3.2.1  SO<INF>2</INF> Emission Rate

    The owner or operator may account for SO<INF>2</INF> emissions 
either by using a default SO<INF>2</INF> emission rate, as 
determined under section 2.3.2.1.1 of this appendix, or by daily 
sampling of the gas sulfur content using the procedures of section 
2.3.3 of this appendix. For each affected unit using a default 
SO<INF>2</INF> emission rate, the owner or operator must provide 
documentation that the fuel combusted is actually natural gas 
according to the procedures in section 2.3.2.4 of this appendix.
    2.3.2.1.1  In lieu of daily sampling of the sulfur content of 
the natural gas, an SO<INF>2</INF> default emission rate may be 
determined using Equation D-1h. Round off the calculated 
SO<INF>2</INF> default emission rate to the nearest 0.0001 lb/mmBtu.
[GRAPHIC] [TIFF OMITTED] TR26MY99.020

Where:

ER = Default SO<INF>2</INF> emission rate for natural gas 
combustion, lb/mmBtu.
H<INF>2</INF>S = Hydrogen sulfide content of the natural gas, gr/
100scf.

    2.3.2.1.2  The hydrogen sulfide value used in Equation D-1h may 
be obtained from one of the following sources of information:
    (a) The highest hydrogen sulfide content specified by a purchase 
contract or by a pipeline transportation contract;
    (b) The highest hydrogen sulfide content from a certification of 
the gas vendor, based on routine vendor sampling and analysis 
(minimum of one year of data with samples taken monthly or more 
frequently);
    (c) The highest hydrogen sulfide content from at least one 
year's worth of analytical data on the fuel hydrogen sulfide content 
from samples taken monthly or more frequently;
    (d) For fuels delivered in shipments or lots, the highest 
hydrogen sulfide content from all shipments or lots received in a 
one year period; or (5) the highest hydrogen sulfide content 
measured during a 720-hour demonstration conducted using the 
procedures of section 2.3.6 of this appendix.

2.3.2.2  Hourly Heat Input Rate

    Calculate hourly heat input rate for natural gas combustion, in 
mmBtu/hr, using the procedures in section 3.4.1 of this appendix. 
Use the measured fuel flow rate from section 2.1 of this appendix 
and the gross calorific value from section 2.3.4.2 of this appendix 
in the calculations.

2.3.2.3  SO<INF>2</INF> Mass Emission Rate and Hourly Mass Emissions

    For natural gas combustion, calculate the SO<INF>2</INF> mass 
emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this 
appendix, when the default SO<INF>2</INF> emission rate is used. 
Then, use the calculated SO<INF>2</INF> mass emission rate and the 
unit operating time to determine the hourly SO<INF>2</INF> mass 
emissions from natural gas combustion, in lb, using Equation D-12 in 
section 3.5.1 of this appendix.

2.3.2.4  Documentation that a Fuel Is Natural Gas

    (a) For natural gas, provide information in the monitoring plan 
required under Sec. 75.53, demonstrating that the definition of 
natural gas in Sec. 72.2 of this chapter has been met. The 
information must demonstrate that the fuel has a hydrogen sulfide 
content of less than 1.0 grain/100 scf. This demonstration must be 
made using one of the following sources of information:
    (1) The gas quality characteristics specified by a purchase 
contract or by a transportation contract;
    (2) A certification of the gas vendor, based on routine vendor 
sampling and analysis (minimum of one year of data with samples 
taken monthly or more frequently);
    (3) At least one year's worth of analytical data on the fuel 
hydrogen sulfide content from samples taken monthly or more 
frequently;
    (4) For fuels delivered in shipments or lots, sulfur content 
from all shipments or lots received in a one year period; or
    (5) Data from a 720-hour demonstration conducted using the 
procedures of section 2.3.6 of this appendix.
    (b) When a 720-hour test is used for initial qualification as 
natural gas, the owner or operator shall continue sampling the fuel 
for hydrogen sulfide at least once per month for one year after the 
initial qualification period. The use of the default natural gas 
SO<INF>2</INF> emission rate under 2.3.2.1.1 is not allowed if any 
sample during the one year period has a hydrogen sulfide content 
greater than 1.0 grain/100 scf.

2.3.3  SO<INF>2</INF> Mass Emissions From Any Gaseous Fuel

    The owner or operator of a unit may determine SO<INF>2</INF> 
mass emissions using this section for any gaseous fuel (including 
fuels such as refinery gas, landfill gas, digester gas, coke oven 
gas, blast furnace gas, coal-derived gas, producer gas or any other 
gas which may have a variable sulfur content).

