BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
IN THE MATTER OF:
)
)
R09-10
AMENDMENTS TO 35 ILL. ADM.
)
CODE 225: CONTROL OF EMISSIONS
)
(Rulemaking – Air)
FROM LARGE COMBUSTION SOURCES
)
NOTICE
TO:
John Therriault, Assistant Clerk
Illinois Pollution Control Board
James R. Thompson Center
100 West Randolph St., Suite 11-500
Chicago, IL 60601
SEE ATTACHED SERVICE LIST
PLEASE TAKE NOTICE that I have today filed with the Office of the Pollution Control
Board the ILLINOIS ENVIRONMENTAL PROTECTION AGENCY’S POST-HEARING
COMMENTS TO THE DECEMBER 17, 2008, HEARING ON THE PROPOSAL FOR
AMENDING 35 ILL. ADM. CODE 225, ILLINOIS ENVIRONMENTAL PROTECTION
AGENCY’S SECOND ERRATA SHEET TO ITS PROPOSAL TO AMEND 35 ILL. ADM.
CODE 225 and MOTION FOR WAIVER OF REQUIREMENTS of the Illinois Environmental
Protection Agency a copy of which is herewith served upon you.
ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY
By: ______________________
Charles E. Matoesian
Assistant Counsel
Division of Legal Counsel
DATED: January 14, 2009
1021 North Grand Avenue East
P.O. Box 19276
Springfield, Illinois 62794-9276
THIS FILING IS SUBMITTED
217.782.5544
ON RECYCLED PAPER
217.782.9143 (TDD)
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
IN THE MATTER OF:
)
)
R09-10
PROPOSED AMENDMENTS TO
)
(Rulemaking – Air)
35 ILL. ADM. CODE 225
)
CONTROL OF EMISSIONS FROM
)
LARGE COMBUSTION SOURCES
)
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY’S POST-HEARING
COMMENTS TO THE DECEMBER 17, 2008, HEARING ON THE PROPOSAL
FOR AMENDING 35 ILL. ADM. CODE 225
NOW COMES the ILLINOIS ENVIRONMENTAL PROTECTION AGENCY
(“Illinois EPA”), by its attorneys, and hereby submits its post-hearing comments in the
above rulemaking proceeding. The Illinois EPA has reviewed the transcript of the
December 17, 2008, hearing and responds to the information requests as follows. Other
information requested at the hearing will be addressed in the Illinois EPA’s Second
Errata, filed concurrently with these post-hearing comments:
1. To the information request on Transcript page 27, line 14: The Agency was asked
to identify the sections of the proposed rule that limit a source’s ability to switch
between emissions testing and continuous emissions monitoring systems
(“CEMS”). The Agency identifies Section 225.233(d)(4), Sections 225.239(a)(4),
(d)(6), and (g)(2), Section 225.240(b)(4), and Section 225.294(e)(1)(B) (some of
which are modified by the Agency’s Second Errata).
2. To the information request on Transcript page 25, line 15: The Agency agreed to
consider deferring the December 31, 2008, date in Section 225.220(a)(2)(A), as
the current rulemaking will not be completed by that date. The Agency believes
that the date in the current proposal is appropriate. All of the subject sources have
already submitted their initial permit applications and thus no revision is
necessary.
3. To the information request on Transcript page 18, line 8: The Agency agreed to
identify the rule provisions that allow submission of alternative mercury
monitoring plans. The Agency identifies Section 225.210(b)(1) and (2).
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4. To the information request on Transcript page 80, line 9: The Agency agreed to
address whether a source that obtains a construction permit to install and operate a
sorbent injection system, but subsequently moves the injection sites, must obtain
another construction permit. The Agency responds that, if and when such a
situation arises, the source should contact the Agency and seek guidance
regarding the appropriate way to proceed considering that source’s specific
circumstances. The need for a construction permit or a revised permit will be
dependent on several factors, including any existing permit requirements and the
extent of the proposed changes.
5. To the information request on Transcript page 91, line 13: The Agency agreed to
address whether Section 225.233(d)(4) accomplishes the same purpose as Section
225.233(c)(6). The subsections do not accomplish the same purpose. Section
225.233(c)(6) addresses monitoring, while Section 225.233(d)(4) addresses
compliance with emission limits. In its Second Errata, the Agency has revised
these subsections to further clarify the difference.
6. To the information request on Transcript page 92, line 16: The Agency agreed to
consider amending the date in Section 225.233(f)(5) in light of the dates in
Sections 225.233(f)(1) and (f)(2). The Agency believes that the date in the
current proposal is appropriate. Because CAIR allowances are allocated several
years in advance, such that sources can trade them before the date on the
allowance, even though the rule does not restrict trading until “vintage years 2012
and beyond,” the sources will have those allowances in their accounts probably by
2009 and almost certainly by 2010. Allowances for 2012 and beyond do not need
to be retired until those years, and sources will not necessarily be able to
determine which allowances are available due to overcompliance until that year
has actually passed. However, the report required by Section 225.233(f)(5) asks
for, among other things, “identification of any allowances that were sold, gifted,
used, exchanged, or traded because they became available due to over-
compliance,” and it is possible that sources may be able to make a determination
of such actions ahead of time. Since the report only covers the previous calendar
year, if the Agency does not start getting reports until the 2012 calendar year, the
Agency would not be provided with the necessary information in cases when
trading occurred in 2010 or 2011. Accordingly, it is necessary to have sources
begin submitting reports in 2010, as currently required in the rule.
7. To the information request on Transcript page 146, line 14: The Agency agreed
to look at the interplay between the dates in Section 225.240(b)(1) and (b)(3).
However, there is no actual interplay between the dates in these subsections, as
they deal with two different topics. Section 225.240(b)(1) covers the deadline date
by which monitoring is required for existing sources; (b)(3) deals with the
monitoring date for sources that later add on a control device. Thus, an existing
source needs to begin monitoring with a certified CEMS by July 1, 2009, per the
proposed Agency change to the date (from the original date of January 1, 2009). If
that source then adds a control system described in (b)(3), the modified CEMS
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
has the lesser of 90 unit operating days or 180 calendar days to re-certify the
CEMS.
8. To the information request on Transcript page 172, line 1: The Agency was asked
to review a list to be submitted by Midwest Generation detailing references to
bias adjustment factor and missing data substitution procedures and strike such
references from the proposed rule where appropriate. Midwest Generation
provided such a list, which also included references to records, reports, electronic
data, AETB, NIST, and designated representatives. The Agency deleted or
revised several of the references, as outlined in the Agency’s Second Errata. The
remaining references were kept and/or revised as follows:
A. Section 1.8(a): The Agency is not proposing changes to this Section. The
monitor availability calculations in 40 CFR Part 75, suggested for use here
by Midwest Generation, are to be performed for missing data substitution
calculations for a trading regulation and are not appropriate for this
command and control rule. In addition, those calculations are for annual
calculations, while the Illinois Mercury Rule uses a quarterly standard.
B. Section 1.10(d)(1)(A-I): Revisions were made to remove electronic
reporting. However, the electronic storage of data will be required to be
furnished to the Agency upon request.
C. Section 1.11(a): Revisions were made to remove electronic reporting.
However, the electronic storage of data will be required to be furnished to
the Agency upon request.
D. Section 1.11(b-f): The Agency is not proposing revisions to this Section,
as this decision would be made by the owner/operator and the vendor.
E. Section 1.12(a-b): The Agency is not proposing revisions to this Section.
It does not concern missing data substitution, but rather parametric
monitoring when the mercury CEMS is unavailable.
F. Section 1.13(a)(1-7): Revisions were made to remove electronic
reporting. However, the electronic storage of data will be required to be
furnished to the Agency upon request.
G. Section 1.13(b): The Agency is not proposing revisions to this Section. It
does not concern missing data substitution, but rather parametric
monitoring when the mercury CEMS is unavailable.
H. Section 1.18(a)(1): The Agency is not proposing revisions to this Section,
as this decision would be made by the owner/operator and the vendor.
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
I. Section 1.18(a)(2): The Agency is not proposing revisions to this Section.
It does not concern missing data substitution, but rather parametric
monitoring when the mercury CEMS is unavailable.
J. Section 1.18(e)(1): Revisions were made to remove electronic reporting.
However, the electronic storage of data will be required to be furnished to
the Agency upon request.
K. Section 1.18(f)(1): Revisions were made to remove electronic reporting.
However, the electronic storage of data will be required to be furnished to
the Agency upon request.
L. Section 1.18(f)(1)(B)(iii) and 1.18(f)(2)(B)(ii): The Agency is not
proposing revisions to these subsections. They do not concern missing
data substitution, but rather parametric monitoring when the mercury
CEMS is unavailable.
M. Exhibit A, Section 2.1.3.1: The Agency is not proposing revisions to this
Section. It does not concern missing data substitution, and the value(s) is
needed for calculating the proper span and range of the CEMS.
N. Exhibit A, Section 2.1.3.2: The Agency is not proposing revisions to this
Section. It does not concern missing data substitution, and the value(s) is
needed for calculating the proper span and range of the CEMS.
O. Exhibit A, Section 2.1.3.3(b): The Agency is not proposing revisions to
this Section. It does not concern missing data substitution, and the value(s)
is needed for calculating the proper span and range of the CEMS.
P. Exhibit A, Section 2.1.3.4: The Agency is not proposing revisions to this
Section. It does not concern missing data substitution, and the value(s) is
needed for calculating the proper span and range of the CEMS.
Q. Exhibit A, Section 4: Revisions were made to remove electronic
reporting. However, the electronic storage of data will be required to be
furnished to the Agency upon request.
R. Exhibit A, Section 5.1.9: The Agency is not proposing revisions to this
Section. The Agency believes there will be NIST traceable source
standards for oxidized mercury prior to January 1, 2010.
S. Exhibit A, Section 6.1.2(a-c) and Exhibit B, Section 1.1.4: These
provisions will be stayed indefinitely pending an outcome by the USEPA.
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
T. Exhibit B, Section 1.2.4: The Agency is not proposing revisions to this
Section. It does not concern missing data substitution, but rather
parametric monitoring when the mercury CEMS is unavailable.
U. Exhibit B, Section 2.6: The Agency is not proposing revisions to this
Section. Exhibit A, Section 5.1.9 has already addressed the use of a NIST
traceable source for oxidized mercury standards.
V. Section 1.13(a)(7)(H): “All appropriate data elements for Methods 30A
and 30B” means those data elements, specific for each reference method,
which would be contained in a Relative Accuracy Test Audit report
demonstrating proper execution of the reference method, and proper
calculation and analysis of the raw test data.
9. To the information request on Transcript page 190, line 11: The Agency agreed
to consider changing the date in Section 225.233(f)(5) to May 1. The Agency is
not proposing such a change. The information required under subsection (f)(5) is
different from other information that sources are required to submit to the
Agency, such as information submitted in Title V annual compliance
certifications. There is therefore no overlap and no need for a revision.
10. To the information request on Transcript page 197, line 12: The Agency agreed
to explain the procedural history post-CAMR vacatur (i.e., the date the mandate
vacating CAMR was issued and the issues currently on appeal to the United
States Supreme Court). The federal Clean Air Mercury Rule (“CAMR”) was
challenged by numerous states in the U.S. Court of Appeals for the D.C. Circuit.
The court accepted the petition as
New Jersey v. EPA
. The Utility Air Regulatory
Group (“UARG”) was also a respondent. On February 8, the court issued a
decision vacating the CAMR. The court, based upon the “plain text and structure
of section 112,” vacated EPA’s delisting of mercury from electric generating units
(“EGUs”) from Section 112 of the Clean Air Act (“CAA”). In the court’s view,
this then required “vacation of CAMR’s regulations for both new and existing
EGUs.” On March 14, 2008, the court issued the final mandate vacating CAMR.
Following several unsuccessful petitions for review filed by both UARG and the
USEPA, both respondents separately filed petitions for
writ of certiorari
with the
U.S. Supreme Court for certain issues. The petition by UARG, filed on
September 17, 2008, presented the Supreme Court with two issues:
1. Whether the D.C. Circuit acted contrary to
Chevron
by focusing
solely on the supposed meaning of CAA § 112(c) to find that EPA
must regulate EGUs under CAA §112(d), even though EPA
determined under CAA § 112(n) that such regulation was neither
“appropriate” nor “necessary.”
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
2. Whether an outgoing EPA Administrator may, without notice-
and-comment, require a subsequent Administrator to regulate
EGUs under CAA § 112(d), despite the subsequent
Administrator’s determination after rulemaking that such
regulation is not “appropriate and necessary.”
Petition for a Writ of Certiorari in UARG v. New Jersey
.
On October 17, 2008, the USEPA filed a
writ of certiorari
with the Supreme
Court for the following issue:
Whether the Environmental Protection Agency may remove power
plants from a list of source categories to be regulated under 42
U.S.C. 7412 when it determines that regulation under that
provision is not appropriate or necessary.
Petition for a Writ of Certiorari in EPA v. New Jersey
.
Respondents (New Jersey, et al.) replied on November 24, 2008, by requesting an
extension of time to file responses to the
writs
. On December 1, 2008, the
Supreme Court granted respondents’ requests and extended the deadline for
responses until January 21, 2009.
11. The Agency agreed to consider allowing additional time for sources to submit
original monitoring reports. The Agency is not proposing such a change, as it has
not identified any reports that would require additional time. For example, the
quarterly reports required pursuant to Section 225.290(b) are due 45 days after the
end of a quarter, meaning the first report will not be due until mid-November. If
there is a different report that sources believe requires additional time, the Agency
will consider extending the deadline if such report is identified.
Electronic filing - Received, Clerk's Office, January 14, 2009
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Respectfully submitted,
ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY
Charles E. Matoesian
Assistant Counsel
____________________________________
Dana Vetterhoffer
Assistant Counsel
DATED:
1021 North Grand Avenue East
P.O. Box 19276
Springfield, Illinois 62794-9276
(217) 782-5544
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
IN THE MATTER OF:
)
)
R09-10
PROPOSED AMENDMENTS TO
)
(Rulemaking – Air)
35 ILL. ADM. CODE 225
)
CONTROL OF EMISSIONS FROM
)
LARGE COMBUSTION SOURCES
)
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY’S SECOND ERRATA
SHEET TO ITS PROPOSAL TO AMEND 35 ILL. ADM. CODE 225
NOW COMES the Illinois Environmental Protection Agency (“Illinois EPA” or
“Agency”), by and through its attorneys, and submits this Second Errata Sheet to its
proposal to amend 35 Ill. Adm. Code 225. The Illinois EPA proposes the following
amendments to the text of the rules submitted in its proposal to the Board dated October
2, 2008, and revised by the Agency’s First Errata, submitted to the Board on December 2,
2008:
1.
The Agency proposes amending Section 225.210 to add the acronym QAMO,
resulting from a change to the monitoring calculation provisions (explained under
Second Errata number 5). The Agency also proposes correcting “quality
certification” to “quality control,” which is the proper term.
Section 225.120
Acronyms
QAMO
quality-assured monitor operating
QC
quality control certification
2.
The Agency proposes amending Section 225.130, Definitions, to allow for
changes to the term “Designated Representative” to account for the separation of
the Illinois Mercury Rule and the federal Clean Air Interstate Rule. This was
done in response to questions at the first hearing and to remove any confusion
about the need to refer to federal programs when implementing the Illinois
Mercury Rule. In addition, a definition for the term “Sorbent Trap Monitoring
System” was added to the rule as it was inadvertently left out of the original
proposal. “NIST traceable elemental mercury standards” was amended based
upon United States Environmental Protection Agency (“USEPA”)comments that
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
interim versions of the mercury generator protocols will be issued in early 2009
and are acceptable until final protocols are issued. A definition for “Excepted
Monitoring System” was added to the rule for clarity.
Section 225.130
Definitions
The following definitions apply for the purposes of this Part. Unless otherwise defined in
this Section or a different meaning for a term is clear from its context, the terms used in
this Part have the meanings specified in 35 Ill. Adm. Code 211.
“Designated representative” means, for the purposes of Subpart B of this Part, the
same
natural person as the person who is the designated by the owner or operator
of an EGU, in a letter to the Manager of the Bureau of Air’s Compliance Section,
to be responsible for compliance with Subpart B of this Part, including all
monitoring, reporting, and recordkeeping requirements herein. representative for
the CAIR trading and Acid Rain programs.
***
“Excepted monitoring system” means a sorbent trap monitoring system, as
defined in this section.
***
“NIST traceable elemental mercury standards” means either:
(1) Compressed gas cylinders having known concentrations of elemental mercury,
which have been prepared according to the "EPA Traceability Protocol for Assay
and Certification of Gaseous Calibration Standards"; or
(2) Calibration gases having known concentrations of elemental mercury,
produced by a generator that fully meets the performance requirements of the
"EPA Traceability Protocol for Qualification and Certification of Elemental
Mercury Gas Generators,
" or an interim version of that protocol until such time as
a final protocol is issued.
“NIST traceable source of oxidized mercury” means a generator that is capable of
providing known concentrations of vapor phase mercuric chloride (HgCl2), and
that fully meets the performance requirements of the "EPA Traceability Protocol
for Qualification and Certification of Mercuric Chloride
Oxidized Mercury Gas
Generators," or an interim version of that protocol until such time as a final
protocol is issued
.
***
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
“Sorbent Trap Monitoring System” means the equipment required by Appendix B
of this Part for the continuous monitoring of Hg emissions, using paired sorbent
traps containing iodated charcoal (IC) or other suitable reagents. This excepted
monitoring system consists of a probe, the paired sorbent traps, an umbilical line,
moisture removal components, an air tight sample pump, a gas flow meter, and an
automated data acquisition and handling system. The monitoring system samples
the stack gas at a rate proportional to the stack gas volumetric flowrate. The
sampling is a batch process. Using the sample volume measured by the gas flow
meter and the results of the analyses of the sorbent traps, the average mercury
concentration in the stack gas for the sampling period is determined, in units of
micrograms per dry standard cubic meter (?g/dscm). Mercury mass emissions for
each hour in the sampling period are calculated using the average Hg
concentration for that period, in conjunction with contemporaneous hourly
measurements of the stack gas flow rate, corrected for the stack moisture content.
3.
The Agency proposes amending Section 225.140(a) to more accurately cite the
provisions of the Code of Federal Regulations incorporated by reference. This
was done at the behest of the USEPA for the sake of clarity. The Agency also
proposes amending subsection (c) to incorporate by reference 40 CFR 75, as the
Agency is proposing to add two references to Part 75 in Second Errata number 16
below. In addition, at the request of industry representatives, a new ASTM
standard was added to subsection (h) as an additional means of determining the
mercury content of coal.
Section 225.140
The following materials are incorporated by reference. These incorporations do not
include any later amendments or editions.
a) Appendices
Appendix A-1 through A-8, Subpart A, and Performance
Specifications 2 and 3 of Appendix B of 40 CFR 60 (2005).
***
c)
40 CFR 75.4, 75.11 through 75.14, 75.16 through 75.19, 75.30, 75.34
through 75.37, 75.40 through 75.48, 75.53(e), 75.57(c)(2)(i) through
75.57(c)(2)(vi), 75.60 through 75.67, 75.71, 75.74(c)40 CFR 75 (2006),
Sections 2.1.1.5, 2.1.1.2, 7.7, and 7.8 of Appendix A to 40 CFR 75,
Appendix C to 40 CFR 75, Section 3.3.5 of Appendix F to 40 CFR 75
(2006).
***
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
h)
ASTM. The following methods from the American Society for Testing
and Materials, 100 Barr Harbor Drive, P.O. Box C700, West
Conshohocken PA 19428-2959, (610) 832-9585:
1)
ASTM D388-77 (approved February 25, 1977), D388-90
(approved March 30, 1990), D388-91a (approved April 15, 1991),
D388-95 (approved January 15, 1995), D388-98a (approved
September 10, 1998), or D388-99 (approved September 10, 1999,
reapproved in 2004), Classification of Coals by Rank.
