[Title 40 CFR 60.50Da]
[Code of Federal Regulations (annual edition) - July 1, 2009 Edition]
[Title 40 - PROTECTION OF ENVIRONMENT]
[Chapter I - ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)]
[Subchapter C - AIR PROGRAMS (CONTINUED)]
[Part 60 - STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES--]
[Subpart Da - Standards of Performance for Electric Utility Steam]
[Sec. 60.50da - Compliance determination procedures and methods.]
[From the U.S. Government Printing Office]


40PROTECTION OF ENVIRONMENT62009-07-012009-07-01false60.50DaSec. 60.50DaPROTECTION OF ENVIRONMENTENVIRONMENTAL PROTECTION AGENCY (CONTINUED)AIR PROGRAMS (CONTINUED)STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES--Standards of Performance for Electric Utility Steam
Sec. 60.50Da  Compliance determination procedures and methods.

    (a) In conducting the performance tests required in Sec. 60.8, the 
owner or operator shall use as reference methods and procedures the 
methods in appendix A of this part or the methods and procedures as 
specified in this section, except as provided in Sec. 60.8(b). Section 
60.8(f) does not apply to this section for SO2 and 
NOX. Acceptable alternative methods are given in paragraph 
(e) of this section.
    (b) The owner or operator shall determine compliance with the PM 
standards in Sec. 60.42Da as follows:
    (1) The dry basis F factor (O2) procedures in Method 19 
of appendix A of this part shall be used to compute the emission rate of 
PM.
    (2) For the particular matter concentration, Method 5 of appendix A 
of this part shall be used at affected facilities without wet FGD 
systems and Method 5B of appendix A of this part shall be used after wet 
FGD systems.
    (i) The sampling time and sample volume for each run shall be at 
least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder 
heating system in the sampling train may be set to provide an average 
gas temperature of no greater than 16014 [deg]C 
(32025 [deg]F).
    (ii) For each particulate run, the emission rate correction factor, 
integrated or grab sampling and analysis procedures of Method 3B of 
appendix A of this part shall be used to determine the O2 
concentration. The O2 sample shall be obtained simultaneously 
with, and at the same traverse points as, the particulate run. If the 
particulate run has more than 12 traverse points, the O2 
traverse points may be reduced to 12 provided that Method 1 of appendix 
A of this part is used to locate the 12 O2 traverse points. 
If the grab sampling procedure is used, the O2 concentration 
for the run shall be the arithmetic mean of the sample O2 
concentrations at all traverse points.
    (3) Method 9 of appendix A of this part and the procedures in Sec. 
60.11 shall be used to determine opacity.
    (c) The owner or operator shall determine compliance with the 
SO2 standards in Sec. 60.43Da as follows:
    (1) The percent of potential SO2 emissions (%Ps) to the 
atmosphere shall be computed using the following equation:
[GRAPHIC] [TIFF OMITTED] TR13JN07.015

Where:

%Ps = Percent of potential SO2 emissions, percent;
%Rf = Percent reduction from fuel pretreatment, percent; and
%Rg = Percent reduction by SO2 control system, percent.

    (2) The procedures in Method 19 of appendix A of this part may be 
used to determine percent reduction (%Rf) of sulfur by such 
processes as fuel pretreatment (physical coal cleaning, 
hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom 
and fly ash interactions. This determination is optional.
    (3) The procedures in Method 19 of appendix A of this part shall be 
used to determine the percent SO2 reduction (%Rg) 
of any SO2 control system. Alternatively, a combination of an 
``as fired'' fuel monitor and emission rates measured after the control 
system, following the procedures in Method 19 of

[[Page 180]]