2.3.3.1  Sulfur Content Determination

    2.3.3.1.1  Analyze the total sulfur content of the gaseous fuel 
in grain/100 scf, at the frequency specified in Table D-5 of this 
appendix. That is: for fuel delivered in discrete shipments or lots, 
sample each shipment or lot; for fuel transmitted by pipeline, if a 
demonstration is provided under section 2.3.6 of this appendix 
showing that the gaseous fuel has a ``low sulfur variability,'' 
determine the sulfur content daily using either manual sampling or a 
gas chromatograph; and for all other gaseous fuels, determine the 
sulfur content on an hourly basis using a gas chromatograph.
    2.3.3.1.2  Use one of the following methods when using manual 
sampling (as applicable to the type of gas combusted) to determine 
the sulfur content of the fuel: ASTM D1072-90, ``Standard Test 
Method for Total Sulfur in Fuel Gases'', ASTM D4468-85 (Reapproved 
1989) ``Standard Test Method for Total Sulfur in Gaseous Fuels by 
Hydrogenolysis and Radiometric Colorimetry,'' ASTM D5504-94 
``Standard Test Method for Determination of Sulfur Compounds in 
Natural Gas and Gaseous Fuels by Gas Chromatography and 
Chemiluminescence,'' or ASTM D3246-81 (Reapproved 1987) ``Standard 
Test Method for Sulfur in Petroleum Gas By Oxidative 
Microcoulometry'' (incorporated by reference under Sec. 75.6).

[[Page 28662]]

    2.3.3.1.3  The sampling and analysis of daily manual samples may 
be performed by the owner or operator, an outside laboratory, or the 
gas supplier. If hourly sampling with a gas chromatograph is 
required, or a source chooses to use an online gas chromatograph to 
determine daily fuel sulfur content, the owner or operator shall 
develop and implement a program to quality assure the data from the 
gas chromatograph, in accordance with the manufacturer's recommended 
procedures. The quality assurance procedures shall be kept on-site, 
in a form suitable for inspection.
    2.3.3.1.4  Results of all sample analyses must be available no 
later than thirty calendar days after the sample is taken.
    2.3.3.2  SO<INF>2</INF> Mass Emission Rate
    Calculate the SO<INF>2</INF> mass emission rate for the gaseous 
fuel, in lb/hr, using equation D-4 in section 3.3.1 of this 
appendix. Use the appropriate sulfur content, in equation D-4, as 
specified in Table D-5 of this appendix. That is, for fuels 
delivered by pipeline which demonstrate a low sulfur variability 
(under section 2.3.6 of this appendix) use either the daily value or 
the highest value in the previous 30 days or for fuels requiring 
hourly sulfur content sampling with a gas chromatograph use the 
actual hourly sulfur content).

2.3.3.3  Hourly Heat Input Rate

    Calculate the hourly heat input rate for combustion of the 
gaseous fuel, using the provisions in section 3.4.1 of this 
appendix. Use the measured fuel flow rate from section 2.1 of this 
appendix and the gross calorific value from section 2.3.4.3 of this 
appendix in the calculations.

2.3.4  Gross Calorific Values for Gaseous Fuels

    Determine the GCV of each gaseous fuel at the frequency 
specified in this section, using one of the following methods: ASTM 
D1826-88, ASTM D3588-91, ASTM D4891-89, GPA Standard 2172-86 
``Calculation of Gross Heating Value, Relative Density and 
Compressibility Factor for Natural Gas Mixtures from Compositional 
Analysis,'' or GPA Standard 2261-90 ``Analysis for Natural Gas and 
Similar Gaseous Mixtures by Gas Chromatography'' (incorporated by 
reference under Sec. 75.6 of this part). Use the appropriate GCV 
value, as specified in section 2.3.4.1, 2.3.4.2 or 2.3.4.3 of this 
appendix, in the calculation of unit hourly heat input rates.

2.3.4.1  GCV of Pipeline Natural Gas

    Determine the GCV of fuel that is pipeline natural gas, as 
defined in Sec. 72.2 of this chapter, at least once per calendar 
month. For GCV used in calculations use the specifications in Table 
D-5: either the value from the most recent monthly sample, the 
highest value specified in a contract or tariff sheet, or the 
highest value from the previous year. The fuel GCV value from the 
most recent monthly sample shall be used for any month in which that 
value is higher than a contract limit. If a unit combusts pipeline 
natural gas for less than 48 hours during a calendar month, the 
sampling and analysis requirement for GCV is waived for that 
calendar month. The preceding waiver is limited by the condition 
that at least one analysis for GCV must be performed for each 
quarter the unit operates for any amount of time.

2.3.4.2  GCV of Natural Gas

    Determine the GCV of fuel that is natural gas, as defined in 
Sec. 72.2 of this chapter, on a monthly basis, in the same manner as 
described for pipeline natural gas in section 2.3.4.1 of this 
appendix.