2)
ASTM D3173-03, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke (Approved April 10, 2003).
3)
ASTM D3684-01, Standard Test Method for Total Mercury in
Coal by the Oxygen Bomb Combustion/Atomic Absorption
Method (Approved October 10, 2001).
4)
ASTM D4840-99, Standard Guide for Sampling Chain-of-Custody
Procedures (Reapproved 2004).
5)
ASTM D5865-04, Standard Test Method for Gross Calorific Value
of Coal and Coke (Approved April 1, 2004).
6)
ASTM D6414-01, Standard Test Method for Total Mercury in
Coal and Coal Combustion Residues by Acid Extraction or Wet
Oxidation/Cold Vapor Atomic Absorption (Approved October 10,
2001).
7)
ASTM D6722-01, Standard Test Method for Total Mercury in
Coal and Coal Combustion Residues by Direct Combustion
Analysis (2001).
87)
ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from
Coal-Fired Stationary Sources (Ontario Hydro Method) (Approved
April 10, 2002).
98)
ASTM D6911-03, Standard Guide for Packaging and Shipping
Environmental Samples for Laboratory Analysis.
109)
ASTM D7036-04, Standard Practice for Competence of Air
Emission Testing Bodies.
4.
The Agency proposes amending Section 225.202 to add a new subsection (f) to
reflect the addition of the new ASTM standard, referenced in Second Errata
number 3 above, as an allowable test method for determining the mercury content
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
of coal. The Agency also proposes amending the new subsection (h) to specify the
proper test methods.
Section 225.202
Measurement Methods
Measurement of mercury must be according to the following:
***
f)
ASTM D6722-01, Standard Test Method for Total Mercury in Coal and
Coal Combustion Residues by Direct Combustion Analysis (2001),
incorporated by reference in Section 225.140.
gf)
ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method) (Approved April 10, 2002),
incorporated by reference in Section 225.140.
hg)
Emissions testing pursuant to Methods 29, 30A, and 30B in Appendix A-8
to of 40 CFR 60.
5.
The Agency proposes amending Section 225.230 in response to comments from
USEPA. The Agency has included amendments to remedy issues presented by the
elimination of the data substitution procedures. Because EGUs could potentially
have monitor downtime of up to 25% during a given quarter, allowable emissions
must be based upon emissions that are recorded during quality-assured monitor
operating (“QAMO”) hours. Sources recording emissions for less than 100% of
operating hours cannot calculate an emission rate or control efficiency based on
only the emissions recorded during monitor up time while averaging emissions
over 100% of operating hours. Emission rates and control efficiencies will be
calculated using emissions from QAMO hours and an average of mercury input
or electrical output for a given month based upon the uptime of the monitor
system recording emissions.
Section 225.230
Emission Standards for EGUs at Existing Sources
a)
Emission Standards.
1)
Except as provided in Sections 225.230(b) and (d), 225.232
through 225.234, 225.239, and 225.291 through 225.299 of this
Subpart B, beginning
July 1, 2009, the owner or operator of a
source with one or more EGUs subject to this Subpart B that
commenced commercial operation on or before December 31,
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* * * * * PC #1 * * * * * *
2008, must comply with one of the following standards for each
EGU on a rolling 12-month basis:
A)
An emission standard of 0.0080 lb mercury/GWh gross
electrical output; or
B)
A minimum 90-percent reduction of input mercury.
2)
For an EGU complying with subsection (a)(1)(A) of this Section,
the actual
mercury emission rate during quality-assured monitoring
operating “QAMO” hours of the EGU for each 12-month rolling
period, as monitored in accordance with this Subpart B and
calculated as follows, must not exceed the applicable emission
standard:
∑
=
∑
=
=÷
12
i1
i
12
i1
ER
E
i
O
Where:
ER = Mercury Actual mercury emissions rate of the EGU during
QAMO hours for the particular 12-month rolling period,
expressed in lb/GWh.
E
i
=
Mercury Actual mercury emissions of the EGU during
QAMO hours, in lbs, in an individual month in the 12-
month rolling period, as determined in accordance with the
emissions monitoring provisions of this Subpart B.
O
i
=
Gross electrical output of the EGU during QAMO hours, in
GWh, in an individual month in the 12-month rolling
period, as determined in accordance with Section 225.263
of this Subpart B.
3)
For an EGU complying with subsection (a)(1)(B) of this Section,
the actual control efficiency for mercury emissions achieved by the
EGU for each 12-month rolling period, as monitored in accordance
with this Subpart B and calculated as follows, must meet or exceed
the applicable efficiency requirement:
∑
=
∑
=
=×−
÷
12
i1
i
12
i1
CE 100 {1 (
E
i
I)}
Where:
CE
= Control Actual control efficiency for mercury emissions of
the EGU during QAMO hours
for the particular 12-month
rolling period, expressed as a percent.
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
E
i
=
Mercury Actual mercury emissions of the EGU during
QAMO hours, in lbs, in an individual month in the 12-
month rolling period, as determined in accordance with the
emissions monitoring provisions of this Subpart B.
I
i
=
Amount of mercury in the fuel fired in the EGU during
QAMO hours, in lbs, in an individual month in the 12-
month rolling period, as determined in accordance with
Section 225.265 of this Subpart B. I
i
is determined by
multiplying the amount of mercury in the fuel fired in the
EGU in month
i
by the number of QAMO hours in that
month, and dividing that product by the number of EGU
operating hours in that month.
b)
Alternative Emission Standards for Single EGUs.
1)
As an alternative to compliance with the emission standards in
subsection (a) of this Section, the owner or operator of the EGU
may comply with the emission standards of this Subpart B by
demonstrating that the actual
emissions of mercury from the EGU
are less than the allowable emissions of mercury from the EGU on
a rolling 12-month basis.
2)
For the purpose of demonstrating compliance with the alternative
emission standards of this subsection (b), for each rolling 12-
month period, the actual
emissions of mercury from the EGU, as
monitored in accordance with this Subpart B, must not exceed the
allowable emissions of mercury from the EGU, as further provided
by the following formulas:
E
12
≤
A
12
∑
=
=
12
i1
E
12
E
i
∑
=
=
12
i1
A
12
A
i
Where:
E
12
= Mercury Actual mercury emissions of the EGU during
QAMO hours for the particular 12-month rolling period.
A
12
= Allowable mercury emissions of the EGU during QAMO
hours for the particular 12-month rolling period.
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E
i
= Mercury Actual mercury emissions of the EGU during
QAMO hours in an individual month in the 12-month rolling
period.
A
i
= Allowable mercury emissions of the EGU during QAMO
hours in an individual month in the 12-month rolling period, based
on either the input mercury to the unit (A
Input i
) or the electrical
output from the EGU (A
Output i
), as selected by the owner or
operator of the EGU for that given month. A
i
is determined by
multiplying the allowable mercury emissions based on either input
mercury or electrical output in month i by the number of QAMO
hours in that month, and dividing that product by the number of
EGU operating hours in that month.
A
Input i
= Allowable mercury emissions of the EGU in an individual
month based on the input mercury to the EGU, calculated as 10.0
percent (or 0.100) of the input mercury to the EGU.
A
Output i
= Allowable mercury emissions of the EGU in a particular
month based on the electrical output from the EGU, calculated as
the product of the output based mercury limit, i.e., 0.0080 lb/GWh,
and the electrical output from the EGU, in GWh.
3)
If the owner or operator of an EGU does not conduct the necessary
sampling, analysis, and recordkeeping, in accordance with Section
225.265 of this Subpart B, to determine the mercury input to the
EGU, the allowable emissions of the EGU must be calculated
based on the electrical output of the EGU.
c)
If two or more EGUs are served by common stack(s) and the owner or
operator conducts monitoring for mercury emissions in the common
stack(s), as provided for by Sections 1.14 through 1.18 of Appendix B to
this Part, such that the mercury emissions of each EGU are not determined
separately, compliance of the EGUs with the applicable emission
standards of this Subpart B must be determined as if the EGUs were a
single EGU.
d)
Alternative Emission Standards for Multiple EGUs.
1)
As an alternative to compliance with the emission standards of
subsection (a) of this Section, the owner or operator of a source
with multiple EGUs may comply with the emission standards of
this Subpart B by demonstrating that the actual
emissions of
mercury from all EGUs at the source during QAMO hours are less
than the allowable emissions of mercury from all EGUs at the
source on a rolling 12-month basis.
2)
For the purposes of the alternative emission standard of subsection
(d)(1) of this Section, for each rolling 12-month period, the actual
emissions of mercury from all the EGUs at the source during
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QAMO hours, as monitored in accordance with this Subpart B,
must not exceed the sum of the allowable emissions of mercury
from all the EGUs at the source, as further provided by the
following formulas:
E
S
≤
A
S
∑
=
=
n
i1
E
S
E
i
∑
=
=
n
i1
A
S
A
i
Where:
E
S
= Sum of the actual mercury emissions of the EGUs at the
source during QAMO hours.
A
S
= Sum of the allowable mercury emissions of the EGUs at the
source during QAMO hours.
E
i
= Mercury Actual mercury emissions of an individual EGU at
the source during QAMO hours
, as determined in accordance with
subsection (b)(2) of this Section.
A
i
= Allowable mercury emissions of an individual EGU at the
source during QAMO hours, as determined in accordance with
subsection (b)(2) of this Section.
n = Number of EGUs covered by the demonstration.
3)
If an owner or operator of a source with two or more EGUs that is
relying on this subsection (d) to demonstrate compliance fails to
meet the requirements of this subsection (d) in a given 12-month
rolling period, all EGUs at such source covered by the compliance
demonstration are considered out of compliance with the
applicable emission standards of this Subpart B for the entire last
month of that period.
6.
The Agency proposes amending Section 225.232 to remove the word “actual.”
This was necessitated by the changes to the calculations in Section 225.230.
Section 225.232
Averaging Demonstrations for Existing Sources
a)
Through December 31, 2013, as an alternative to compliance with the
emission standards of Section 225.230(a) of this Subpart B, the owner or
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operator of an EGU may comply with the emission standards of this
Subpart B by means of an Averaging Demonstration (Demonstration) that
demonstrates that the actual emissions of mercury from the EGU and other
EGUs at the source and other EGUs at other sources covered by the
Demonstration are less than the allowable emissions of mercury from all
EGUs covered by the Demonstration on a rolling 12-month basis.
7.
The Agency proposes amending Section 225.233 in several places. First, the
Agency proposes amending subsection 225.233(c)(6) to clarify the ability to use
an excepted monitoring system and clarify that the sunset date of June 30, 2012,
applies. This was inadvertently left out of the proposal. Second, in response to a
request on pages 88-89 of the Transcript of the December 17, 2008, hearing, the
Agency proposes amending subsection 225.233(d)(3) to clarify that EGUs in the
MPS may utilize the averaging provisions set forth in Section 225.232 until
December 31, 2013. The Agency also proposes amending subsection
225.233(d)(4) to provide the proper citation to emission testing in Section
225.239. Finally, the Agency proposes amending subsection 225.233(f)(4)
consistent with the terms and conditions agreed to by the affected sources in their
multi-pollutant reduction agreements with the Agency regarding the treatment of
NOx and SO2 allowances. This revision is necessary due to the uncertainty
surrounding the future of the federal CAIR as adopted by Illinois in Sections
225.310, 225.410, or 225.510. The CAIR was reinstated on December 23, 2008
and remanded back to USEPA with instructions to fix the rule, however, no
deadline was imposed upon USEPA under which to accomplish this task. It is
envisioned that either a new or modified version of CAIR will be forthcoming
from USEPA.
Section 225.233(c)(6) -
Multi-Pollutant Standards (MPS)
6)
Until June 30, 2012, as As an alternative to the CEMS or excepted
monitoring system (sorbent trap system) monitoring,
recordkeeping, and reporting requirements in Sections 225.240
through 225.290, the owner or operator of an EGU may elect to
comply with the emissions testing, monitoring, recordkeeping, and
reporting requirements in Section 225.239(c), (d), (e), (f)(1) and
(2), (h)(2), (i)(3) and (4), and (j)(1).
***
d)
Emission Standards for Mercury.
1)
For each EGU in an MPS Group that is not addressed by
subsection (c)(1)(B) of this Section, beginning January 1, 2015 (or
such earlier date when the owner or operator of the EGU notifies
the Agency that it will comply with these standards) and
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continuing thereafter, the owner or operator of the EGU must
comply with one of the following standards on a rolling 12-month
basis:
A)
An emission standard of 0.0080 lb mercury/GWh gross
electrical output; or
B)
A minimum 90-percent reduction of input mercury.
2)
For each EGU in an MPS Group that has been addressed under
subsection (c)(1)(B) of this Section, beginning on the date when
the owner or operator of the EGU notifies the Agency that it will
comply with these standards and continuing thereafter, the owner
or operator of the EGU must comply with one of the following
standards on a rolling 12-month basis:
A)
An emission standard of 0.0080 lb mercury/GWh gross
electrical output; or
B)
A minimum 90-percent reduction of input mercury.
3)
Compliance with the mercury emission standard or reduction
requirement of this subsection (d) must be calculated in accordance
with Section 225.230(a) or (d), or Section 225.232 until December
31, 2013.
4)
Until June 30, 2012, as an alternative to demonstrating compliance
with the emissions standards in this subsection (d), the owner or
operator of an EGU may elect to comply with the emissions testing
requirements in Section 225.239(a)(4), (b),
(c), (d), (e), (f)(1) and
(2), (g), (h)(2), (i)(3) and (4), and (j)(1) of this Subpart.
e)
Emission Standards for NO
x
and SO
2
.
1)
NO
x
Emission Standards.
A)
Beginning in calendar year 2012 and continuing in each
calendar thereafter, for the EGUs in each MPS Group, the
owner and operator of the EGUs must comply with an
overall NOx annual emission rate of no more than 0.11
lb/million Btu or an emission rate equivalent to 52 percent
of the Base Annual Rate of NO
x
emissions, whichever is
more stringent.
B)
Beginning in the 2012 ozone season and continuing in each
ozone season thereafter, for the EGUs in each MPS Group,
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the owner and operator of the EGUs must comply with an
overall NO
x
seasonal emission rate of no more than 0.11
lb/million Btu or an emission rate equivalent to 80 percent
of the Base Seasonal Rate of NO
x
emissions, whichever is
more stringent.
2)
SO
2
Emission Standards.
A)
Beginning in calendar year 2013 and continuing in calendar
year 2014, for the EGUs in each MPS Group, the owner
and operator of the EGUs must comply with an overall SO
2
annual emission rate of 0.33 lbs/million Btu or a rate
equivalent to 44 percent of the Base Rate of SO
2
emissions,
whichever is more stringent.
B)
Beginning in calendar year 2015 and continuing in each
calendar year thereafter, for the EGUs in each MPS
Grouping, the owner and operator of the EGUs must
comply with an overall annual emission rate for SO
2
of
0.25 lbs/million Btu or a rate equivalent to 35 percent of the
Base Rate of SO
2
emissions, whichever is more stringent.
3)
Compliance with the NO
x
and SO
2
emission standards must be
demonstrated in accordance with Sections 225.310, 225.410, and
225.510. The owner or operator of EGUs must complete the
demonstration of compliance before March 1 of the following year
for annual standards and before November 1 for seasonal
standards, by which date a compliance report must be submitted to
the Agency.
f)
Requirements for NO
x
and SO
2
Allowances.
1)
The owner or operator of EGUs in an MPS Group must not sell or
trade to any person or otherwise exchange with or give to any
person NO
x
allowances allocated to the EGUs in the MPS Group
for vintage years 2012 and beyond that would otherwise be
available for sale, trade, or exchange as a result of actions taken to
comply with the standards in subsection (e) of this Section. Such
allowances that are not retired for compliance must be surrendered
to the Agency on an annual basis, beginning in calendar year 2013.
This provision does not apply to the use, sale, exchange, gift, or
trade of allowances among the EGUs in an MPS Group.
2)
The owners or operators of EGUs in an MPS Group must not sell
or trade to any person or otherwise exchange with or give to any
person SO
2
allowances allocated to the EGUs in the MPS Group
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for vintage years 2013 and beyond that would otherwise be
available for sale or trade as a result of actions taken to comply
with the standards in subsection (e) of this Section. Such
allowances that are not retired for compliance, or otherwise
surrendered pursuant to a consent decree to which the State of
Illinois is a party, must be surrendered to the Agency on an annual
basis, beginning in calendar year 2014. This provision does not
apply to the use, sale, exchange, gift, or trade of allowances among
the EGUs in an MPS Group.
3)
The provisions of this subsection (f) do not restrict or inhibit the
sale or trading of allowances that become available from one or
more EGUs in a MPS Group as a result of holding allowances that
represent over-compliance with the NO
x
or SO
2
standard in
subsection (e) of this Section, once such a standard becomes
effective, whether such over-compliance results from control
equipment, fuel changes, changes in the method of operation, unit
shut downs, or other reasons.
4)
For purposes of this subsection (f), NO
x
and SO
2
allowances mean
allowances necessary for compliance with Sections 225.310,
225.410, or 225.510,Subpart W of Section 217 (NO
x
Trading
Program for Electrical Generating Units), 40 CFR 72, or Subparts
AA and AAAA through I of 40 CFR 96, or any future federal NO
x
or SO
2
emissions trading programs that modify or replace these
programs.include Illinois sources. This Section does not prohibit
the owner or operator of EGUs in an MPS Group from purchasing
or otherwise obtaining allowances from other sources as allowed
by law for purposes of complying with federal or state
requirements, except as specifically set forth in this Section.
5)
Before March 1, 2010, and continuing each year thereafter, the
owner or operator of EGUs in an MPS Group must submit a report
to the Agency that demonstrates compliance with the requirements
of this subsection (f) for the previous calendar year, and which
includes identification of any allowances that have been
surrendered to the USEPA or to the Agency and any allowances
that were sold, gifted, used, exchanged, or traded because they
became available due to over-compliance. All allowances that are
required to be surrendered must be surrendered by August 31,
unless USEPA has not yet deducted the allowances from the
previous year. A final report must be submitted to the Agency by
August 31 of each year, verifying that the actions described in the
initial report have taken place or, if such actions have not taken
place, an explanation of all changes that have occurred and the
reasons for such changes. If USEPA has not deducted the
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allowances from the previous year by August 31, the final report
willmust be due, and all allowances required to be surrendered
must be surrendered, within 30 days after such deduction occurs.
g)
Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied
with the applicable emission standards of subsections (d) and (e) of this Section
for 12 months, the owner or operator of the EGU must obtain a construction
permit for any new or modified air pollution control equipment that it proposes to
construct for control of emissions of mercury, NO
x
, or SO
2
.
8.
In response to a request at the December 17, 2008, hearing that the Agency
clarify whether references to “CEMS” include sorbent trap monitoring systems as
well, the Agency proposes amending Section 225.234(a)(4) to include a reference
to excepted monitoring systems. Also, the Agency proposes amending subsection
(b)(3)(B) to remove an extra “the” that was inadvertently left in the proposal.
Section 225.234(a)(4)
4)
Until June 30, 2012, as an alternative to the CEMS monitoring (or
an excepted monitoring system), recordkeeping, and reporting
requirements in Sections 225.240 through 225.290, the owner or
operator of an EGU may elect to comply with the emissions
testing, monitoring, recordkeeping, and reporting requirements in
Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), (i)(3) and (4),
and (j)(1).
Section 225.234(b)(3)(B)
B)
For the owner or operator of only a single existing source
with EGUs (i.e., City, Water, Light & Power, City of
Springfield, ID 167120AAO; Kincaid Generating Station,
ID 021814AAB; and Southern Illinois Power
Cooperative/Marion Generating Station, ID 199856AAC),
25 percent of the total rated capacity, in MW, of the
all the
EGUs at the existing sources, other than any EGUs
operating pursuant to Section 225.235.
9.