appendix A of this part, may be used if the percent reduction is 
calculated using the average emission rate from the SO2 
control device and the average SO2 input rate from the ``as 
fired'' fuel analysis for 30 successive boiler operating days.
    (4) The appropriate procedures in Method 19 of appendix A of this 
part shall be used to determine the emission rate.
    (5) The CEMS in Sec. 60.49Da(b) and (d) shall be used to determine 
the concentrations of SO2 and CO2 or 
O2.
    (d) The owner or operator shall determine compliance with the 
NOX standard in Sec. 60.44Da as follows:
    (1) The appropriate procedures in Method 19 of appendix A of this 
part shall be used to determine the emission rate of NOX.
    (2) The continuous monitoring system in Sec. 60.49Da(c) and (d) 
shall be used to determine the concentrations of NOX and 
CO2 or O2.
    (e) The owner or operator may use the following as alternatives to 
the reference methods and procedures specified in this section:
    (1) For Method 5 or 5B of appendix A-3 of this part, Method 17 of 
appendix A-6 of this part may be used at facilities with or without wet 
FGD systems if the stack temperature at the sampling location does not 
exceed an average temperature of 160 [deg]C (320 [deg]F). The procedures 
of sections 8.1 and 11.1 of Method 5B of appendix A-3 of this part may 
be used in Method 17 of appendix A-6 of this part only if it is used 
after wet FGD systems. Method 17 of appendix A-6 of this part shall not 
be used after wet FGD systems if the effluent is saturated or laden with 
water droplets.
    (2) The Fc factor (CO2) procedures in Method 
19 of appendix A of this part may be used to compute the emission rate 
of PM under the stipulations of Sec. 60.46(d)(1). The CO2 
shall be determined in the same manner as the O2 
concentration.
    (f) Electric utility combined cycle gas turbines that are not 
designed to burn fuels containing 50 percent (by heat input) or more 
solid derived fuel not meeting the definition of natural gas are 
performance tested for PM, SO2, and NOX using the 
procedures of Method 19 of appendix A-7 of this part. The SO2 
and NOX emission rates calculations from the gas turbine used 
in Method 19 of appendix A-7 of this part are determined when the gas 
turbine is performance tested under subpart GG of this part. The 
potential uncontrolled PM emission rate from a gas turbine is defined as 
17 ng/J (0.04 lb/MMBtu) heat input.
    (g) For the purposes of determining compliance with the emission 
limits in Sec. 60.45Da, the owner or operator of an electric utility 
steam generating unit which is also a cogeneration unit shall use the 
procedures in paragraphs (g)(1) and (2) of this section to calculate 
emission rates based on electrical output to the grid plus 75 percent of 
the equivalent electrical energy (measured relative to ISO conditions) 
in the unit's process stream.
    (1) All conversions from Btu/hr unit input to MW unit output must 
use equivalents found in 40 CFR 60.40(a)(1) for electric utilities 
(i.e., 250 MMBtu/hr input to an electric utility steam generating unit 
is equivalent to 73 MW input to the electric utility steam generating 
unit); 73 MW input to the electric utility steam generating unit is 
equivalent to 25 MW output from the boiler electric utility steam 
generating unit; therefore, 250 MMBtu input to the electric utility 
steam generating unit is equivalent to 25 MW output from the electric 
utility steam generating unit).
    (2) Use the Equation 5 in this section to determine the cogeneration 
Hg emission rate over a specific compliance period.
[GRAPHIC] [TIFF OMITTED] TR13JN07.016


[[Page 181]]


Where:

ERcogen = Cogeneration Hg emission rate over a compliance 
period in lb/MWh;
E = Mass of Hg emitted from the stack over the same compliance period 
(lb);
Vgrid = Amount of energy sent to the grid over the same 
compliance period (MWh); and
Vprocess = Amount of energy converted to steam for process 
use over the same compliance period (MWh).

    (h) The owner or operator shall determine compliance with the Hg 
limit in Sec. 60.45Da according to the procedures in paragraphs (h)(1) 
through (3) of this section.
    (1) The initial performance test shall be commenced by the 
applicable date specified in Sec. 60.8(a). The required CEMS must be 
certified prior to commencing the test. The performance test consists of 
collecting hourly Hg emission data (lb/MWh) with the CEMS for 12 
successive months of unit operation (excluding hours of unit startup, 
shutdown and malfunction). The average Hg emission rate is calculated 
for each month, and then the weighted, 12-month average Hg emission rate 
is calculated according to paragraph (h)(2) or (h)(3) of this section, 
as applicable. If, for any month in the initial performance test, the 
minimum data capture requirement in Sec. 60.49Da(p)(4)(i) is not met, 
the owner or operator shall report a substitute Hg emission rate for 
that month, as follows. For the first such month, the substitute monthly 
Hg emission rate shall be the arithmetic average of all valid hourly Hg 
emission rates recorded to date. For any subsequent month(s) with 
insufficient data capture, the substitute monthly Hg emission rate shall 
be the highest valid hourly Hg emission rate recorded to date. When the 
12-month average Hg emission rate for the initial performance test is 
calculated, for each month in which there was insufficient data capture, 
the substitute monthly Hg emission rate shall be weighted according to 
the number of unit operating hours in that month. Following the initial 
performance test, the owner or operator shall demonstrate compliance by 
calculating the weighted average of all monthly Hg emission rates (in 
lb/MWh) for each 12 successive calendar months, excluding data obtained 
during startup, shutdown, or malfunction.
    (2) If a CEMS is used to demonstrate compliance, follow the 
procedures in paragraphs (h)(2)(i) through (iii) of this section to 
determine the 12-month rolling average.
    (i) Calculate the total mass of Hg emissions over a month (M), in 
lb, using either Equation 6 in paragraph (h)(2)(i)(A) of this section or 
Equation 7 in paragraph (h)(2)(i)(B) of this section, in conjunction 
with Equation 8 in paragraph (h)(2)(i)(C) of this section.
    (A) If the Hg CEMS measures Hg concentration on a wet basis, use 
Equation 6 below to calculate the Hg mass emissions for each valid hour:
[GRAPHIC] [TIFF OMITTED] TR13JN07.017

Where:

Eh = Hg mass emissions for the hour, (lb);
K = Units conversion constant, 6.24 x 10-\11\ lb-scm/
[micro]gm-scf;
Ch = Hourly Hg concentration, wet basis, 
([micro]gm/scm);
Qh = Hourly stack gas volumetric flow rate, (scfh); and
th = Unit operating time, i.e., the fraction of the hour for 
which the unit operated. For example, th = 0.50 for a half-hour of unit 
operation and 1.00 for a full hour of operation.