2.3.4.3  GCV of Other Gaseous Fuels

    For gaseous fuels other than natural gas or pipeline natural 
gas, determine the GCV as specified in section 2.3.4.3.1, 2.3.4.3.2 
or 2.3.4.3.3, as applicable. 2.3.4.3.1 For a gaseous fuel that is 
delivered in discrete shipments or lots, determine the GCV for each 
shipment or lot. The determination may be made by sampling each 
delivery or by sampling the supply tank after each delivery. For 
sampling of each delivery, use the highest GCV in the previous 
year's samples. For sampling from the tank after each delivery, use 
either the most recent GCV sample or the highest GCV in the previous 
year. 2.3.4.3.2 For any gaseous fuel that does not qualify as 
pipeline natural gas or natural gas and which is not delivered in 
shipments or lots which performs the required 720 hour test under 
section 2.3.5 of this appendix, and the results of the test 
demonstrate that the gaseous fuel has a low GCV variability, 
determine the GCV at least monthly. In calculations of hourly heat 
input for a unit, use either the most recent monthly sample or the 
highest fuel GCV from the previous year's samples. 2.3.4.3.3 For any 
other gaseous fuel, determine the GCV at least daily and use the 
actual fuel GCV in calculations of unit hourly heat input. If an 
online gas chromatograph or on-line calorimeter is used to determine 
fuel GCV each day, the owner or operator shall develop and implement 
a program to quality assure the data from the gas chromatograph or 
on-line calorimeter, in accordance with the manufacturer's 
recommended procedures. The quality assurance procedures shall be 
kept on-site, in a form suitable for inspection.

2.3.5  Demonstration of Fuel GCV Variability

    (a) This demonstration is required of any fuel which does not 
qualify as pipeline natural gas or natural gas, and is not delivered 
only in shipments or lots. The demonstration data shall be used to 
determine whether daily or monthly sampling of the GCV of the 
gaseous fuel or blend is required.
    (b) To make this demonstration, proceed as follows. Provide a 
minimum of 720 hours of data, indicating the GCV of the gaseous fuel 
or blend (in Btu/100 scf). The demonstration data shall be obtained 
using either: hourly sampling and analysis using the methods in 
section 2.3.4 to determine GCV of the fuel; an on-line gas 
chromatograph capable of determining fuel GCV on an hourly basis; or 
an on-line calorimeter. For gaseous fuel produced by a variable 
process, the data shall be representative of and include all process 
operating conditions including seasonal and yearly variations in 
process which may affect fuel GCV.
    (c) The data shall be reduced to hourly averages. The mean GCV 
value and the standard deviation from the mean shall be calculated 
from the hourly averages. Specifically, the gaseous fuel is 
considered to have a low GCV variability, and monthly gas sampling 
for GCV may be used, if the mean value of the GCV multiplied by 
1.075 is less than the sum of the mean value and one standard 
deviation. If the gaseous fuel or blend does not meet this 
requirement, then daily fuel sampling and analysis for GCV, using 
manual sampling, a gas chromatograph or an on-line calorimeter is 
required.

2.3.6  Demonstration of Fuel Sulfur Variability

    (a) This demonstration is required for any fuel which does not 
qualify as pipeline natural gas or natural gas and is not delivered 
in shipments or lots. The results of the demonstration will be used 
to determine whether daily or hourly sampling for sulfur in the fuel 
is required. To make this demonstration, proceed as follows. Provide 
a minimum of 720 hours of data, indicating the total sulfur content 
(and hydrogen sulfide content, if needed to define a fuel as either 
pipeline natural gas or natural gas) of the gaseous fuel or blend 
(in gr/100 scf). The demonstration data shall be obtained using 
either manual hourly sampling or an on-line gas chromatograph 
capable of determining fuel total sulfur content (and, if 
applicable, H<INF>2</INF>S content) on an hourly basis. For gaseous 
fuel produced by a variable process, additional data shall be 
provided which is representative of all process operating conditions 
including seasonal or annual variations which may affect fuel sulfur 
content.
    (b) Reduce the data to hourly averages of the total sulfur 
content (and hydrogen sulfide content, if applicable) of the fuel. 
Then, calculate the mean value of the total sulfur content and 
standard deviation in order to determine whether daily sampling of 
the sulfur content of the gaseous fuel or blend is sufficient or 
whether hourly sampling with a gas chromatograph is required. 
Specifically, daily gas sampling and analysis for total sulfur 
content, using either manual sampling or an online gas 
chromatograph, shall be sufficient, provided that the standard 
deviation of the hourly average values from the mean value does not 
exceed 5.0 grains per 100 scf. If the gaseous fuel or blend does not 
meet this requirement, then hourly sampling of the fuel with a gas 
chromatograph and hourly reporting of the average sulfur content of 
the fuel is required.

2.4 * * *

2.4.1  Missing Data for Oil and Gas Samples

    When fuel sulfur content, gross calorific value or, when 
necessary, density data are missing or invalid for an oil or gas 
sample taken according to the procedures in section 2.2.3, 2.2.4.1, 
2.2.4.2, 2.2.4.3, 2.2.5, 2.2.6, 2.2.7, 2.3.3.1, 2.3.3.1.2, or 2.3.4 
of this appendix, then substitute the maximum potential sulfur 
content, density, or gross calorific value of that fuel from Table 
D-6 of this appendix. Irrespective of which reporting option is 
selected (i.e., actual value, contract value or highest value from 
the previous year, the missing data values in Table D-6 shall be 
reported whenever the


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