In response to a request at the December 17, 2008, hearing that the Agency
clarify whether references to “CEMS” include sorbent trap monitoring systems as
well, the Agency proposes amending Section 225.237(b) to include a reference to
excepted monitoring systems.
Section 225.237(b)
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b)
The initial 12-month rolling period for which compliance with the
emission standards of subsection (a)(1) of this Section must be
demonstrated for a new EGU will commence on the date that the initial
performance testing commences under 40 CFR 60.8. The CEMS (or
excepted monitoring system) monitoring required by this Subpart B for
mercury emissions from the EGU must be certified prior to this date.
Thereafter, compliance must be demonstrated on a rolling 12-month basis
based on calendar months.
10.
In response to a request at the December 17, 2008, hearing that the Agency
clarify whether references to “CEMS” include sorbent trap monitoring systems as
well, the Agency proposes amending Section 225.238(a)(4) to include a reference
to excepted monitoring systems.
Section 225.238(a)(4)
4)
Until June 30, 2012, as an alternative to the CEMS (or excepted
monitoring system) monitoring, recordkeeping, and reporting
requirements in Sections 225.240 through 225.290, the owner or
operator of an EGU may elect to comply with the emissions
testing, monitoring, recordkeeping, and reporting requirements in
Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), (i)(3) and (4),
and (j)(1).
11.
The Agency proposes amending Section 225.239 in several places. First, in
response to a request at the December 17, 2008, hearing that the Agency clarify
whether references to “CEMS” include sorbent trap monitoring systems as well,
the Agency proposes amending Section 225.239 to include references to excepted
monitoring systems. Next, in response to a request for clarification at hearing,
the Agency proposes amending subsection (a)(4) to specify that such subsection
applies to EGUs in the MPS and CPS. Next, subsection 225.239(d)(2) is being
amended to specify that EGUs in the MPS and CPS that opt into either the 0.0080
lb mercury/GWh gross electric output emission limit or 90% control efficiency
requirement early are excepted from performing emissions testing on a semi-
annual calendar basis, and instead must perform such testing on a quarterly
basis. This amendment corrects an error in the Agency’s original proposal
regarding the frequency of emissions testing for MPS/CPS sources that opt into
an emissions standard early.
The Agency further proposes amending Section 225.239(e)(3) to clarify that
EGUs in the MPS or CPS complying with the 90% control efficiency requirement
and electing to demonstrate compliance pursuant to the emissions testing
requirements in Section 225.239 are included in the group that must perform coal
sampling according to the schedule set forth in subsection (e)(3).
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In addition, the Agency proposes amending Section 225.239(f)(4) to specify that
EGUs in the MPS or CPS that opt into either the 0.0080 lb/GWh emission limit or
the 90% control efficiency requirement early and that elect to demonstrate
compliance pursuant to the emissions testing requirements in Section 225.239
must submit a Continuous Parameter Monitoring Plan. Similarly, the Agency
proposes amending Section 225.239(h)(2) to specify that such EGUs must submit
an updated Continuous Parameter Monitoring Plan following a significant
change.
In response to a request on pages 146-147 of the Transcript of the December 17,
2008, hearing that the Agency clarify what is meant by a “significant change,”
the Agency proposes amending Section 225.239(h)(2) to specify that any “change
that would render the most recent test no longer representative of current
operations according to the parameters listed in the Continuous Parameter
Monitoring Plan,” is a significant change. Also in response to a request at
hearing, the Agency proposes amending subsection (h)(2) to give sources
additional time to perform an emissions test following a significant change.
Section 225.239(i)(2)(A) is being amended to require use of parts per million
rather than pounds per trillion BTUs when recording the daily mercury content of
coal used.
Finally, in response to a request at hearing, the Agency proposes amending
Section 225.239(i)(4) to require that records be retained for five years.
Section 225.239
Periodic Emissions Testing Alternative Requirements
a)
General.
1)
As an alternative to demonstrating compliance with the emissions
standards of Sections 225.230(a) or 225.237(a), the owner or
operator of an EGU may elect to demonstrate compliance pursuant
to the emission standards in subsection (b) of this Section and the
use of quarterly emissions testing as an alternative to the use of
CEMS or an excepted monitoring system
;
2)
The owner or operator of an EGU that elects to demonstrate
compliance pursuant to this Section must comply with the testing,
recordkeeping, and reporting requirements of this Section in
addition to other applicable recordkeeping and reporting
requirements in this Subpart;
3)
The alternative method of compliance provided under this
subsection may only be used until June 30, 2012, after which a
CEMS (or an excepted monitoring system)
certified in accordance
with Section 225.250 of this Subpart B must be used.
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4)
If an owner or operator of an EGU demonstrating compliance
pursuant to Section 225.230, 225.233(d)(1) or (2), or 225.237, or
225.294(e)(1)(A) discontinues use of CEMS (or an excepted
monitoring system) before collecting a full 12 months of CEMS
data and elects to demonstrate compliance pursuant to this Section,
the data collected prior to that point must be averaged to determine
compliance for such period. In such case, for purposes of
calculating an emission standard or mercury control efficiency
using the equations in Section 225.230(a) or (b), the “12” in the
equations will be replaced by a variable equal to the number of full
and partial months for which the owner or operator collected data
from a CEMS data. or an excepted monitoring system.
b)
Emission Limits.
1)
Existing Units: Beginning July 1, 2009, the owner or operator of a
source with one or more EGUs subject to this Subpart B that
commenced commercial operation on or before June 30, 2009,
must comply with one of the following standards for each EGU, as
determined through quarterly emissions testing according to
subsections (c), (d), (e), and (f) of this Section:
A)
An emission standard of 0.0080 lb mercury/GWh gross
electrical output; or
B)
A minimum 90-percent reduction of input mercury.
2)
New Units: Beginning within the first 2,160 hours after the
commencement of commercial operations, the owner or operator
of a source with one or more EGUs subject to this Subpart B that
commenced commercial operation after June 30, 2009, must
comply with one of the following standards for each EGU, as
determined through quarterly emissions testing in accordance with
subsections (c), (d), (e), and (f) of this Section:
A)
An emission standard of 0.0080 lb mercury/GWh gross
electrical output; or
B)
A minimum 90-percent reduction of input mercury.
c)
Initial Emissions Testing Requirements for New Units. The owner or
operator of an EGU that commenced commercial operation after June 30,
2009, and that is complying by means of this Section must conduct an
initial performance test in accordance with the requirements of subsections
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(d) and (e) of this Section within the first 2,160 hours after the
commencement of commercial operations.
d)
Emissions Testing Requirements
1)
Subsequent to the initial performance test, emissions tests must be
performed on a quarterly calendar basis in accordance with the
requirements of subsections (d), (e), and (f) of this Section;
2)
Notwithstanding the provisions in subparagraph (1) of this
subsection, owners or operators of EGUs demonstrating
compliance under Section 225.233 or Sections 225.291 through
225.299, and which have not opted in to the emission limit
provisions of Section 225.233(d)(1) or (d)(2), or Section
225.294(c) pursuant to Section 225.294(e)(1)(B), must perform
emissions testing on a semi-annual calendar basis, where the
periods consist of the months of January through June and July
through December, in accordance with the requirements of
subsections (d), (e), and (f)(1) and (2) of this Section;
3)
Emissions tests which demonstrate compliance with this Subpart
must be performed at least 45 days apart. However, if an emissions
test fails to demonstrate compliance with this Subpart or the
emissions test is being performed subsequent to a significant
change in the operations of an EGU under subsection (h)(2) of this
Section, the owner or operator of an EGU may perform additional
emissions test(s) using the same test protocol previously submitted
in the same period, with less than 45 days in between emissions
tests;
4)
A minimum of three and a maximum of nine emissions test runs,
lasting at least one hour each, shall be conducted and averaged to
determine compliance. All test runs performed will be reported.
5)
If the EGU shares a common stack with one or more other EGUs,
the owner or operator of the EGU will conduct emissions testing in
the duct to the common stack from each unit, unless the owner or
operator of the EGU considers the combined emissions measured
at the common stack as the mass emissions of mercury for the
EGUs for recordkeeping and compliance purposes.
6)
If an owner or operator of an EGU demonstrating compliance
pursuant to this Section later elects to demonstrate compliance
pursuant to the CEMS monitoring provisions (or excepted
monitoring system provisions) in Section 225.240 of this Subpart,
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the owner or operator must comply with the emissions monitoring
deadlines in Section 225.240(b)(4) of this Subpart.
e)
Emissions Testing Procedures
1)
The owner or operator must conduct a compliance test in
accordance with Method 29, 30A, or 30B of 40 CFR 60, Appendix
A, as incorporated by reference in Section 225.140;
2)
Mercury emissions or control efficiency must be measured while
the affected unit is operating at or above 90% of peak load;
3)
For units complying with the control efficiency standard of
subsection (b)(1)(B) or (b)(2)(B) of this Section, Section
225.233(d)(1)(B) or (d)(2)(B) and electing to demonstrate
compliance pursuant to Section 225.233(d)(4), or Section
225.294(c)(2) pursuant to Section 225.294(e)(1)(B), the owner or
operator must perform coal sampling as follows:
A)
in accordance with Section 225.265 of this Subpart at least
once during each day of testing; and
B)
in accordance with Section 225.265 of this Subpart, once
each month in those months when emissions testing is not
performed unless the boiler did not operate or combust coal
at all during that month;
4)
For units complying with the output-based emission standard of
subsection (b)(1)(A) or (b)(2)(A) of this Section, the owner or
operator must monitor gross electrical output for the duration of
the testing.
5)
The owner or operator of an EGU may use an alternative emissions
testing method if such alternative is submitted to the Agency in
writing and approved in writing by the Manager of the Bureau of
Air’s Compliance Section.
f)
Notification Requirements
1)
The owner or operator of an EGU must submit a testing protocol as
described in USEPA’s Emission Measurement Center’s Guideline
Document #42 to the Agency at least 45 days prior to a scheduled
emissions test, except as provided in Section 225.239(h)(2) and
(h)(3). Upon written request directed to the Manager of the Bureau
of Air’s Compliance Section, the Agency may, in its sole
discretion, waive the 45-day requirement. Such waiver shall only
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be effective if it is provided in writing and signed by the Manager
of the Bureau of Air’s Compliance Section, or his or her designee;
2)
Notification of a scheduled emissions test must be submitted to the
Agency in writing, directed to the Manager of the Bureau of Air’s
Compliance Section, at least 30 days prior to the expected date of
the emissions test. Upon written request directed to the Manager of
the Bureau of Air’s Compliance Section, the Agency may, in its
sole discretion,
waive the 30-day notification requirement. Such
waiver shall only be effective if it is provided in writing and signed
by the Manager of the Bureau of Air’s Compliance Section, or his
or her designee. Notification of the actual date and expected time
of testing must be submitted in writing, directed to the Manager of
the Bureau of Air’s Compliance Section, at least five working days
prior to the actual date of the test;
3)
For an EGU that has elected to demonstrate compliance by use of
the emission standards of subsection (b) of this Section, if an
emissions test performed under the requirements of this Section
fails to demonstrate compliance with the limits of subsection (b) of
this Section, the owner or operator of an EGU may perform a new
emissions test using the same test protocol previously submitted in
the same period, by notifying the Manager of the Bureau of Air’s
Compliance Section or his or her designee of the actual date and
expected time of testing at least five working days prior to the
actual date of the test. The Agency may, in its sole discretion,
waive this five-day notification requirement. Such waiver shall
only be effective if it is provided in writing and signed by the
Manager of the Bureau of Air’s Compliance Section, or his or her
designee;
4)
In addition to the testing protocol required by subsection (f)(1) of
this Section, the owner or operator of an EGU that has elected to
demonstrate compliance by use of the emission standards of
subsection (b) of this Section, that opts into Section 225.233(d)(1)
or (d)(2) early and elects to demonstrate compliance pursuant to
Section 225.233(d)(4), or that opts into Section 225.294(c)
pursuant to Section 225.294(e)(1)(B), must submit a Continuous
Parameter Monitoring Plan to the Agency at least 45 days prior to
a scheduled emissions test. Upon written request directed to the
Manager of the Bureau of Air’s Compliance Section, the Agency
may, in its sole discretion, waive the 45-day requirement. Such
waiver shall only be effective if it is provided in writing and signed
by the Manager of the Bureau of Air’s Compliance Section, or his
or her designee. The Continuous Parameter Monitoring Plan must
detail how the EGU will continue to operate within the parameters
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enumerated in the testing protocol and how those parameters will
ensure compliance with the applicable mercury limit. For example,
the Continuous Parameter Monitoring Plan must include coal
sampling as described in Section 225.239(e)(3) of this Subpart and
must ensure that an EGU that performs an emissions test using a
blend of coals continues to operate using that same blend of coal.
If the Agency disapproves the Continuous Parameter Monitoring
Plan, the owner or operator of the EGU has 30 days from the date
of receipt of the disapproval to submit more detailed information in
accordance with the Agency’s request.
g)
Compliance Determination
1)
Each quarterly emissions test shall determine compliance with this
Subpart for that quarter, where the quarterly periods consist of the
months of January through March, April through June, July
through September, and October through December;
2)
If emissions testing conducted pursuant to this Section fails to
demonstrate compliance, the owner or operator of the EGU will be
deemed to have been out of compliance with this Subpart
beginning on the day after the most recent emissions test that
demonstrated compliance or the last day of certified CEMS data
(or certified data from an excepted monitoring system)
demonstrating compliance on a rolling 12-month basis, and the
EGU will remain out of compliance until a subsequent emissions
test successfully demonstrates compliance with the limits of this
Section.
h)
Operation Requirements
1)
The owner or operator of an EGU that has elected to demonstrate
compliance by use of the emission standards of subsection (b) of
this Section must continue to operate the EGU commensurate with
the Continuous Parameter Monitoring Plan until another
Continuous Parameter Monitoring Plan is developed and submitted
to the Agency in conjunction with the next compliance
demonstration, in accordance with subsection (f)(4) of this Section.
2)
If the owner or operator makes a significant change to the
operations of an EGU subject to this Section, such as changing
from bituminous to subbituminous coal or any other change that
would render the most recent test no longer representative of
current operations according to the parameters listed in the
Continuous Parameter Monitoring Plan, the owner or operator
must submit a testing protocol to the Agency and perform an
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emissions test within seven operating days of the significant
change and perform an emissions test within 30 days of the change
if the change takes place more than 30 days before the end of the
current calendar quarter, or within 30 days of the beginning of the
new quarter if the change takes place less than 30 days before the
end of the current calendar quarter. In addition, the owner or
operator of an EGU that has elected to demonstrate compliance by
use of the emission standards of subsection (b) of this Section,
Section 225.233(d)(1) or (d)(2), or Section 225.294(c) pursuant to
Section 225.294(e)(1)(B) must submit an a updated Continuous
Parameter Monitoring Plan within seven operating days of the
significant change.
3)
If a blend of bituminous and subbituminous coal is fired in the
EGU, the owner or operator of the EGU must ensure that the EGU
continues to operate using the same blend that was used during the
most recent successful emissions test. If the blend of coal changes,
the owner or operator of the EGU must re-test in accordance with
subsections (d), (e), (f), and (g) of this Section within 30 days of
the change in coal blend, notwithstanding the requirement of
subsection (d)(3) of this Section that there must be 45 days
between emissions tests.
i)
Recordkeeping
1)
The owner or operator of an EGU and its designated representative
must comply with all applicable recordkeeping and reporting
requirements in this Section.
2)
Continuous Parameter Monitoring. The owner or operator of an
EGU must maintain records to substantiate that the EGU is
operating in compliance with the parameters listed in the
Continuous Parameter Monitoring Plan, detailing the parameters
that impact mercury reduction and including the following records
related to the emissions of mercury:
A)
For an EGU for which the owner or operator is complying
with this Subpart B pursuant to Section 225.239(b)(1)(B) or
225.239(b)(2)(B), records of the daily mercury content of
coal used (parts per millionlbs/trillion
Btu) and the daily
and quarterly input mercury (lbs).
B)
For an EGU for which the owner or operator of an EGU
complying with this Subpart B pursuant to Section
225.239(b)(1)(A) or 225.239(b)(2)(A), records of the daily
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and quarterly gross electrical output (MWh) on an hourly
basis.:
3)
The owner or operator of an EGU using activated carbon injection
must also comply with the following requirements:
A)
Maintain records of the usage of sorbent, the exhaust gas
flow rate from the EGU, and the sorbent feed rate, in
pounds per million actual cubic feet of exhaust gas at the
injection point, on a weekly average;
B)
If a blend of bituminous and subbituminous coal is fired in
the EGU, keep records of the amount of each type of coal
burned and the required injection rate for injection of
activated carbon, on a weekly basis.
4)
The owner or operator of an EGU must retain all records required
by this Section at the source for a period of five years from the date
the document is created unless otherwise provided in the CAAPP
permit issued for the source and must make a copy of any record
available to the Agency promptly upon request. This period may
be extended in writing by the Agency, for cause, at any time prior
to the end of five years.
5)
The owner or operator of an EGU demonstrating compliance
pursuant to this Section must monitor and report the heat input rate
at the unit level.
6)
The owner or operator of an EGU demonstrating compliance
pursuant to this Section must perform and report coal sampling in
accordance with subsection 225.239(e)(3).
j)
Reporting Requirements
1)
An owner or operator of an EGU shall submit to the Agency a
Final Source Test Report for each periodic emissions test within 45
days after the test is completed. The Final Source Test Report will
be directed to the Manager of the Bureau of Air’s Compliance
Section, or his or her designee, and include at a minimum:
A)
A summary of results;
B)
A description of test method(s), including a description of
sampling points, sampling train, analysis equipment, and
test schedule, and a detailed description of test conditions,
including:
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i)
Process information, including but not limited to
mode(s) of operation, process rate, and fuel or raw
material consumption;
ii)
Control equipment information (i.e., equipment
condition and operating parameters during testing);
iii)
A discussion of any preparatory actions taken (i.e.,
inspections, maintenance, and repair); and
iv)
Data and calculations, including copies of all raw
data sheets and records of laboratory analyses,
sample calculations, and data on equipment
calibration.
2)
The owner or operator of a source with one or more EGUs
demonstrating compliance with Subpart B in accordance with this
Section must submit to the Agency a Quarterly Certification of
Compliance within 45 days following the end of each calendar
quarter. Quarterly certifications of compliance must certify
whether compliance existed for each EGU for the calendar quarter
covered by the certification. If the EGU failed to comply during
the quarter covered by the certification, the owner or operator must
provide the reasons the EGU or EGUs failed to comply and a full
description of the noncompliance (i.e., tested emissions rate, coal
sample data, etc.). In addition, for each EGU, the owner or
operator must provide the following appropriate data to the
Agency as set forth in this Section.
A)
A list of all emissions tests performed within the calendar
quarter covered by the Certification and submitted to the
Agency for each EGU, including the dates on which such
tests were performed.
B)
Any deviations or exceptions each month and discussion of
the reasons for such deviations or exceptions.
C)
All Quarterly Certifications of Compliance required to be
submitted must include the following certification by a
responsible official:
I certify under penalty of law that this document and all
attachments were prepared under my direction or
supervision in accordance with a system designed to assure
that qualified personnel properly gather and evaluate the
information submitted. Based on my inquiry of the person
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or persons directly responsible for gathering the
information, the information submitted is, to the best of my
knowledge and belief, true, accurate, and complete. I am
aware that there are significant penalties for submitting
false information, including the possibility of fine and
imprisonment for knowing violations.
3)
Deviation Reports. For each EGU, the owner or operator must
promptly notify the Agency of deviations from any of the
requirements of this Subpart B. At a minimum, these notifications
must include a description of such deviations within 30 days after
discovery of the deviations, and a discussion of the possible cause
of such deviations, any corrective actions, and any preventative
measures taken.
12.
The Agency proposes deleting subsection (c)(2) of Section 225.240, as the
subsection is redundant. The Agency also proposes deleting the title of subsection
(c), as it does not accurately reflect the content of the subsection. Finally, in
response to a request at the December 17, 2008, hearing that the Agency clarify
whether references to “CEMS” include sorbent trap monitoring systems as well,
the Agency proposes amending Section 225.240 to include references to excepted
monitoring systems.