    (B) If the Hg CEMS measures Hg concentration on a dry basis, use 
Equation 7 below to calculate the Hg mass emissions for each valid hour:
[GRAPHIC] [TIFF OMITTED] TR13JN07.018

Where:

Eh = Hg mass emissions for the hour, (lb);
K = Units conversion constant, 6.24 x 10-11 lb-scm/[micro]gm-
scf;
Ch = Hourly Hg concentration, dry basis, ([micro]gm/dscm);
Qh = Hourly stack gas volumetric flow rate, (scfh);
th = Unit operating time, i.e., the fraction of the hour for 
which the unit operated; and
Bws = Stack gas moisture content, expressed as a decimal 
fraction (e.g., for 8 percent H2O, Bws = 0.08).

    (C) Use Equation 8, below, to calculate M, the total mass of Hg 
emitted for the month, by summing the hourly masses derived from 
Equation 6 or 7 (as applicable):

[[Page 182]]

[GRAPHIC] [TIFF OMITTED] TR13JN07.019

Where:

M = Total Hg mass emissions for the month, (lb);
Eh = Hg mass emissions for hour ``h'', from Equation 6 or 7 
of this section, (lb); and
n = Number of unit operating hours in the month with valid CE and 
electrical output data, excluding hours of unit startup, shutdown and 
malfunction.

    (ii) Calculate the monthly Hg emission rate on an output basis (lb/
MWh) using Equation 9, below. For a cogeneration unit, use Equation 5 in 
paragraph (g) of this section instead.
[GRAPHIC] [TIFF OMITTED] TR13JN07.020

Where:

ER = Monthly Hg emission rate, (lb/MWh);
M = Total mass of Hg emissions for the month, from Equation 8, above, 
(lb); and
P = Total electrical output for the month, for the hours used to 
calculate M, (MWh).

    (iii) Until 12 monthly Hg emission rates have been accumulated, 
calculate and report only the monthly averages. Then, for each 
subsequent calendar month, use Equation 10 below to calculate the 12-
month rolling average as a weighted average of the Hg emission rate for 
the current month and the Hg emission rates for the previous 11 months, 
with one exception. Calendar months in which the unit does not operate 
(zero unit operating hours) shall not be included in the 12-month 
rolling average.
[GRAPHIC] [TIFF OMITTED] TR13JN07.021

Where:

Eavg = Weighted 12-month rolling average Hg emission rate, 
(lb/MWh);
ERi = Monthly Hg emission rate, for month ``i'', (lb/MWh); 
and
n = Number of unit operating hours in month ``i'' with valid CEM and 
electrical output data, excluding hours of unit startup, shutdown, and 
malfunction.

    (3) If a sorbent trap monitoring system is used in lieu of a Hg 
CEMS, as described in Sec. 75.15 of this chapter and in appendix K to 
part 75 of this chapter, calculate the monthly Hg emission rates using 
Equations 7 through 9 of this section, except that for a particular pair 
of sorbent traps, Ch in Equation 7 shall be the flow-
proportional average Hg concentration measured over the data collection 
period.
    (i) Daily calibration drift (CD) tests and quarterly accuracy 
determinations shall be performed for Hg CEMS in accordance with 
Procedure 1 of appendix F to this part. For the CD assessments, you may 
use either elemental mercury or mercuric chloride (Hg[deg] 
HgCl2) standards. The four quarterly accuracy determinations 
shall consist of one RATA and three measurement error (ME) tests using 
HgCl2 standards, as described in section 8.3 of Performance 
Specification 12-A in appendix B to this part (note: Hg[deg] standards 
may be used if the Hg monitor does not have a converter). Alternatively, 
the owner or operator may implement the applicable daily, weekly, 
quarterly, and annual quality assurance (QA) requirements for Hg CEMS in 
appendix B to part 75 of this chapter, in lieu of the QA procedures in 
appendices B and F to this part. Annual RATA of sorbent trap monitoring 
systems shall be performed in accordance with appendices A and B to part 
75 of this chapter, and all other quality assurance requirements 
specified in appendix K to part 75 of this chapter shall be met for 
sorbent trap monitoring systems.

[72 FR 32722, June 13, 2007, as amended at 74 FR 5083, Jan. 28, 2009]