Section 225.240
General Monitoring and Reporting Requirements
The owner or operator of an EGU must comply with the monitoring, recordkeeping, and
reporting requirements as provided in this Section, Sections 225.250 through 225.290 of
this Subpart B, and Sections 1.14 through 1.18 of Appendix B to this Part. If the EGU
utilizes a common stack with units that are not EGUs and the owner or operator of the
EGU does not conduct emissions monitoring in the duct to the common stack from each
EGU, the owner or operator of the EGU must conduct emissions monitoring in
accordance with Section 1.16(b)(2) of Appendix B to this Part and this Section, including
monitoring in the duct to the common stack from each unit that is not an EGU, unless the
owner or operator of the EGU counts the combined emissions measured at the common
stack as the mass emissions of mercury for the EGUs for recordkeeping and compliance
purposes.
a)
Requirements for installation, certification, and data accounting. The
owner or operator of each EGU must:
1)
Install all monitoring systems required pursuant to this Section and
Sections 225.250 through 225.290 for monitoring mercury mass
emissions (including all systems required to monitor mercury
concentration, stack gas moisture content, stack gas flow rate, and
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CO
2
or O
2
concentration, as applicable, in accordance with
Sections 1.15 and 1.16 of Appendix B to this Part.
2)
Successfully complete all certification tests required pursuant to
Section 225.250 and meet all other requirements of this Section,
Sections 225.250 through 225.290,
and Sections 1.14 through 1.18
of Appendix B to this Part applicable to the monitoring systems
required under subsection (a)(1) of this Section.
3)
Record, report, and assure the quality of the data from the
monitoring systems required under subsection (a)(1) of this
Section.
4)
If the owner or operator elects to use the low mass emissions
excepted monitoring methodology for an EGU that emits no more
than 464 ounces (29 pounds) of mercury per year pursuant to
Section 1.15(b) of Appendix B to this Part
, it must perform
emissions testing in accordance with Section 1.15(c) of Appendix
B to this Part to demonstrate that the EGU is eligible to use this
excepted emissions monitoring methodology, as well as comply
with all other applicable requirements of Section 1.15(b) through
(f)
of Appendix B to this Part. Also, the owner or operator must
submit a copy of any information required to be submitted to the
USEPA pursuant to these provisions to the Agency. The initial
emissions testing to demonstrate eligibility of an EGU for the low
mass emissions excepted methodology must be conducted by the
applicable of the following dates:
A)
If the EGU has commenced commercial operation before
July 1, 2008, at least by July 1, 2009, or 45 days prior to
relying on the low mass emissions excepted methodology,
whichever date is later.
B)
If the EGU has commenced commercial operation on or
after July 1, 2008, at least 45 days prior to the applicable
date specified pursuant to subsection (b)(2) of this Section
or 45 days prior to relying on the low mass emissions
excepted methodology, whichever date is later.
b)
Emissions Monitoring Deadlines. The owner or operator must meet the
emissions monitoring system certification and other emissions monitoring
requirements of subsections (a)(1) and (a)(2) of this Section on or before
the applicable of the following dates. The owner or operator must record,
report, and quality-assure the data from the emissions monitoring systems
required under subsection (a)(1) of this Section on and after the applicable
of the following dates:
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1)
For the owner or operator of an EGU that commences commercial
operation before July 1, 2008, by July 1, 2009.
2)
For the owner or operator of an EGU that commences commercial
operation on or after July 1, 2008, by 90 unit operating days or 180
calendar days, whichever occurs first, after the date on which the
EGU commences commercial operation.
3)
For the owner or operator of an EGU for which construction of a
new stack or flue or installation of add-on mercury emission
controls, a flue gas desulfurization system, a selective catalytic
reduction system, a fabric filter, or a compact hybrid particulate
collector system is completed after the applicable deadline
pursuant to subsection (b)(1) or (b)(2) of this Section, by 90 unit
operating days or 180 calendar days, whichever occurs first, after
the date on which emissions first exit to the atmosphere through
the new stack or flue, add-on mercury emission controls, flue gas
desulfurization system, selective catalytic reduction system, fabric
filter, or compact hybrid particulate collector system.
4)
For an owner or operator of an EGU that originally elected to
demonstrate compliance pursuant to the emissions testing
requirements in Section 225.239, by the first day of the calendar
quarter following the last emissions test demonstrating compliance
with Section 225.239.
c)
Reporting Data.
1)
Except as provided in subsection (c)(2) of this Section, Thethe
owner or operator of an EGU that does not meet the applicable
emissions monitoring date set forth in subsection (b) of this
Section for any emissions monitoring system required pursuant to
subsection (a)(1) of this Section must begin periodic emissions
testing in accordance with Section 225.239.
2)
The owner or operator of an EGU that does not meet the applicable
emissions monitoring date set forth in subsection (b)(3) of this
Section for any emissions monitoring system required pursuant to
subsection (a)(1) of this Section must begin periodic emissions
testing in accordance with Section 225.239.
d)
Prohibitions.
1)
No owner or operator of an EGU may use any alternative
emissions monitoring system, alternative reference method for
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measuring emissions, or other alternative to the emissions
monitoring and measurement requirements of this Section and
Sections 225.250 through 225.290, unless such alternative is
submitted to the Agency in writing and approved in writing by the
Manager of the Bureau of Air’s Compliance Section, or his or her
designee.
2)
No owner or operator of an EGU may operate its EGU so as to
discharge, or allow to be discharged, mercury emissions to the
atmosphere without accounting for all such emissions in
accordance with the applicable provisions of this Section, Sections
225.250 through 225.290, and
Sections 1.14 through 1.18 of
Appendix B to this Part, unless demonstrating compliance pursuant
to Section 225.239, as applicable.
3)
No owner or operator of an EGU may disrupt the CEMS (or
excepted monitoring system), any portion thereof, or any other
approved emission monitoring method, and thereby avoid
monitoring and recording mercury mass emissions discharged into
the atmosphere, except for periods of recertification or periods
when calibration, quality assurance testing, or maintenance is
performed in accordance with the applicable provisions of this
Section, Sections 225.250 through 225.290,
and Sections 1.14
through 1.18 of Appendix B to this Part.
4)
No owner or operator of an EGU may retire or permanently
discontinue use of the CEMS (or excepted monitoring system)
or
any component thereof, or any other approved monitoring system
pursuant to this Subpart B, except under any one of the following
circumstances:
A)
The owner or operator is monitoring emissions from the
EGU with another certified monitoring system that has
been approved, in accordance with the applicable
provisions of this Section, Sections 225.250 through
225.290 of this Subpart B,
and Sections 1.14 through 1.18
of Appendix B to this Part, by the Agency for use at that
EGU and that provides emission data for the same pollutant
or parameter as the retired or discontinued monitoring
system; or
B)
The owner or operator or designated representative submits
notification of the date of certification testing of a
replacement monitoring system for the retired or
discontinued monitoring system in accordance with Section
225.250(a)(3)(A).
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C)
The owner or operator is demonstrating compliance
pursuant to the applicable subsections of Section 225.239.
e)
Long-term Cold Storage.
The owner or operator of an EGU that is in long-term cold storage is
subject to the provisions of 40 CFR 75.4 and 40 CFR 75.64, incorporated
by reference in Section 225.140, relating to monitoring, recordkeeping,
and reporting for units in long-term cold storage.
13.
In response to a request at the December 17, 2008, hearing that the Agency
clarify whether references to “CEMS” include sorbent trap monitoring systems as
well, the Agency proposes amending Section 225.250 to include references to
excepted monitoring systems.
Section 225.250
Initial Certification and Recertification Procedures for Emissions
Monitoring
a)
The owner or operator of an EGU must comply with the following initial
certification and recertification procedures for a CEMS (i.e., a CEMS
or
an excepted monitoring system) (sorbent trap monitoring system) pursuant
to Section 1.3 of Appendix B to this Part) required by Section
225.240(a)(1). The owner or operator of an EGU that qualifies for, and
for which the owner or operator elects to use, the low-mass-emissions
excepted methodology pursuant to Section 1.15(b) of Appendix B to this
Part, must comply with the procedures set forth in subsection (c) of this
Section.
1)
Requirements for Initial Certification. The owner or operator of an
EGU must ensure that, for each CEMS (or excepted monitoring
system) required by Section 225.240(a)(1) (including the
automated data acquisition and handling system), the owner or
operator successfully completes all of the initial certification
testing required pursuant to Section 1.4 of Appendix B to this Part,
by the applicable deadline in Section 225.240(b). In addition,
whenever the owner or operator of an EGU installs a monitoring
system to meet the requirements of this Subpart B in a location
where no such monitoring system was previously installed, the
owner or operator must successfully complete the initial
certification requirements of Section 1.4 of Appendix B to this
Part.
2)
Requirements for Recertification. Whenever the owner or operator
of an EGU makes a replacement, modification, or change in any
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certified CEMS, or an excepted monitoring system (sorbent trap
monitoring system) pursuant to Section 1.3 of Appendix B to this
Part, and required by Section 225.240(a)(1), that may significantly
affect the ability of the system to accurately measure or record
mercury mass emissions or heat input rate or to meet the quality-
assurance and quality-control requirements of Section 1.5 of
Appendix B to this Part or Exhibit B to Appendix B to this Part,
the owner or operator of an EGU must recertify the monitoring
system in accordance with Section 1.4(b) of Appendix B to this
Part. Furthermore, whenever the owner or operator of an EGU
makes a replacement, modification, or change to the flue gas
handling system or the EGU’s operation that may significantly
change the stack flow or concentration profile, the owner or
operator must recertify each CEMS, and each excepted monitoring
system (sorbent trap monitoring system)
pursuant to Section 1.3 to
Appendix B to this Part, whose accuracy is potentially affected by
the change, all in accordance with Section 1.4(b) to Appendix B to
this Part. Examples of changes to a CEMS that require
recertification include, but are not limited to, replacement of the
analyzer, complete replacement of an existing CEMS, or change in
location or orientation of the sampling probe or site.
3)
Approval Process for Initial Certification and Recertification.
Subsections (a)(3)(A) through (a)(3)(D) of this Section apply to
both initial certification and recertification of a CEMS (or an
excepted monitoring system) required by Section 225.240(a)(1).
For recertifications, the words “certification” and “initial
certification” are to be read as the word “recertification”, the word
“certified” is to be read as the word “recertified”, and the
procedures set forth in Section 1.4(b)(5) of Appendix B to this Part
are to be followed in lieu of the procedures set forth in subsection
(a)(3)(E) of this Section.
A)
Notification of Certification. The owner or operator must
submit written notice of the dates of certification testing to
the Agency, directed to the Manager of the Bureau of Air’s
Compliance Section, in accordance with Section 225.270.
B)
Certification Application. The owner or operator must
submit to the Agency a certification application for each
monitoring system. A complete certification application
must include the information specified in 40 CFR 75.63,
incorporated by reference in Section 225.140.
C)
Provisional Certification Date. The provisional
certification date for a monitoring system must be
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determined in accordance with Section 1.4(a)(3) of
Appendix B to this Part. A provisionally certified
monitoring system may be used pursuant to this Subpart B
for a period not to exceed 120 days after receipt by the
Agency of the complete certification application for the
monitoring system pursuant to subsection (a)(3)(B) of this
Section. Data measured and recorded by the provisionally
certified monitoring system, in accordance with the
requirements of Appendix B to this Part, will be considered
valid quality-assured data (retroactive to the date and time
of provisional certification), provided that the Agency does
not invalidate the provisional certification by issuing a
notice of disapproval within 120 days after the date of
receipt by the Agency of the complete certification
application.
D)
Certification Application Approval Process. The Agency
must issue a written notice of approval or disapproval of
the certification application to the owner or operator within
120 days after receipt of the complete certification
application required by subsection (a)(3)(B) of this Section.
In the event the Agency does not issue a written notice of
approval or disapproval within the 120-day period, each
monitoring system that meets the applicable performance
requirements of Appendix B to this Part
and which is
included in the certification application will be deemed
certified for use pursuant to this Subpart B.
i)
Approval Notice. If the certification application is
complete and shows that each monitoring system
meets the applicable performance requirements of
Appendix B to this Part, then the Agency must issue
a written notice of approval of the certification
application within 120 days after receipt.
ii)
Incomplete Application Notice. If the certification
application is not complete, then the Agency must
issue a written notice of incompleteness that sets a
reasonable date by which the owner or operator
must submit the additional information required to
complete the certification application. If the owner
or operator does not comply with the notice of
incompleteness by the specified date, the Agency
may issue a notice of disapproval pursuant to
subsection (a)(3)(D)(iii) of this Section. The 120-
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day review period will not begin before receipt of a
complete certification application.
iii)
Disapproval Notice. If the certification application
shows that any monitoring system does not meet the
performance requirements of Appendix B to this
Part, or if the certification application is incomplete
and the requirement for disapproval pursuant to
subsection (a)(3)(D)(ii) of this Section is met, the
Agency must issue a written notice of disapproval
of the certification application. Upon issuance of
such notice of disapproval, the provisional
certification is invalidated, and the data measured
and recorded by each uncertified monitoring system
will not be considered valid quality-assured data
beginning with the date and hour of provisional
certification (as defined pursuant to Section
1.4(a)(3) of Appendix B to this Part). The owner or
operator must follow the procedures for loss of
certification set forth in subsection (a)(3)(E) of this
Section for each monitoring system that is
disapproved for initial certification.
iv)
Audit Decertification. The Agency may issue a
notice of disapproval of the certification status of a
monitor in accordance with Section 225.260(b).
E)
Procedures for Loss of Certification. If the Agency issues a
notice of disapproval of a certification application pursuant
to subsection (a)(3)(D)(iii) of this Section or a notice of
disapproval of certification status pursuant to subsection
(a)(3)(D)(iv) of this Section, the owner or operator must
fulfill the following requirements:
i)
The owner or operator must submit a notification of
certification retest dates and a new certification
application in accordance with subsections
(a)(3)(A) and (B) of this Section.
ii)
The owner or operator must repeat all certification
tests or other requirements that were failed by the
monitoring system, as indicated in the Agency’s
notice of disapproval, no later than 30 unit
operating days after the date of issuance of the
notice of disapproval.
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b)
Exemption.
1)
If an emissions monitoring system has been previously certified in
accordance with Appendix B to this Part and the applicable quality
assurance and quality control requirements of Section 1.5 and
Exhibit B to Appendix B to this Part
are fully met, the monitoring
system will be exempt from the initial certification requirements of
this Section.
2)
The recertification provisions of this Section apply to an emissions
monitoring system required by Section 225.240(a)(1) exempt from
initial certification requirements pursuant to subsection (a)(1) of
this Section.
c)
Initial certification and recertification procedures for EGUs using the
mercury low mass emissions excepted methodology pursuant to Section
1.15(b) of Appendix B to this Part. The owner or operator that has elected
to use the mercury-low-mass-emissions-excepted methodology for a
qualified EGU pursuant to Section 1.15(b) to Appendix B to this Part
must meet the applicable certification and recertification requirements in
Section 1.15(c) through (f) to Appendix B to this Part.
d)
Certification Applications. The owner or operator of an EGU must submit
an application to the Agency within 45 days after completing all initial
certification or recertification tests required pursuant to this Section,
including the information required pursuant to 40 CFR 75.63.
14.
In response to a request on page 160, line 3 of the Transcript of the December 17,
2008, hearing, the Agency proposes amending Section 225.260 to clarify that
MPS and CPS sources are subject to the 75% data availability uptime
requirement. The Agency also proposes amending subsection (c) to change
“must” to “will.”
Section 225.260
Out of Control Periods and Data Availability
for Emission
Monitors
a)
Out of control periods must be determined in accordance with Section 1.7
of Appendix B.
b)
Monitor data availability must be determined on a calendar quarter basis
in accordance with Section 1.8 of Appendix B following initial
certification of the required CO
2
, O
2
, flow monitor, or mercury
concentration or moisture monitoring system(s) at a particular unit or stack
location. Compliance with the percent reduction standard in Section
225.230(a)(1)(B), 225.233(d)(1)(B) or (d)(2)(B),
or 225.237(a)(1)(B), or
225.294(c)(2), or the emissions concentration standard in Section
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225.230(a)(1)(A), 225.233(d)(1)(A) or (d)(2)(A), or 225.237(a)(1)(A), or
225.294(c)(1), can only be demonstrated if the monitor data availability is
equal to or greater than 75 percent; that is, quality assured data must be
recorded by a certified primary monitor, a certified redundant or non-
redundant backup monitor, or reference method for that unit at least 75
percent of the time the unit is in operation.
c)
Audit Decertification. Whenever both an audit of an emissions
monitoring system and a review of the initial certification or recertification
application reveal that any emissions monitoring system should not have
been certified or recertified because it did not meet a particular
performance specification or other requirement pursuant to Section
225.250 or the applicable provisions of Appendix B to this Part, both at
the time of the initial certification or recertification application submission
and at the time of the audit, the Agency must issue a notice of disapproval
of the certification status of such monitoring system. For the purposes of
this subsection (c), an audit must be either a field audit or an audit of any
information submitted to the Agency. By issuing the notice of
disapproval, the Agency revokes prospectively the certification status of
the emissions monitoring system. The data measured and recorded by the
monitoring system willmust
not be considered valid quality-assured data
from the date of issuance of the notification of the revoked certification
status until the date and time that the owner or operator completes
subsequently approved initial certification or recertification tests for the
monitoring system. The owner or operator must follow the applicable
initial certification or recertification procedures in Section 225.250 for
each disapproved monitoring system.
15.
The Agency proposes several changes to Section 225.265. First, in subsection
(a), the Agency’s proposed revisions clarify that the coal sampling requirements
in this Section apply to EGUs in the MPS and CPS, except EGUs subject to the
0.0080 lb/GWh emission limit (this exception includes EGUs that opt into the
emission limit early). Second, the Agency proposes dividing subsection (a)(1)
into subsections (a)(1)(A) through (a)(1)(C) for clarity purposes. The proposed
revisions to subsection (a)(1)(A) specify that, of the EGUs that need to perform
coal sampling, those in the MPS or CPS, except EGUs complying with the 90%
control efficiency standard or utilizing emissions testing to demonstrate
compliance, must perform coal sampling at least once each month. The proposed
revisions to subsection (a)(1)(B) clarify that EGUs in the MPS and CPS
complying with the 90% control efficiency requirement, including EGUs that opt
into such limit early, and that utilize emissions testing to demonstrate compliance
must perform coal sampling according to the schedule set forth in Section
225.239. The proposed revisions to subsection (a)(1)(C) clarify that EGUs in the
MPS and CPS subject to the 90% control efficiency standard, including EGUs
that opt into such limit early, and that utilize CEMS to demonstrate compliance
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must perform coal sampling daily. Therefore, as revised, the coal sampling
requirements set forth in subsection (a)(1) can be summarized as follows:
(a)(1)(A) EGUs in the MPS or CPS that comply pursuant to the
sorbent injection rate requirement and utilize CEMS must
coal sample monthly;
(a)(1)(B) EGUs electing to demonstrate compliance pursuant to the
periodic emissions testing alternative in Section 225.239,
including EGUs in the MPS/CPS that opt into the 90%
control efficiency requirement and utilize periodic
emissions testing, must coal sample according to the
schedule set forth in Section 225.239;
(a)(1)(C) All other EGUs subject to Section 225.265, including EGUs
in the MPS/CPS complying with the 90% control efficiency
requirement and utilizing CEMS to demonstrate
compliance, must coal sample daily.
Finally, in response to a request by a stakeholder, the Agency proposes amending
subsection (a)(2) to include ASTM D6722-01 as an approved method for
measuring mercury content of coal.
Section 225.265
Coal Analysis for Input Mercury Levels
a)
The owner or operator of an EGU complying with this Subpart B by
means of Section 225.230(a)(1)(B);
, using input mercury levels (I
i
) and
complying by means of Section 225.230(b) or (d) or Section 225.232;,
electing to comply with the emissions testing, monitoring, and
recordkeeping requirements under Section 225.239;, or demonstrating
compliance under Section 225.233, except an EGU in an MPS Group that
elects to comply with the emission standard in Section 225.233(d)(1)(A)
or (d)(2)(A); or demonstrating compliance under Sections 225.291
through 225.299, except an EGU in a CPS Group that elects to comply
with the emission standard in Section 225.294(c)(1) or that opts into the
emission standard in Section 225.294(c)(1) pursuant to Section
225.294(e)(1), must fulfill the following requirements:
1)
Perform sampling of the coal combusted in the EGU for mercury
content. The owner or operator of such EGU must collect a
minimum of one 2-lb. grab sample from the belt feeders anywhere
between the crusher house or breaker building and the boiler,
according to the schedule below. The sample must be taken in a
manner that provides a representative mercury content for the coal
burned on that day. If multiple samples are tested, the owner or
operator must average those tests to arrive at the final mercury
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content for that time period. The owner or operator of the EGU
must perform coal sampling as follows:
A)
EGUs complying by means of Section 225.233, except an
EGU in an MPS Group that elects to comply with the
control efficiency standard in Section 225.233(d)(1)(B) or
(d)(2)(B) or elects to comply with Section 225.233(d)(4), or
Sections 225.291 through 225.299, except an EGU in a
CPS Group that elects to comply with the control efficiency
standard in Section 225.294(c)(2) or that opts into the
emission standard in Section 225.294(c)(2) pursuant to
Section 225.294(e)(1), of this Subpart must perform such
coal sampling at least once per month unless the boiler did
not operate or combust coal at all during that month;
B)
EGUs complying by means of the emissions testing,
monitoring, and recordkeeping requirements under Section
225.239 or Section 225.233(d)(4), or EGUs that opt into the
emission standard in Section 225.294(c)(2) pursuant to
Section 225.294(e)(1)(B), must perform such coal sampling
according to the schedule provided in Section
225.239(e)(3) of this Subpart;
C)
Allall
other EGUs subject to this requirement, including
EGUs in an MPS or CPS Group electing to comply with
the control efficiency standard in Section 225.233(d)(1)(B)
or (d)(2)(B), Section 225.294(c)(2), or Section
225.294(c)(2) pursuant to Section 225.294(e)(1)(A), must
perform such coal sampling on a daily basis when the
boiler is operating and combusting coal. If multiple
samples are tested, the owner or operator must average
those tests to arrive at the final mercury content for that
time period.
2)
Analyze the grab coal sample for the following:
A)
Determine the heat content using ASTM D5865-04
or an equivalent method approved in writing by the
Agency.
B)
Determine the moisture content using ASTM
D3173-03 or an equivalent method approved in
writing by the Agency.
C)
Measure the mercury content using ASTM D6414-
01, ASTM D3684-01, ASTM D6722-01,
or an
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equivalent method approved in writing by the
Agency.
3)
The owner or operator of multiple EGUs at the same source
using the same crusher house or breaker building may take
one sample per crusher house or breaker building, rather
than one per EGU.
4)
The owner or operator of an EGU must use the data analyzed
pursuant to subsection (b) of this Section to determine the mercury
content in terms of parts per millionlbs/trillion
Btu.
b)
The owner or operator of an EGU that must conduct sampling and analysis
of coal pursuant to subsection (a) of this Section must begin such activity
by the following date:
1)
If the EGU is in daily service, at least 30 days before the start of
the month for which such activity will be required.
2)
If the EGU is not in daily service, on the day that the EGU resumes
operation.
16.
The Agency proposes several changes to Section 225.290. The Agency proposes
amending subsection (a)(1)(A) to require use of parts per million rather than
pounds per trillion BTUs when recording the mercury content of coal. In
response to requests at the December 17, 2008, hearing and the fact that, as
discussed at the hearing, USEPA will not be accepting electronic reports from
sources, the Agency proposes deleting subsection (a)(6), as it references
electronic reporting, and proposes amending the new subsection (a)(6) to specify
that sources must only retain records for five years. Also in response to requests
at hearing and USEPA’s inability to accept electronic reports, the Agency is
amending subsection (b) regarding the content of quarterly reports. The Agency
is also attaching a draft form as Exhibit 1 to this Second Errata that sources can
utilize to aid in the reporting of the information listed in subsection (b). The draft
form was previously provided to affected sources and revised based upon
comments received from such sources.
The Agency proposes amending subsection (c)(2) to replace a reference to
missing data with a reference to data that is unavailable or out of control, for
clarity purposes. The Agency also proposes amending this subsection to replace
two references to Appendix B with references to 40 CFR 75. The Agency
mistakenly deleted these references to Part 75 in its original proposal.
Finally, the Agency proposes amending subsection (d) to add several references
to QAMO, resulting from a change to the monitoring calculation provisions
(explained in more detail under Second Errata number 5).
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Section 225.290
Recordkeeping and Reporting
a)
General Provisions.
1)
The owner or operator of an EGU and its designated representative
must comply with all applicable recordkeeping and reporting
requirements in this Section and with all applicable recordkeeping
and reporting requirements of Section 1.18 to Appendix B to this
Part.
2)
The owner or operator of an EGU must maintain records for each
month identifying the emission standard in Section 225.230(a) or
225.237(a) of this Section with which it is complying or that is
applicable for the EGU and the following records related to the
emissions of mercury that the EGU is allowed to emit:
A)
For an EGU for which the owner or operator is complying
with this Subpart B by means of Section 225.230(a)(1)(B)
or 225.237(a)(1)(B) or using input mercury levels to
determine the allowable emissions of the EGU, records of
the daily mercury content of coal used (parts per
millionlbs/trillion Btu) and the daily and monthly input
mercury (lbs), which must be kept in the file pursuant to
Section 1.18(a) of Appendix B to this Part.
B)
For an EGU for which the owner or operator of an EGU
complying with this Subpart B by means of Section
225.230(a)(1)(A) or 225.237(a)(1)(A) or using electrical
output to determine the allowable emissions of the EGU,
records of the daily and monthly gross electrical output
(GWh), which must be kept in the file required pursuant to
Section 1.18(a) of Appendix B to this Part.
3)
The owner or operator of an EGU must maintain records of the
following data for each EGU:
A)
Monthly emissions of mercury from the EGU.
B)
For an EGU for which the owner or operator is complying
by means of Section 225.230(b) or (d) of this Subpart B,
records of the monthly allowable emissions of mercury
from the EGU.
4)
The owner or operator of an EGU that is participating in an
Averaging Demonstration pursuant to Section 225.232 of this
Subpart B must maintain records identifying all sources and EGUs
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covered by the Demonstration for each month and, within 60 days
after the end of each calendar month, calculate and record the
actual and allowable mercury emissions of the EGU for the month
and the applicable 12-month rolling period.
5)
The owner or operator of an EGU must maintain the following
records related to quality assurance activities conducted for
emissions monitoring systems:
A)
The results of quarterly assessments conducted pursuant to
Section 2.2 of Exhibit B to Appendix B to this Part; and
B)
Daily/weekly system integrity checks pursuant to Section
2.6 of Exhibit B to Appendix B to this Part.
6)
The owner or operator of an EGU must maintain an electronic
copy of all electronic submittals to the USEPA pursuant to Section
1.18(f) to Appendix B to this Part.
67)
The owner or operator of an EGU must retain all records required
by this Section at the source for a period of five years from the date
the document is created unless otherwise provided in the CAAPP
permit issued for the source and must make a copy of any record
available to the Agency upon request. This period may be
extended in writing by the Agency, for cause, at any time prior to
the end of five years.
b)
Quarterly Reports. The owner or operator of a source with one or more
EGUs using CEMS or excepted monitoring systems at any time during a
calendar quarter must submit quarterly reports to the Agency as follows:
1)
These reports must include the following information for operation
of the EGUs during the quarter:
A)
The total operating hours of each EGU and the mercury
CEMS, as also reported in accordance with Appendix B to
this Part.
B)
A discussion of any significant changes in the measures
used to control emissions of mercury from the EGUs or the
coal supply to the EGUs, including changes in the source of
coal.
C)
Summary information on the performance of the mercury
CEMS. When the mercury CEMS was not inoperative,
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repaired, or adjusted, except for routine zero and span
checks, this must be stated in the report.
D)
If the CEMS downtime was more than 5.0 percent of the
total operating time for the EGU: the date and time
identifying each period during which the CEMS was
inoperative, except for routine zero and span checks; the
nature of CEMS repairs or adjustments and a summary of
quality assurance data consistent with Appendix B to this
Part
,
i.e., the dates and results of the Linearity Tests and
any RATAs during the quarter; a listing of any days when a
required daily calibration was not performed; and the date
and duration of any periods when the CEMS was out-of-
control as addressed by Section 225.260.
E)
Recertification testing that has been performed for any
CEMS and the status of the results.
2)
The owner or operator must submit each quarterly report to the
Agency within 45 days following the end of the calendar quarter
covered by the report.
1)
Source information such as source name, source ID number, and
the period covered by the report;
2)
A list of all EGU(s) at the source that identifies the applicable Part
225 monitoring and reporting requirements with which each EGU
is complying for the reported quarter, including the following
EGUs, which are excluded from subsection (b)(3) of this Section:
A)
All EGUs using the periodic emissions testing provisions of
Section 225.239, 225.233(d)(4), or Section 225.294(c)
pursuant to Section 225.294(e)(1)(B) for the quarter.
B)
All EGUs using the low mass emissions (LME) excepted
monitoring methodology pursuant to Section 1.15(b) of
Appendix B to this Part.
3)
For only those EGUs using CEMS or excepted monitoring systems
at any time during a calendar quarter:
A)
An indication of whether the identified EGUs were in
compliance with all applicable monitoring, recordkeeping,
and reporting requirements of Part 225 for the entire
reporting period.
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B)
The total quarterly operating hours of each EGU.
C)
The quarterly CEMS or excepted monitoring system
quality-assured monitor operating (QAMO) hours and
percentage data availability, determined in accordance with
Sections 1.8 (CEMS) or 1.9 (excepted monitoring system)
of Appendix B to this Part.
D)
The average monthly mercury concentration of the coal
combusted in each EGU in parts per million (determined by
averaging all analyzed coal samples in the month) and the
quarterly total amount of mercury (calculated by
multiplying the total amount of coal combusted each month
by the average monthly mercury concentration and
converting to ounces, then adding together for the quarter)
of the coal combusted in each EGU. If the EGU is
complying by means of Sections 225.230(a)(1)(A),
225.233(d)(1)(A), 225.233(d)(2)(A), or Section
225.294(c)(1), reporting of the data in this subparagraph D
is not required.
E)
The quarterly mercury mass emissions (in ounces),
determined from the QAMO hours in accordance with
Section 4.2 of Exhibit C to Appendix B to this Part. If the
EGU is complying by means of Sections 225.230(a)(1)(A),
225.233(d)(1)(A), 225.233(d)(2)(A), or Section
225.294(c)(1), reporting of the data in this subparagraph E
is not required.
F)
The average monthly and quarterly mercury control
efficiency. This is determined by dividing the mercury
mass emissions recorded during QAMO hours, calculated
each month and quarter, by the total amount of mercury in
the coal combusted modified by the monitor availability
(total mercury content multiplied by the percent monitor
availability, or QAMO hours divided by total hours) for
each month and quarter. If the EGU is complying by means
of Sections 225.230(a)(1)(A), 225.233(d)(1)(A),
225.233(d)(2)(A), or Section 225.294(c)(1), reporting of
the data in this subparagraph F is not required.
G)
The average monthly and quarterly mercury emission rate
(in lb/GWh) for each EGU, determined in accordance with
Section 225.230(a)(2). Only those EGUs complying by
means of Sections 225.230(a)(1)(A), 225.233(d)(1)(A),
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225.233(d)(2)(A), or Section 225.294(c)(1) are required to
report the data in this subparagraph G.
H)
The 12-month rolling average control efficiency
(percentage) or emission rate (in lb/GWh) for each month
in the reporting period, as applicable (or the rolling
average control efficiency or emission rate for a lesser
number of months if a full 12 months of data is not
available). This applicable data is determined according to
the following requirements:
i.
The 12-month rolling average control efficiency is
required for those sources complying by means of
Sections 225.230(a)(1)(B), 225.233(d)(1)(B),
225.233(d)(2)(B), 225.294(c)(2), 225.230(b),
225.230(d), 225.232(b)(2), or 225.237(a)(1)(B).
ii.
The 12-month rolling average emission rate is
required for those sources complying by means of
Sections 225.230(a)(1)(A), 225.233(d)(1)(A),
225.233(d)(2)(A), or Section 225.294(c)(1),
225.230(b), 225.230(d), 225.232(b)(1), or
225.237(a)(1)(A).
I)
If the CEMS or excepted monitoring system percentage
data availability was less than 95.0 percent of the total
operating time for the EGU, the date and time identifying
each period during which the CEMS was inoperative,
except for routine zero and span checks; the nature of
CEMS repairs or adjustments and a summary of quality
assurance data consistent with Appendix B to this Part, i.e.,
the dates and results of the Linearity Tests and any RATAs
during the quarter; a listing of any days when a required
daily calibration was not performed; and the date and
duration of any periods when the CEMS was unavailable or
out-of-control as addressed by Section 225.260.
4)
The owner or operator must submit each quarterly report to the
Agency within 45 days following the end of the calendar quarter
covered by the report.
c)
Compliance Certification. The owner or operator of a source with one or
more EGUs must submit to the Agency a compliance certification in
support of each quarterly report based on reasonable inquiry of those
persons with primary responsibility for ensuring that all of the EGUs'
emissions are correctly and fully monitored. The certification must state:
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1)
That the monitoring data submitted were recorded in accordance
with the applicable requirements of this Section, Sections 225.240
through 225.270 and Section 225.290 of this Subpart B,
and
Appendix B to this Part, including the quality assurance procedures
and specifications; and
2)
For an EGU with add-on mercury emission controls, a flue gas
desulfurization system, a selective catalytic reduction system, or a
compact hybrid particulate collector system for all hours where
mercury data is unavailable or out of controlmissing
that:
A)
The mercury add-on emission controls, flue gas
desulfurization system, selective catalytic reduction system,
or compact hybrid particulate collector system was
operating within the range of parameters listed in the
quality assurance/quality control program pursuant to
Exhibit B to Appendix B to this Part; or
B)
With regard to a flue gas desulfurization system or a
selective catalytic reduction system, quality-assured SO
2
emission data recorded in accordance with Appendix B40
CFR 75 to this Part document that the flue gas
desulfurization system was operating properly, or quality-
assured NO
X
emission data recorded in accordance with
Appendix B40 CFR 75 to this Part document that the
selective catalytic reduction system was operating properly,
as applicable; and
d)
Annual Certification of Compliance.
1)
The owner or operator of a source with one or more EGUs subject
to this Subpart B must submit to the Agency an Annual
Certification of Compliance with this Subpart B no later than May
1 of each year and must address compliance for the previous
calendar year. Such certification must be submitted to the Agency,
Air Compliance Section, and the Air Regional Field Office.
2)
Annual Certifications of Compliance must indicate whether
compliance existed for each EGU for each month in the year
covered by the Certification and it must certify to that effect. In
addition, for each EGU, the owner or operator must provide the
following appropriate data as set forth in subsections (d)(2)(A)
through (d)(2)(E) of this Section, together with the data set forth in
subsection (d)(2)(F) of this Section:
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A)
If complying with this Subpart B by means of Section
225.230(a)(1)(A) or 225.237(a)(1)(A):
i)
Actual
Emissionsemissions rate during QAMO
hours, in lb/GWh, for each 12-month rolling period
ending in the year covered by the Certification;
ii)
Actual Emissionsemissions during QAMO hours, in
lbs, and gross electrical output, in GWh, for each
12-month rolling period ending in the year covered
by the Certification; and
iii)
Actual
Emissionsemissions during QAMO hours, in
lbs, and gross electrical output, in GWh, for each
month in the year covered by the Certification and
in the previous year.
B)
If complying with this Subpart B by means of Section
225.230(a)(1)(B) or 225.237(a)(1)(B):
i)
Actual
Controlcontrol efficiency for emissions
during QAMO hours
for each 12-month rolling
period ending in the year covered by the
Certification, expressed as a percent;
ii)
Actual Emissionsemissions during QAMO hours, in
lbs, and mercury content in the fuel fired in such
EGU, in lbs, for each 12-month rolling period
ending in the year covered by the Certification; and
iii)
Actual
Emissionsemissions during QAMO hours, in
lbs, and mercury content in the fuel fired in such
EGU, in lbs, for each month in the year covered by
the Certification and in the previous year.
C)
If complying with this Subpart B by means of Section
225.230(b):
i)
Actual
Emissionsemissions and allowable emissions
during QAMO hours for each 12-month rolling
period ending in the year covered by the
Certification; and
ii)
Actual Emissionsemissions and allowable emissions
during QAMO hours
, and which standard of
compliance the owner or operator was utilizing for
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each month in the year covered by the Certification
and in the previous year.
D)
If complying with this Subpart B by means of Section
225.230(d):
i)
Actual
Emissionsemissions and allowable emissions
during QAMO hours for all EGUs at the source for
each 12-month rolling period ending in the year
covered by the Certification; and
ii)
Actual
Emissionsemissions and allowable emissions
during QAMO hours, and which standard of
compliance the owner or operator was utilizing for
each month in the year covered by the Certification
and in the previous year.
E)
If complying with this Subpart B by means of Section
225.232:
i)
Actual
Emissionsemissions and allowable emissions
during QAMO hours
for all EGUs at the source in
an Averaging Demonstration for each 12-month
rolling period ending in the year covered by the
Certification; and
ii)
Actual
Emissionsemissions and allowable emissions
during QAMO hours, with the standard of
compliance the owner or operator was utilizing for
each EGU at the source in an Averaging
Demonstration for each month for all EGUs at the
source in an Averaging Demonstration in the year
covered by the Certification and in the previous
year.
F)
Any deviations or exceptions each month and discussion of
the reasons for such deviations or exceptions.
3)
All Annual Certifications of Compliance required to be submitted
must include the following certification by a responsible official:
I certify under penalty of law that this document and all
attachments were prepared under my direction or supervision in
accordance with a system designed to assure that qualified
personnel properly gather and evaluate the information submitted.
Based on my inquiry of the person or persons directly responsible
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for gathering the information, the information submitted is, to the
best of my knowledge and belief, true, accurate, and complete. I
am aware that there are significant penalties for submitting false
information, including the possibility of fine and imprisonment for
knowing violations.
4)
The owner or operator of an EGU must submit its first Annual
Certification of Compliance to address calendar year 2009 or the
calendar year in which the EGU commences commercial
operation, whichever is later. Notwithstanding subsection (d)(2) of
this Section, in the Annual Certifications of Compliance that are
required to be submitted by May 1, 2010, and May 1, 2011, to
address calendar years 2009 and 2010, respectively, the owner or
operator is not required to provide 12-month rolling data for any
period that ends before June 30, 2010.
e)
Deviation Reports. For each EGU, the owner or operator must promptly
notify the Agency of deviations from requirements of this Subpart B. At a
minimum, these notifications must include a description of such deviations
within 30 days after discovery of the deviations, and a discussion of the
possible cause of such deviations, any corrective actions, and any
preventative measures taken.
f)
Quality Assurance RATA Reports. The owner or operator of an EGU
must submit to the Agency, Air Compliance and Enforcement Section, the
quality assurance RATA report for each EGU or group of EGUs
monitored at a common stack and each non-EGU pursuant to
Section
1.16(b)(2)(B) of Appendix B to this Part, within 45 days after completing
a quality assurance RATA.
17.
The Agency proposes amending Section 225.292(e) to delete a reference to the
CAIR designated representative.
Section 225.292
Applicability of the Combined Pollutant Standard
***
e)
If an EGU is subject to the requirements of this Section, then the
requirements apply to all owners and operators of the EGU, and to the
CAIR
designated representative for the EGU.
18.
First, the Agency proposes amending Section 225.294(e)(1)(B) to correct an error
in the Agency’s original proposal regarding the frequency of emissions testing for
CPS sources utilizing Section 225.239 to demonstrate compliance. While EGUs
in the CPS that are complying with the sorbent injection rate requirement must
perform emissions testing on a semi-annual basis, if such EGUs opt into either the
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0.0080 lb/GWh emission limit or 90% control efficiency requirement early, they
must perform quarterly emissions testing. Also, in response to requests for
clarification at the December 17, 2008, hearing, the Agency amended subsection
(e)(1)(B) to specify which subsections of Section 225.239 are applicable to EGUs
in the CPS that utilize emissions testing to demonstrate compliance.
Second, in response to a request on pages 88-89 of the Transcript of the
December 17, 2008, hearing, the Agency proposes amending Section 225.294(f)
to clarify that EGUs in the CPS may utlilize the averaging provisions set forth in
Section 225.232.
Next, the Agency proposes amending Section 225.294(l) to clarify the “sunset
date” for the emissions testing alternative in Section 225.239. Also, in response
to a request at hearing that the Agency clarify whether references to “CEMS”
include sorbent trap monitoring systems as well, the Agency proposes amending
subsection (l) to include references to excepted monitoring systems.
Section 225.294
Combined Pollutant Standard: Control Technology Requirements
and Emissions Standards for Mercury
a)
Control Technology Requirements for Mercury.
1)
For each EGU in a CPS group other than an EGU that is addressed
by subsection (b) of this Section, the owner or operator of the EGU
must install, if not already installed, and properly operate and
maintain, by the dates set forth in subsection (a)(2) of this Section,
ACI equipment complying with subsections (g), (h), (i), (j), and
(k) of this Section, as applicable.
2)
By the following dates, for the EGUs listed in subsections
(a)(2)(A) and (B), which include hot and cold side ESPs, the owner
or operator must install, if not already installed, and begin
operating ACI equipment or the Agency must be given written
notice that the EGU will be shut down on or before the following
dates:
A)
Fisk 19, Crawford 7, Crawford 8, Waukegan 7, and
Waukegan 8 on or before July 1, 2008; and
B)
Powerton 5, Powerton 6, Will County 3, Will County 4,
Joliet 6, Joliet 7, and Joliet 8 on or before July 1, 2009.
b)
Notwithstanding subsection (a) of this Section, the following EGUs are
not required to install ACI equipment because they will be permanently
shut down, as addressed by Section 225.297, by the date specified:
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1)
EGUs that are required to permanently shut down:
A)
On or before December 31, 2007, Waukegan 6; and
B)
On or before December 31, 2010, Will County 1 and Will
County 2.
2)
Any other specified EGU that is permanently shut down by
December 31, 2010.
c)
Beginning on January 1, 2015, and continuing thereafter, and measured on
a rolling 12-month basis (the initial period is January 1, 2015, through
December 31, 2015, and, then, for every 12-month period thereafter), each
specified EGU, except Will County 3, shall achieve one of the following
emissions standards:
1)
An emissions standard of 0.0080 lbs mercury/GWh gross electrical
output; or
2)
A minimum 90 percent reduction of input mercury.
d)
Beginning on January 1, 2016, and continuing thereafter, Will County 3
shall achieve the mercury emissions standards of subsection (c) of this
Section measured on a rolling 12-month basis (the initial period is January
1, 2016, through December 31, 2016, and, then, for every 12-month period
thereafter).
e)
Compliance with Emission Standards
1)
At any time prior to the dates required for compliance in
subsections (c) and (d) of this Section, the owner or operator of a
specified EGU, upon notice to the Agency, may elect to comply
with the emissions standards of subsection (c) of this Section
measured on either:
A)
a rolling 12-month basis, or;
B)
a quarterly
semi-annual calendar basis pursuant to the
emissions testing requirements in Section 225.239(a)(4),
(c), (d), (e), (f)(1) and (2), (g), (h)(2), and (i)(3) and (4),
and (j) of this Subpart until June 30, 2012.
2)
Once an EGU is subject to the mercury emissions standards of
subsection (c) of this Section, it shall not be subject to the
requirements of subsections (g), (h), (i), (j) and (k) of this Section.
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f)
Compliance with the mercury emissions standards or reduction
requirement of this Section must be calculated in accordance with Section
225.230(a) or (b), or Section 225.232 until December 31, 2013.
g)
For each EGU for which injection of halogenated activated carbon is
required by subsection (a)(1) of this Section, the owner or operator of the
EGU must inject halogenated activated carbon in an optimum manner,
which, except as provided in subsection (h) of this Section, is defined as
all of the following:
1)
The use of an injection system for effective absorption of mercury,
considering the configuration of the EGU and its ductwork;
2)
The injection of halogenated activated carbon manufactured by
Alstom, Norit, or Sorbent Technologies, Calgon Carbon’s
FLUEPAC CF Plus, or Calgon Carbon's FLUEPAC MC Plus, or
the injection of any other halogenated activated carbon or sorbent
that the owner or operator of the EGU has demonstrated to have
similar or better effectiveness for control of mercury emissions;
and
3)
The injection of sorbent at the following minimum rates, as
applicable:
A)
For an EGU firing subbituminous coal, 5.0 lbs per million
actual cubic feet or, for any cyclone-fired EGU that will
install a scrubber and baghouse by December 31, 2012, and
which already meets an emission rate of 0.020 lb
mercury/GWh gross electrical output or at least 75 percent
reduction of input mercury, 2.5 lbs per million actual cubic
feet;
B)
For an EGU firing bituminous coal, 10.0 lbs per million
actual cubic feet or, for any cyclone-fired EGU that will
install a scrubber and baghouse by December 31, 2012, and
which already meets an emission rate of 0.020 lb
mercury/GWh gross electrical output or at least 75 percent
reduction of input mercury, 5.0 lbs per million actual cubic
feet;
C)
For an EGU firing a blend of subbituminous and
bituminous coal, a rate that is the weighted average of the
rates specified in subsections (g)(3)(A) and (B), based on
the blend of coal being fired; or
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D)
A rate or rates set lower by the Agency, in writing, than the
rate specified in any of subsection (g)(3)(A), (B), or (C) of
this Section on a unit-specific basis, provided that the
owner or operator of the EGU has demonstrated that such
rate or rates are needed so that carbon injection will not
increase particulate matter emissions or opacity so as to
threaten noncompliance with applicable requirements for
particulate matter or opacity.
4)
For purposes of subsection (g)(3) of this Section, the flue gas flow
rate must be determined for the point sorbent injection; provided
that this flow rate may be assumed to be identical to the stack flow
rate if the gas temperatures at the point of injection and the stack
are normally within 100º F, or the flue gas flow rate may otherwise
be calculated from the stack flow rate, corrected for the difference
in gas temperatures.
h)
The owner or operator of an EGU that seeks to operate an EGU with an
activated carbon injection rate or rates that are set on a unit-specific basis
pursuant to subsection (g)(3)(D) of this Section must submit an application
to the Agency proposing such rate or rates, and must meet the
requirements of subsections (h)(1) and (h)(2) of this Section, subject to the
limitations of subsections (h)(3) and (h)(4) of this Section:
1)
The application must be submitted as an application for a new or
revised federally enforceable operation permit for the EGU, and it
must include a summary of relevant mercury emissions data for the
EGU, the unit-specific injection rate or rates that are proposed, and
detailed information to support the proposed injection rate or rates;
and
2)
This application must be submitted no later than the date that
activated carbon must first be injected. For example, the owner or
operator of an EGU that must inject activated carbon pursuant to
subsection (a)(1) of this Section must apply for unit-specific
injection rate or rates by July 1, 2008. Thereafter, the owner or
operator may supplement its application; and
3)
Any decision of the Agency denying a permit or granting a permit
with conditions that set a lower injection rate or rates may be
appealed to the Board pursuant to Section 39 of the Act; and
4)
The owner or operator of an EGU may operate at the injection rate
or rates proposed in its application until a final decision is made on
the application including a final decision on any appeal to the
Board.
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i)
During any evaluation of the effectiveness of a listed sorbent, alternative
sorbent, or other technique to control mercury emissions, the owner or
operator of an EGU need not comply with the requirements of subsection
(g) of this Section for any system needed to carry out the evaluation, as
further provided as follows:
1)
The owner or operator of the EGU must conduct the evaluation in
accordance with a formal evaluation program submitted to the
Agency at least 30 days prior to commencement of the evaluation;
2)
The duration and scope of the evaluation may not exceed the
duration and scope reasonably needed to complete the desired
evaluation of the alternative control techniques, as initially
addressed by the owner or operator in a support document
submitted with the evaluation program; and
3)
The owner or operator of the EGU must submit a report to the
Agency no later than 30 days after the conclusion of the evaluation
that describes the evaluation conducted and which provides the
results of the evaluation; and
4)
If the evaluation of alternative control techniques shows less
effective control of mercury emissions from the EGU than was
achieved with the principal control techniques, the owner or
operator of the EGU must resume use of the principal control
techniques. If the evaluation of the alternative control technique
shows comparable effectiveness to the principal control technique,
the owner or operator of the EGU may either continue to use the
alternative control technique in a manner that is at least as effective
as the principal control technique or it may resume use of the
principal control technique. If the evaluation of the alternative
control technique shows more effective control of mercury
emissions than the control technique, the owner or operator of the
EGU must continue to use the alternative control technique in a
manner that is more effective than the principal control technique,
so long as it continues to be subject to this Section.
j)
In addition to complying with the applicable recordkeeping and
monitoring requirements in Sections 225.240 through 225.290, the owner
or operator of an EGU that elects to comply with Section 225.230(a) by
means of the CPS must also comply with the following additional
requirements:
1)
For the first 36 months that injection of sorbent is required, it must
maintain records of the usage of sorbent, the exhaust gas flow rate
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from the EGU, and the sorbent feed rate, in pounds per million
actual cubic feet of exhaust gas at the injection point, on a weekly
average;
2)
After the first 36 months that injection of sorbent is required, it
must monitor activated sorbent feed rate to the EGU, flue gas
temperature at the point of sorbent injection, and exhaust gas flow
rate from the EGU, automatically recording this data and the
sorbent carbon feed rate, in pounds per million actual cubic feet of
exhaust gas at the injection point, on an hourly average; and
3)
If a blend of bituminous and subbituminous coal is fired in the
EGU, it must keep records of the amount of each type of coal
burned and the required injection rate for injection of activated
carbon on a weekly basis.
k)
In addition to complying with the applicable reporting requirements in
Sections 225.240 through 225.290, the owner or operator of an EGU that
elects to comply with Section 225.230(a) by means of the CPS must also
submit quarterly reports for the recordkeeping and monitoring conducted
pursuant to subsection (j) of this Section.
l)
Until June 30, 2012, asAs
an alternative to the CEMS (or excepted
monitoring system) monitoring, recordkeeping, and reporting
requirements in Sections 225.240 through 225.290, the owner or operator
of an EGU may elect to comply with the emissions testing, monitoring,
recordkeeping, and reporting requirements in Section 225.239(c), (d), (e),
(f)(1) and (2), (h)(2), (i)(3) and (4), and (j)(1).
19.
The Agency proposes amending Appendix B Sections 1.2(a) and (c) to make
minor clarifications. Language was added in response to comments by the
USEPA to include auxiliary monitors such as auxiliary flow monitors, diluent gas
monitors, moisture monitors, or other auxiliary monitors in the equipment
performance requirements. Accordingly, the Agency is suggesting the following
addition.
a)
Primary Equipment Performance Requirements. The owner or operator
must ensure that each continuous mercury emission monitoring system
and each auxiliary monitoring system
required by this Appendix meets the
equipment, installation, and performance specifications in Exhibit A to
this Appendix and is maintained according to the quality assurance and
quality control procedures in Exhibit B to this Appendix.
***
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c)
Primary equipment hourly operating requirements. The owner or operator
must ensure that all continuous mercury emission monitoring systems and
all auxiliary monitoring systems required by this Appendix are in
operation and monitoring unit emissions at all times that the affected unit
combusts any fuel except during periods of calibration, quality assurance,
or preventive maintenance, performed pursuant to Section 1.5 of this
Appendix and Exhibit B to this Appendix, periods of repair, periods of
backups of data from the data acquisition and handling system, or
recertification performed pursuant to Section 1.4 of this Appendix.
20.
The Agency proposes amending Appendix B Section 1.4(a), 1.4(a)(2), 1.4(a)(3),
and 1.4(a)(4)(c) in response to comments from USEPA.
a)
Initial certification approval process. The owner or operator must ensure
that each continuous mercury emission monitoring system or auxiliary
monitoring system required by this Appendix meets the initial certification
requirements of this Section. In addition, whenever the owner or operator
installs a continuous mercury emission monitoring system in order to meet
the requirements of Sections 1.3 of this Appendix and 40 CFR Sections
75.11 through 75.14 and 75.16 through 75.18, incorporated by reference in
Section 225.140, where no continuous emission monitoring system was
previously installed, initial certification is required.
***
2)
Certification application. The owner or operator must apply for
certification of each continuous mercury emission monitoring
system and, if not previously certified, for each auxiliary
monitoring system. The owner or operator must submit the
certification application in accordance with 40 CFR 75.60,
incorporated by reference in Section 225.140, and each complete
certification application must include the information specified in
40 CFR 75.63, incorporated by reference in Section 225.140.
3)
Provisional approval of certification (or recertification)
applications. Upon the successful completion of the required
certification (or recertification) procedures of this Section, each
continuous mercury emission monitoring system and each
auxiliary monitoring system must be deemed provisionally
certified (or recertified) for use for a period not to exceed 120 days
following receipt by the Agency of the complete certification (or
recertification) application under paragraph (a)(4) of this Section.
Data measured and recorded by a provisionally certified (or
recertified) continuous emission monitoring system, operated in
accordance with the requirements of Exhibit B to this Appendix,
will be considered valid quality-assured data (retroactive to the
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date and time of provisional certification or recertification),
provided that the Agency does not invalidate the provisional
certification (or recertification) by issuing a notice of disapproval
within 120 days of receipt by the Agency of the complete
certification (or recertification) application. Note that when the
conditional data validation procedures of paragraph (b)(3) of this
Section are used for the initial certification (or recertification) of a
continuous emissions monitoring system, the date and time of
provisional certification (or recertification) of the CEMS may be
earlier than the date and time of completion of the required
certification (or recertification) tests.
4)
Certification (or recertification) application formal approval
process. The Agency will issue a notice of approval or disapproval
of the certification (or recertification) application to the owner or
operator within 120 days of receipt of the complete certification (or
recertification) application. In the event the Agency does not issue
such a notice within 120 days of receipt, each continuous emission
monitoring system which meets the performance requirements of
this part and is included in the certification (or recertification)
application will be deemed certified (or recertified) for use under
35 Ill Admin. Code Part 225.
A)
Approval notice. If the certification (or recertification)
application is complete and shows that each continuous
emission monitoring system meets the performance
requirements of this part, then the Agency will issue a
notice of approval of the certification (or recertification)
application within 120 days of receipt.
B)
Incomplete application notice. A certification (or
recertification) application will be considered complete
when all of the applicable information required to be
submitted in 40 CFR 75.63, incorporated by reference in
Section 225.140, has been received by the Agency. If the
certification (or recertification) application is not complete,
then the Agency will issue a notice of incompleteness that
provides a reasonable timeframe for the designated
representative to submit the additional information required
to complete the certification (or recertification) application.
If the designated representative has not complied with the
notice of incompleteness by a specified due date, then the
Agency may issue a notice of disapproval specified under
paragraph (a)(4)(C) of this Section. The 120-day review
period will not begin prior to receipt of a complete
application.
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C)
Disapproval notice. If the certification (or recertification)
application shows that any continuous emission monitoring
system does not meet the performance requirements of this
part, or if the certification (or recertification) application is
incomplete and the requirement for disapproval under
paragraph (a)(4)(B) of this Section has been met, the
Agency must issue a written notice of disapproval of the
certification (or recertification) application within 120 days
of receipt. By issuing the notice of disapproval, the
provisional certification (or recertification) is invalidated
by the Agency, and the data measured and recorded by
each uncertified continuous emission or opacity monitoring
system must not be considered valid quality-assured data as
follows: from the hour of the probationary calibration error
test that began the initial certification (or recertification)
test period (if the conditional data validation procedures of
paragraph (b)(3) of this Section were used to
retrospectively validate data); or from the date and time of
completion of the invalid certification or recertification
tests (if the conditional data validation procedures of
paragraph (b)(3) of this Section were not used). The owner
or operator must follow the procedures for loss of initial
certification in paragraph (a)(5) of this Section for each
continuous emission or opacity
monitoring system which is
disapproved for initial certification. For each disapproved
recertification, the owner or operator must follow the
procedures of paragraph (b)(5) of this Section.
21.
The Agency proposes amending Appendix B Section 1.4(b). The language “
or
auxiliary monitoring system”
was added for reasons identical to those given for
errata item 19. The language “
continuous mercury emission”
was twice deleted
to clarify that all monitors within the monitoring system in the recertification
approval process are included in response to comments by the USEPA.
b)
Recertification approval process. Whenever the owner or operator makes a
replacement, modification, or change in a certified continuous mercury
emission monitoring system or auxiliary monitoring system that may
significantly affect the ability of the system to accurately measure or
record the gas volumetric flow rate, mercury concentration, percent
moisture, or to meet the requirements of Section 1.5 of this Appendix or
Exhibit B to this Appendix, the owner or operator must recertify the
continuous mercury emission
monitoring system, according to the
procedures in this paragraph. Examples of changes which require
recertification include: replacement of the analyzer; change in location or
orientation of the sampling probe or site; and complete replacement of an
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existing continuous mercury emission monitoring system. The owner or
operator must also recertify the continuous emission monitoring systems
for a unit that has recommenced commercial operation following a period
of long-term cold storage as defined in Section 225.130. Any change to a
flow monitor or gas monitoring system for which a RATA is not necessary
will not be considered a recertification event. In addition, changing the
polynomial coefficients or K factor(s) of a flow monitor will require a 3-
load RATA, but is not considered to be a recertification event; however,
records of the polynomial coefficients or K factor(s) currently in use must
be maintained on-site in a format suitable for inspection. Changing the
coefficient or K factor(s) of a moisture monitoring system will require a
RATA, but is not considered to be a recertification event; however,
records of the coefficient or K factor(s) currently in use by the moisture
monitoring system must be maintained on-site in a format suitable for
inspection. In such cases, any other tests that are necessary to ensure
continued proper operation of the monitoring system (e.g., 3-load flow
RATAs following changes to flow monitor polynomial coefficients,
linearity checks, calibration error tests, DAHS verifications, etc.) must be
performed as diagnostic tests, rather than as recertification tests. The data
validation procedures in paragraph (b)(3) of this Section must be applied
to RATAs associated with changes to flow or moisture monitor
coefficients, and to linearity checks, 7-day calibration error tests, and
cycle time tests, when these are required as diagnostic tests. When the data
validation procedures of paragraph (b)(3) of this Section are applied in this
manner, replace the word "recertification" with the word "diagnostic."
22.
The Agency proposes amending Appendix B Section 1.4(b)(3)(C). The word
“mercury” referring to mercury CEMS was deleted to include all relevant CEMS
in the recertification process in response to comments by the USEPA.
C)
Beginning with the hour of commencement of a
recertification test period, emission data recorded by the
mercury
CEMS are considered to be conditionally valid,
contingent upon the results of the subsequent recertification
tests.
23.
The Agency proposes amending Appendix B Section 1.4(b)(3)(D)(i) in order to
include a system integrity check in the recertification process. These checks are
defined and called for in 40 CFR 72.2. Language was added in response to
comments from USEPA. The system integrity check has been added in several
subsequent sections of Appendix B to include it where appropriate.
i)
For a linearity check, a system integrity check,
and/or cycle time test, 168 consecutive unit
operating hours, as defined in 40 CFR 72.2,
incorporated by reference in Section 225.140, or,
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for CEMS installed on common stacks or bypass
stacks, 168 consecutive stack operating hours, as
defined in 40 CFR 72.2;
24.
The Agency proposes amending Appendix B Sections 1.4(b)(3)(E), 1.4(b)(3)(F),
1.4(b)(3)(G), and 1.4(b)(3)(G)(i). The word “mercury” before CEMS has been
deleted in order to include all relevant CEMS, and for in response to comments
from USEPA.
E)
All recertification tests must be performed hands-off. No
adjustments to the calibration of the mercury
CEMS, other
than the routine calibration adjustments following daily
calibration error tests as described in Section 2.1.3 of
Exhibit B to this Appendix, are permitted during the
recertification test period. Routine daily calibration error
tests must be performed throughout the recertification test
period, in accordance with Section 2.1.1 of Exhibit B to
this Appendix. The additional calibration error test
requirements in Section 2.1.3 of Exhibit B to this
Appendix, must also apply during the recertification test
period.
F)
If all of the required recertification tests and required daily
calibration error tests are successfully completed in
succession with no failures, and if each recertification test
is completed within the time period specified in paragraph
(b)(3)(D)(i), (ii), or (iii) of this Section, then all of the
conditionally valid emission data recorded by the mercury
CEMS will be considered quality assured, from the hour of
commencement of the recertification test period until the
hour of completion of the required test(s).
G)
If a required recertification test is failed or aborted due to a
problem with the mercury
CEMS, or if a daily calibration
error test is failed during a recertification test period, data
validation must be done as follows:
i)
If any required recertification test is failed, it must
be repeated. If any recertification test other than a 7-
day calibration error test is failed or aborted due to a
problem with the mercury
CEMS, the original
recertification test period is ended, and a new
recertification test period must be commenced with
a probationary calibration error test. The tests that
are required in the new recertification test period
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will include any tests that were required for the
initial recertification event which were not
successfully completed and any recertification or
diagnostic tests that are required as a result of
changes made to the monitoring system to correct
the problems that caused the failure of the
recertification test. For a 2- or 3-load flow RATA, if
the relative accuracy test is passed at one or more
load levels, but is failed at a subsequent load level,
provided that the problem that caused the RATA
failure is corrected without re-linearizing the
instrument, the length of the new recertification test
period must be equal to the number of unit
operating hours remaining in the original
recertification test period, as of the hour of failure
of the RATA. However, if re-linearization of the
flow monitor is required after a flow RATA is
failed at a particular load level, then a subsequent 3-
load RATA is required, and the new recertification
test period must be 720 consecutive unit (or stack)
operating hours. The new recertification test
sequence must not be commenced until all
necessary maintenance activities, adjustments,
linearizations, and reprogramming of the CEMS
have been completed;
25.
The Agency proposes amending Appendix B Section 1.4(b)(3)(G)(ii) in order to
include a system integrity check in the recertification process, and in response to
comments from USEPA.
ii)
If a linearity check, RATA, system integrity check,
or cycle time test is failed or aborted due to a
problem with the mercury CEMS, all conditionally
valid emission data recorded by the CEMS are
invalidated, from the hour of commencement of the
recertification test period to the hour in which the
test is failed or aborted, except for the case in which
a multiple-load flow RATA is passed at one or
more load levels, failed at a subsequent load level,
and the problem that caused the RATA failure is
corrected without re-linearizing the instrument. In
that case, data invalidation will be prospective, from
the hour of failure of the RATA until the
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commencement of the new recertification test
period. Data from the CEMS remain invalid until
the hour in which a new recertification test period is
commenced, following corrective action, and a
probationary calibration error test is passed, at
which time the conditionally valid status of
emission data from the CEMS begins again;
26.
The Agency proposes amending Appendix B Section 1.4(b)(3)(G)(iv). The word
“twice” was deleted to correct an error in the language. A daily calibration
error test is failed when the results of the test exceed the performance
specifications, not by exceeding twice the specification. The reference to Section
3 of Exhibit A was also changed to Section 2.1.4 of Exhibit B to correct an
erroneous reference to the specification.
iv)
If a daily calibration error test is failed during a
recertification test period (i.e., the results of the test
exceed twice the applicable performance
specification in Section 32.1.4 of Exhibit BA to this
Appendix), the CEMS is out-of-control as of the
hour in which the calibration error test is failed.
Emission data from the CEMS will be invalidated
prospectively from the hour of the failed calibration
error test until the hour of completion of a
subsequent successful calibration error test
following corrective action, at which time the
conditionally valid status of data from the
monitoring system resumes. Failure to perform a
required daily calibration error test during a
recertification test period will also cause data from
the CEMS to be invalidated prospectively, from the
hour in which the calibration error test was due until
the hour of completion of a subsequent successful
calibration error test. Whenever a calibration error
test is failed or missed during a recertification test
period, no further recertification tests must be
performed until the required subsequent calibration
error test has been passed, re-establishing the
conditionally valid status of data from the
monitoring system. If a calibration error test failure
occurs while a linearity check or RATA is still in
progress, the linearity check or RATA must be re-
started.
27.
The Agency proposes amending Appendix B Section 1.4(b)(3)(G)(v) to reflect the
appropriate technical specifications and conditions for when trial gas injections
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and trial RATA runs are permissible. Changes reflect specific comments and
suggested changes recommended in comments from USEPA.
(v)
Trial gas injections and trial RATA runs are
permissible during the recertification test period,
prior to commencing a linearity check or RATA, for
the purpose of optimizing the performance of the
CEMS. The results of such gas injections and trial
runs must not affect the status of previously-
recorded conditionally valid data or result in
termination of the recertification test period,
provided that they meet the following specifications
and conditions:
fFor diluent gas injections, the
stable, ending monitor response is within ±5 percent
or within 5 ppm of the tag value of the reference
gas;
for 0.5% CO
2
or O
2
. For Hg vapor injections,
the stable, ending monitor response is within ± 10
percent of the value of the reference gas or 0.8
?g/scm. For RATA trial runs, the average reference
method reading and the average CEMS reading for
the run differ by no more than +- ±10% of the
average reference method value (for flow, diluent
gas, and moisture monitors), or ± 20% of the
average reference method value (for mercury
monitors), or differ by no more than 1.0% CO
2
or
O2,+-15 ppm, or 1.5% H
2
O, or +-0.02 lb/mmBtu
1.0?g/scm
from the average reference method
value, as applicable;. No no adjustments to the
calibration of the CEMS areshall be made following
the trial injection(s) or run(s), other than the
adjustments permitted under Section 2.1.3 of
Exhibit B to this Appendix and the CEMS is not
repaired, re-linearized or reprogrammed (e.g.,
changing flow monitor polynomial coefficients,
linearity constants, or K-factors) after the trial
injection(s) or run(s).
28.
The Agency proposes amending Appendix B Section 1.4(b)(3)(H) to include the
system integrity check in response to comments from USEPA.
H)
If any required recertification test is not completed within
its allotted time period, data validation must be done as
follows. For a late linearity test, RATA, system integrity
check, or cycle time test that is passed on the first attempt,
data from the monitoring system will be invalidated from
the hour of expiration of the recertification test period until
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the hour of completion of the late test. For a late 7-day
calibration error test, whether or not it is passed on the first
attempt, data from the monitoring system will also be
invalidated from the hour of expiration of the recertification
test period until the hour of completion of the late test. For
a late linearity test, RATA, system integrity check
, or cycle
time test that is failed on the first attempt or aborted on the
first attempt due to a problem with the monitor, all
conditionally valid data from the monitoring system will be
considered invalid back to the hour of the first probationary
calibration error test which initiated the recertification test
period. Data from the monitoring system will remain
invalid until the hour of successful completion of the late
recertification test and any additional recertification or
diagnostic tests that are required as a result of changes
made to the monitoring system to correct problems that
caused failure of the late recertification test.
29.
The Agency proposes amending Appendix B Section 1.4(b)(3)(I) in order to delete
inappropriate references to electronic reporting.
The Agency will not be
requiring electronic reporting.
I)
If any required recertification test of a monitoring system
has not been completed by the end of a calendar quarter
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
must indicate this by means of a suitable conditionally
valid data flag in the electronic quarterly report, and
notification within the quarterly pursuant to
225.290(b)(1)(E), report for that quarter. The owner or
operator must resubmit the report for that quarter if the
required recertification test is subsequently failed. If any
required recertification test is not completed by the end of a
particular 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 40 CFR 75.64,
incorporated by reference in Section 225.140), the test data
and results may be submitted with the earlier quarterly
report even though the test date(s) are from the next
calendar quarter. In such instances, if the recertification
test(s) are passed in accordance with the provisions of
paragraph (b)(3) of this Section, conditionally valid data
may be reported as quality-assured, in lieu of reporting a
conditional data flag. In addition, if the owner or operator
uses a conditionally valid data flag in any of the four
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quarterly reports for a given year, the owner or operator
must indicate the final status of the conditionally valid data
(i.e., resolved or unresolved) in the annual compliance
certification report required under 40 CFR 72.90 for that
year.. The Agency may invalidate any conditionally valid
data that remains unresolved at the end of a particular
calendar year.
30.
The Agency proposes amending Appendix B Section 1.4(b)(4) to delete the word
“mercury.” This is in response to comments from USEPA.
4)
Recertification application. The designated representative must
apply for recertification of each continuous mercury emission
monitoring system. The owner or operator must submit the
recertification application in accordance with 40 CFR 75.60,
incorporated by reference in Section 225.140, and each complete
recertification application must include the information specified
in 40 CFR 75.63, incorporated by reference in Section 225.140.
31.
The Agency proposes amending Appendix B Section 1.4(c) to delete the word
“mercury.” This is consistent with the deletion in errata item 22. The language
“or components” becomes redundant when all other references to the monitoring
systems have been made more general by not specifically referencing continuous
mercury emission monitors.
c)
Initial certification and recertification procedures. Prior to the applicable
deadline in 35 Ill Admin. Code 225.240(b), the owner or operator must
conduct initial certification tests and in accordance with 40 CFR 75.63,
incorporated by reference in Section 225.140, the designated
representative must submit an application to demonstrate that the
continuous emission monitoring system and components thereof meet the
specifications in Exhibit A to this Appendix. The owner or operator must
compare reference method values with output from the automated data
acquisition and handling system that is part of the continuous mercury
emission monitoring system being tested. Except as otherwise specified in
paragraphs (b)(1), (d), and (e) of this Section, and in Sections 6.3.1 and
6.3.2 of Exhibit A to this Appendix, the owner or operator must perform
the following tests for initial certification or recertification of continuous
emission monitoring systems or components
according to the
requirements of Exhibit B to this Appendix:
32.
The Agency proposes deleting current Appendix B Section 1.4(c)(1)(D) to remove
references to bias testing. Bias testing will not be required for certification,
recertification, or calibration in the proposed rule amendments.
Sections
1.4(c)(1)(E) and (F) have been re-lettered and are now Sections (D) and (E)
respectively.
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1)
For each mercury concentration monitoring system:
A)
A 7-day calibration error test;
B)
A linearity check, for mercury monitors, perform this check
with elemental mercury standards;
C)
A relative accuracy test audit must be done on a ?g/scm
basis;
D)
A bias test;
ED)
A cycle time test;
FE)
For mercury monitors a 3-level system integrity check,
using a NIST-traceable source of oxidized mercury, as
described in Section 6.2 of Exhibit A to this Appendix.
This test is not required for a mercury monitor that does not
have a converter.
33.
The Agency proposes amending Appendix B Section 1.4(c)(2)(B) to eliminate
references to level rather than to load only. All EGUs have load, and the
references to levels apply only to non-EGU sources. This elimination is in
response to USEPA comments.
B)
Relative accuracy test audits, as follows:
i)
A single-load (or single-level)
RATA at the normal
load (or level), as defined in Section 6.5.2.1(d) of
Exhibit A to this Appendix, for a flow monitor
installed on a peaking unit or bypass stack, or for a
flow monitor exempted from multiple-levelload
RATA testing under Section 6.5.2(e) of Exhibit A
to this Appendix;
ii)
For all other flow monitors, a RATA at each of the
three load levels (or operating levels) corresponding
to the three flue gas velocities described in Section
6.5.2(a) of Exhibit A to this Appendix;
34.
The Agency proposes deleting Appendix B Sections 1.4(c)(2)(C) and (D) to
remove references to bias testing for reasons identical to those given for errata
item 32.
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C)
A bias test for the single-load (or single-level) flow RATA
described in paragraph (c)(2)(B)(i) of this Section; and
D)
A bias test (or bias tests) for the 3-level flow RATA
described in paragraph (c)(2)(B)(ii) of this Section, at the
following load or operational level(s):
i)
At each load level designated as normal under
Section 6.5.2.1(d) of Exhibit A to this Appendix, for
units that produce electrical or thermal output, or
ii)
At the operational level identified as normal in
Section 6.5.2.1(d) of Exhibit A to this Appendix, for
units that do not produce electrical or thermal
output.
35.
The Agency proposes amending Appendix B Section 1.4(c)(7) to eliminate a
reference to bias testing. Language was deleted for the reasons identical to
errata item 32.
7)
For each sorbent trap monitoring system, perform a RATA, on a
?g/dscm basis, and a bias test.
36.
The Agency proposes amending Appendix B section 1.4(c)(9)(A) to delete
subsection ii. Language was removed in response to USEPA comments stating
that the absence of cyclonic flow is not essential to the testing. Subsection i has
been included in A due to the deletion of ii.
9)
The owner or operator must provide adequate facilities for initial
certification or recertification testing that include:
A)
Sampling ports adequate for test methods applicable to
such facility, such that:
i)
Vvolumetric flow rate, pollutant concentration, and
pollutant emission rates can be accurately
determined by applicable test methods and
procedures; and
ii)
A stack or duct free of cyclonic flow during
performance tests is available, as demonstrated by
applicable test methods and procedures.
37.
The Agency proposes amending Appendix B Section 1.4(d)(1) to correct a minor
error in syntax.
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1)
Redundant backups. The owner or operator of an optional
redundant backup CEMS must comply with all the requirements
for initial certification and recertification according to the
procedures specified in paragraphs (a), (b), and (c) of this Section.
The owner or operator must operate the redundant backup CEMS
during all periods of unit operation, except for periods of
calibration, quality assurance, maintenance, or repair. The owner
or operator must perform upon the redundant backup CEMS all
quality assurance and quality control procedures specified in
Exhibit B to this Appendix, except that the daily assessments in
Section 2.1 of Exhibit B to this Appendix are optional for days on
which the redundant backup CEMS is not used to report emission
data under this Partpart
. For any day on which a redundant backup
CEMS is used to report emission data, the system must meet all of
the applicable daily assessment criteria in Exhibit B to this
Appendix.
38.
The Agency proposes amending Appendix B Section 1.4(d)(2)(F) and (G) to delete
references to electronic data submission. Language was deleted for reasons
identical to errata item 29.
F)
Each regular non-redundant backup CEMS must be
represented in the monitoring plan required under Section
1.10 of this Appendix as a separate monitoring system,
with unique system and component identification numbers.
When like-kind replacement non-redundant backup
analyzers are used, the owner or operator must represent
each like-kind replacement analyzer used during a
particular calendar quarter in the monitoring plan required
under Section 1.10 of this Appendix as a component of a
primary monitoring system. The owner or operator must
also assign a unique component identification number to
each like-kind replacement analyzer, beginning with the
letters "LK" (e.g., "LK1," "LK2," etc.) and must specify the
manufacturer, model and serial number of the like-kind
replacement analyzer. This information may be added,
deleted or updated as necessary, from quarter to quarter.
The owner or operator must also report data from the like-
kind replacement analyzer using the system identification
number of the primary monitoring system and the assigned
component identification number of the like-kind
replacement analyzer. For
the purposes of the electronic
quarterly report required under 40 CFR 75.64, incorporated
by reference in Section 225.140, the owner or operator may
manually enter the appropriate component identification
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number(s) of any like-kind replacement analyzer(s) used
for data reporting during the quarter.
G)
When reporting data from a certified regular non-redundant
backup CEMS, use a method of determination (MODC)
code of "02." When reporting data from a like-kind
replacement non-redundant backup analyzer, use a MODC
of "17" (see Table 4a under Section 1.11 of this Appendix).
For the purposes of the electronic quarterly report required
under 40 CFR 75.64, incorporated by reference in Section
225.140, the owner or operator may manually enter the
required MODC of "17" for a like-kind replacement
analyzer.
39.
The Agency proposes amending Appendix B, Section 1.4(d)(2)(H) to correct an
erroneous reference. The Agency also proposes amending subsection (e) of this
Section to add the letter “a” that was inadvertently left out of a sentence.
H)
For non-redundant backup mercury CEMS and sorbent trap
monitoring systems, and for like-kind replacement mercury
analyzers, the following provisions apply in addition to, or,
in some cases, in lieu of, the general requirements in
paragraphs (d)(2)(A) through (d)(2)(GH)
of this Section:
e)
Certification/recertification procedures for either peaking unit or by-pass
stack/duct continuous emission monitoring systems. The owner or
operator of either a peaking unit or a
by-pass stack/duct continuous
emission monitoring system must comply with all the requirements for
certification or recertification according to the procedures specified in
paragraphs (a), (b), and (c) of this Section, except as follows: the owner or
operator need only perform one Nine-run relative accuracy test audit for
certification or recertification of a flow monitor installed on the by-pass
stack/duct or on the stack/duct used only by affected peaking unit(s). The
relative accuracy test audit must be performed during normal operation of
the peaking unit(s) or the by-pass stack/duct.
40.
The Agency proposes amending Appendix B Section 1.6 to include more accurate
references to the appendices to 40 CFR 60. This amendment is in response to
comments from USEPA.
Section 1.6
Reference test methods
a)
The owner or operator must use the following methods, which are found
in appendixces A-1 through A-8 to 40 CFR 60, incorporated by reference
in Section 225.140, or have been published by ASTM, to conduct the
following tests: monitoring system tests for certification or recertification
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of continuous mercury emission monitoring systems; the emission tests
required under Section 1.15(c) and (d) of this Appendix; and required
quality assurance and quality control tests:
1)
Methods 1 or 1A in appendix A-1 to 40 CFR 60
are the
reference methods for selection of sampling site and sample
traverses.
2)
Method 2 or its allowable alternatives, as provided in
appendix A-1
to 40 CFR 60, incorporated by reference in
Section 225.140, except for Methods 2B and 2E, are the
reference methods for determination of volumetric flow.
3)
Methods 3, 3A, or 3B in appendix A-2 to 40 CFR 60 are
the reference methods for the determination of the dry
molecular weight O
2
and CO
2
concentrations in the
emissions.
4)
Method 4 in appendix A-3 to 40 CFR 60 (either the
standard procedure described in Section 8.1 of the method
or the moisture approximation procedure described in
Section 8.2 of the method) must be used to correct pollutant
concentrations from a dry basis to a wet basis (or from a
wet basis to a dry basis) and must be used when relative
accuracy test audits of continuous moisture monitoring
systems are conducted. For the purpose of determining the
stack gas molecular weight, however, the alternative wet
bulb-dry bulb technique for approximating the stack gas
moisture content described in Section 2.2 of Method 4 may
be used in lieu of the procedures in Sections 8.1 and 8.2 of
the method.
5)
ASTM D6784-02, Standard Test Method for Elemental,
Oxidized, Particle-Bound and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary Sources (Ontario
Hydro Method) (incorporated by reference under Section
225.140) is the reference method for determining mercury
concentration.
A)
Alternatively, Method 29 in appendix A-8 to 40
CFR 60, incorporated by reference in Section
225.140, may be used, with these caveats: The
procedures for preparation of mercury standards and
sample analysis in Sections 13.4.1.1 through
13.4.1.3 ASTM D6784-02 (incorporated by
reference under Section 225.140) must be followed
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instead of the procedures in Sections 7.5.33 and
11.1.3 of Method 29 in appendix A-8 to 40 CFR 60,
and the QA/QC procedures in Section 13.4.2 of
ASTM D6784-02 (incorporated by reference under
Section 225.140) must be performed instead of the
procedures in Section 9.2.3 of Method 29 in
appendix A-8 to 40 CFR 60. The tester may also opt
to use the sample recovery and preparation
procedures in ASTM D6784-02 (incorporated by
reference under Section 225.140) instead of the
Method 29 in appendix A-8 to 40 CFR 60
procedures, as follows: Sections 8.2.8 and 8.2.9.1 of
Method 29 in appendix A-8 to 40 CFR 60 may be
replaced with Sections 13.2.9.1 through 13.2.9.3 of
ASTM D6784-02 (incorporated by reference under
Section 225.140); Sections 8.2.9.2 and 8.2.9.3 of
Method 29 in appendix A-8 to 40 CFR 60 may be
replaced with Sections 13.2.10.1 through 13.2.10.4
of ASTM D6784-02 (incorporated by reference
under Section 225.140); Section 8.3.4 of Method 29
in appendix A-8 to 40 CFR 60 may be replaced with
Section 13.3.4 or 13.3.6 of ASTM D6784-02 (as
appropriate) (incorporated by reference under
Section 225.140); and Section 8.3.5 of Method 29
in appendix A-8 to 40 CFR 60 may be replaced with
Section 13.3.5 or 13.3.6 of ASTM D6784-02 (as
appropriate) (incorporated by reference under
Section 225.140).
B)
Whenever ASTM D6784-02 (incorporated by
reference under Section 225.140) or Method 29 in
appendix A-8 to 40 CFR 60, incorporated by
reference in Section 225.140, is used, paired
sampling trains are required. To validate a RATA
run or an emission test run, the relative deviation
(RD), calculated according to Section 11.6 of
Exhibit D to this Appendix, must not exceed 10
percent, when the average concentration is greater
than 1.0 ?g/m
3
. If the average concentration is less
than or equal to 1.0 ?g/m
3
, the RD must not exceed
20 percent. The RD results are also acceptable if the
absolute difference between the mercury
concentrations measured by the paired trains does
not exceed 0.03 ?g/m
3
. If the RD criterion is met,
the run is valid. For each valid run, average the
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mercury concentrations measured by the two trains
(vapor phase, only).
C)
Two additional reference methods in appendix A-8
to 40 CFR 60 that may be used to measure mercury
concentration are: Method 30A, "Determination of
Total Vapor Phase Mercury Emissions from
Stationary Sources (Instrumental Analyzer
Procedure)" and Method 30B, "Determination of
Total Vapor Phase Mercury Emissions from Coal-
Fired Combustion Sources Using Carbon Sorbent
Traps".
D)
When Method 29 in appendix A-8 to 40 CFR 60,
incorporated by reference in Section 225.140, or
ASTM D6784- 02 (incorporated by reference under
Section 225.140) is used for the mercury emission
testing required under Section 1.15(c) and (d) of
this Appendix, locate the reference method test
points according to Section 8.1 of Method 30A, and
if mercury stratification testing is part of the test
protocol, follow the procedures in Sections 8.1.3
through 8.1.3.5 of Method 30A.
b)
The owner or operator may use any of the following methods, which are
found in appendix A to 40 CFR 60, incorporated by reference in Section
225.140, or have been published by ASTM, as a reference method backup
monitoring system to provide quality-assured monitor data:
1)
Method 3A in appendix A-2 to 40 CFR 60
for determining O
2
or
CO
2
concentration;
2)
Method 2 in appendix A-1 to 40 CFR 60
, or its allowable
alternatives, as provided in appendix A to 40 CFR 60, incorporated
by reference in Section 225.140, except for Methods 2B and 2E,
for determining volumetric flow. The sample point(s) for reference
methods must be located according to the provisions of Section
6.5.4 of Exhibit A to this Appendix.
3)
ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from
Coal-Fired Stationary Sources (Ontario Hydro Method)
(incorporated by reference under Section 225.140) for determining
mercury concentration;
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4)
Method 29 in appendix A-8 to 40 CFR 60, incorporated by
reference in Section 225.140, for determining mercury
concentration;
5)
Method 30A in appendix A-8 to 40 CFR 60
for determining
mercury concentration; and
6)
Method 30B in appendix A-8 to 40 CFR 60 for determining
mercury concentration.
c)
Instrumental EPA Reference Method 3A in appendices
appendix A-2 and
A-4 of 40 CFR 60, incorporated by reference in Section 225.140, must be
conducted using calibration gases as defined in Section 5 of Exhibit A to
this Appendix. Otherwise, performance tests must be conducted and data
reduced in accordance with the test methods and procedures of this part
unless the Agency:
1)
Specifies or approves, in specific cases, the use of a reference
method with minor changes in methodology;
2)
Approves the use of an equivalent method; or
3)
Approves shorter sampling times and smaller sample volumes
when necessitated by process variables or other factors.
41.
The Agency proposes amending Appendix B Section 1.7 to eliminate reference to
bias testing.
Section 1.7
Out-of-control periods and system bias testing
42.
The Agency proposes amending Appendix B Section 1.7 to include language
specifying what an out of control period is for a weekly system integrity check.
Language was added as 1.7(a)(4) in response to USEPA comments and for
reasons similar to errata item 23.
4)
For weekly system integrity checks, an out-of-control period
occurs when the error exceeds the applicable specification in
Exhibit A to this Appendix.
43.
The Agency proposes amending Appendix B Section 1.7(d) to remove references
to bias testing. See errata item 32.
d)
When the bias test indicates that a flow monitor, a diluent monitoring
system, a mercury concentration monitoring system or a sorbent trap
monitoring system is biased low (i.e., the arithmetic mean of the
differences between the reference method value and the monitor or
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monitoring system measurements in a relative accuracy test audit exceed
the bias statistic in Section 7 of Exhibit A to this Appendix), the owner or
operator must adjust the monitor or continuous emission monitoring
system to eliminate the cause of bias such that it passes the bias test.
44.
The Agency proposes amending Appendix B Section 1.8(a)(1) Equation 8. Add
the language “or stack” in the numerator and denominator of the equation for a
minor clarification.
Total unit or stack operating hours
for which quality-assured data
Percent
was recorded for the calendar quarter
monitor data =
X 100 (Eq. 8)
availability
Total unit or stack
operating hours
for the calendar quarter
45.
The Agency proposes deleting Appendix B Section 1.10(c) to eliminate references
to electronic data submission. See errata item 29.
c)
Contents of monitoring plan for specific situations. The following
additional information must be included in the monitoring plan for the
specific situations described. For each monitoring system recertification,
maintenance, or other event, the designated representative must include
the following additional information in electronic format in the monitoring
plan:
1)
Component/system identification code;
2)
Event code or code for required test;
3)
Event begin date and hour;
4)
Conditionally valid data period begin date and hour (if applicable);
5)
Date and hour that last test is successfully completed; and
6)
Indicator of whether conditionally valid data were reported at the
end of the quarter.
46.
The Agency proposes re-lettering Appendix B Section 1.10(d) due to the prior
deletion of Section 1.10(c). Also, language was added to require electronic
storage of data and to make the data available to the Agency upon request.
cd)
Contents of the mercury monitoring plan. The requirements of paragraph
(d) of this Section must be met on and after July 1, 2009. Each monitoring
plan must contain the information in paragraph (d)(1) of this Section in
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electronic format and the information in paragraph (d)(2) of this Section in
hardcopy format. Electronic storage of all monitoring plan information,
including the hardcopy portions, is permissible provided that a paper copy
of the information
entire monitoring plan can be furnished upon request
for audit purposes.
1)
ElectronicThe following information must be retained on site in
electronic storage and furnished to the Agency in hardcopy, upon
request for audit purposes.
47.
The Agency proposes amending Appendix B Section 1.10(a)(1)(B) to include
moisture as a monitored parameter. Prior omission of moisture as a parameter
was an oversight.
B)
For each monitored parameter (i.e., mercury concentration,
diluent concentration, moisture,
or flow) at each monitoring
location, specify the monitoring methodology for the
parameter. If the unmonitored bypass stack approach is
used for a particular parameter, indicate this by means of an
appropriate code. Provide the activation date/hour, and
deactivation date/hour (if applicable) for each monitoring
methodology.
48.
The Agency proposes deleting Appendix B Section 1.10(a)(1)(E)(vii). The
references to default high range value only apply to SO
2
and NO
x
, and are
inappropriate for this section. The deletion was made in response to USEPA
comments. A period was added to 1.10(a)(1)(E)(vi) to correct grammar.
vi)
Effective date/hour, and (if applicable) inactivation
date/hour of each span value;.
vii)
The default high range value (if applicable) and the
maximum allowable low-range value for this
option.
49.
The Agency proposes amending Appendix B Section 1.10(a)(2)(B) to correct an
erroneous reference.
B)
Description of site locations for each monitoring
component in the continuous emission monitoring systems,
including schematic diagrams and engineering drawings
specified in 40 CFR 75.53(ge)(2)(iv)
and (ge)(2)(v),
incorporated by reference in Section 225.140, and any other
documentation that demonstrates each monitor location
meets the appropriate siting criteria.
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50.
The Agency proposes amending Appendix B Section 1.10(a)(2)(D) to correct an
erroneous reference.
D)
For units monitored by a continuous emission monitoring
system, a schematic diagram identifying entire gas handling
system from boiler to stack for all affected units, using
identification numbers for units, monitoring systems and
components, and stacks corresponding to the identification
numbers provided in paragraphs (cd)(1)(A)
and (cd)(1)(C)
of this Section. The schematic diagram must depict stack
height and the height of any monitor locations.
Comprehensive and/or separate schematic diagrams must
be used to describe groups of units using a common stack.
51.
The Agency proposes amending Appendix B Section 1.11(a)(5) to require
hardcopy submission of monitoring plans submitted to the Agency.
5)
The current monitoring plan as specified in Section 1.10 of this
Appendix, beginning with the initial hardcopy submission to the
Agency required by 40 CFR 75.62, incorporated by reference in
Section 225.140; and
52.
The Agency proposes amending Appendix B Section 1.11(b)(3) through (7) so that
sources are required to submit hourly gross load or steam load, and not both.
Subsequent subsections were renumbered appropriately. Deletion of language in
(b)(4) and (7) was in response to USEPA comments and better reflects a revision
to 40 CFR Part 75.
3)
Hourly gross unit load (rounded to nearest MWge), or
4)
Ssteam load in 1000 lbs/hr at stated temperatures and pressures,
rounded to the nearest 1000 lbs/hr;
45)
Operating load range corresponding to hourly gross load of 1 to 10,
except for units using a common stack, which may use up to 20
load ranges for stack gasor fuel flow rate, as specified in the
monitoring plan;
56)
Hourly heat input rate (mmBtu/hr, rounded to the nearest tenth);
67)
Identification code for formula used for heat input, as provided in
Section 1.10 of this Appendix; and
78)
For Mercury CEMS units only, F-factor for heat input calculation
and indication of whether the diluent cap was used for heat input
calculations for the hour.
Electronic filing - Received, Clerk's Office, January 14, 2009
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53.
The Agency proposes amending Appendix B Section 1.11(e)(1)(C) to remove an
erroneous reference to sorbent trap systems. Section (e) deals only with CEMS
monitoring, while (f) addresses sorbent trap systems. Also, amend 1.11(e)(1)(D)
to use Codes 1-54, as Code 55 has been deleted in errata item 36.
C)
Hourly mercury concentration (µg/scm, rounded to the
nearest tenth); For a particular pair of sorbent traps, this
will be the flow-proportional average concentration for the
data collection period;
D)
Method of determination for hourly mercury concentration
using Codes 1-5455 in Table 4a of this Section; and
54.
The Agency proposes amending Appendix B Section 1.11(f)(8) Table 4a to remove
Code 55. Code 55 was removed from the table to remove a reference to data
substitution. Missing data procedures were removed in the initial filing of this
rulemaking.
Table 4a.--
Codes for Method of Emissions and Flow Determination
-----------------------------------------------------------
--------------------
Code
Hourly emissions/flow measurement or estima
tion method
-----------------------------------------------------------
--------------------
1 ..... Certified primary emission/flow monitoring system.
2 ..... Certified backup emission/flow monitoring system.
3 ..... Approved alternative monitoring system.
4 ..... Reference method:
17 .... Like-kind replacement non-
redundant backup analyzer.
32 .... Hourly Hg concentration determined from analysis of
a
single trap_multiplied by a factor of 1.111 when one of the
paired traps is invalidated or damaged (See Exhibit D
Appendix
K, section 8).
33 .... Hourly Hg concentration determined from the trap re
sulting in the higher Hg concentration when the relative de
viation criterion for the paired traps is not met (See Exhi
bit D Appendix
K, section 8).
40 .... Fuel specific default value (or prorated default va
lue) used for the hour.
54 .... Other quality assured methodologies approved throug
h petition. These hours are included in missing data lookba
ck and are treated as unavailable hours for percent monitor
Electronic filing - Received, Clerk's Office, January 14, 2009
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availability calculations.
55 .... Other substitute data approved through petition. Th
ese hours are not included in missing data lookback and are
treated as unavailable hours for percent monitor availabil
ity calculations.
55.
The Agency proposes amending, in response to USEPA comments, Appendix B
Section 1.13(a) to include a requirement that EGUs use “calibration gas” to
calibrate and certify applicable equipment.
a)
Continuous emission monitoring systems.
The owner or operator must
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. Further,
the owner or operator must verify (e.g., by means of a certificate or data
from the cylinder gas vendor or CEMS vendor) that only “calibration gas”
(as defined in 40 CFR 72.2, incorporated by reference in Section 225.140
and in Exhibit A to this Appendix) is used for all required calibration error
test, linearity checks, and system integrity checks.
56.
The Agency proposes amending Appendix B Section 1.13(a)(1). System integrity
checks are performed weekly, not daily. Language was changed in response to
USEPA comments.
1)
For each flow monitor, mercury monitor, or diluent gas monitor
(including wet- and dry-basis O
2
monitors used to determine
percent moisture), the owner or operator must record the following
for all daily and 7-day calibration error tests, all dailyweekly
system integrity checks, and all off-line calibration demonstrations,
including any follow-up tests after corrective action:
57.
The Agency proposes amending Appendix B Section 1.13(a)(1)(F) to include
language necessary for system integrity checks. Measurement error, not
calibration error, is appropriate for system integrity checks. Language was
added in response to USEPA comments.
F)
Percent calibration or measurement error (rounded to the
nearest tenth of a percent) (flag if using alternative
performance specification for low emitters or differential
pressure flow monitors);
58.
The Agency proposes amending Appendix B Section 1.13(a)(1)(I), (J), and (K).
Language was removed because more general reference to calibration gasses has
been added in 1.13(a). Subsections (J) and (K) have been appropriately re-
lettered.
Electronic filing - Received, Clerk's Office, January 14, 2009
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I)
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 40 CFR
72.2, incorporated by reference in Section 225.140, and
Exhibit A to this Appendix, was used to conduct calibration
error testing;
IJ)
Description of any adjustments, corrective actions, or
maintenance prior to a passed test or following a failed test;
and
JK)
Indication of whether the unit is off-line or on-line.
59.
The Agency proposes amending Appendix B Section 1.13(a)(3)(H) to include
language for measurement error. Language was added for reasons identical to
errata item 39.
H)
Linearity error or measurement error at each of the
reference gas concentrations (rounded to nearest tenth of a
percent) (flag if using alternative performance
specification);
60.
The Agency proposes amending, in response to USEPA comments, Appendix B
Section 1.13(a)(5)(B)(xii) to remove language that applies only to non-EGUs.
Non-EGUs are not affected by this rule.
xii)
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), except
for units that do not produce electrical or thermal
output; and
61.
The Agency proposes amending Appendix B Section 1.13(a)(5)(C)(v) to remove
language that applies only to non-EGUs. This was in response to comments from
the USEPA.
v)
Relative accuracy test results, as specified in
Equation A–10 in Exhibit A to this Appendix. For
multi-levelload
flow monitor tests the relative
accuracy test results must be recorded at each load
(or operating) level tested. Each load (or operating)
level must be expressed as a total gross unit load,
rounded to the nearest MWe, or as steam load,
rounded to the nearest thousand lb/hr, or as
otherwise specified by the Agency, for units that do
not produce electrical or thermal output;
Electronic filing - Received, Clerk's Office, January 14, 2009
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62.
The Agency proposes amending Appendix B Section 1.13(a)(5)(C)(vi) to remove
references to bias testing. See errata item 32.
vi)
Bias test results as specified in Section 7.4.4 in
Exhibit A to this Appendix; and
63.
The Agency proposes amending Appendix B Section 1.13(a)(5)(E) for a minor
rewording. Language was changed in response to USEPA comments.
E)
For flow monitors, the equation used to
linearizecharacterize the flow monitor and the numerical
values of the polynomial coefficients or K factor(s) of that
equation.
64.
The Agency proposes amending Appendix B Section 1.13(a)(7)(D) to make a
minor clarification that 3A is a reference method.
D)
For each RATA using Reference Method or3A in appendix
A to 40 CFR 60, incorporated by reference in Section
225.140, to determine, CO
2
, or O
2
concentration:
65.
The Agency proposes amending, in response to USEPA comments, Appendix B
Section 1.13(a)(7)(G)(vi) through (x) to remove the “m” from the abbreviation of
gram, as a “g” is the preferred and accepted abbreviation.
vi)
Particle-bound mercury collected by the filter,
blank, and probe rinse (?gm)
;
vii)
Oxidized mercury collected by the KCl impingers
(?gm);
viii)
Elemental mercury collected in the HNO
3
/H
2
O
2
impinger and in the KMnO
4
/H
2
SO
4
impingers
(?gm);
ix)
Total mercury, including particle-bound mercury
(?gm); and
x)
Total mercury, excluding particle-bound mercury
(?gm)
66.
The Agency proposes amending Appendix B Section 1.13(a)(10)(B) and (C) to
remove unnecessary references to testing of SO
2
and NO
x
equipment.
Electronic filing - Received, Clerk's Office, January 14, 2009
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B)
For each reference method test run using Method 6C, 7E,
or 3A in appendix A to 40 CFR 60, incorporated by
reference in Section 225.140, to determine SO
2
, NO
x
,CO
2
,
or O
2
concentration:
i)
Unit or stack identification number;
ii)
The reference method system and component
identification numbers;
iii)
Run number;
iv)
Run start date and hour;
v)
Run end date and hour;
vi)
The data in paragraphs (a)(7)(D)(ii) through (ix)
and (xii) through (xv); and (vii) Stack gas density
adjustment factor (if applicable).
C)
For each reference method test run using Method 6C, 7E,
or 3A in appendix A to 40 CFR 60, incorporated by
reference in Section 225.140, to determine SO
2
, NO
x
,CO
2
,
or O
2
concentration:
67.
The Agency proposes deleting Appendix B Section 1.13(a)(12)(A)(vi). Language
was removed because it applies only to SO
2
monitor RATA exemptions.
Subsection (vii) and (viii) have been re-numbered appropriately.
vi)
Year to date hours of usage of fuel other than very
low sulfur fuel;
vii)
Year to date hours of non-redundant back-up CEMS
usage at the unit/stack; and
viii)
Quarter and year.
68.
The Agency proposes amending Appendix B Sections 1.13(a)(12)(C) and (D).
1.13(a)(12)(C) was deleted because it refers only to fuel flow meters. Coal-fired
units do not use fuel flow meters. Paragraph D has been re-lettered
appropriately. Also, language applying only to non-EGUs was removed for
reasons identical to errata item 33.
C)
For a fuel flowmeter accuracy test extension:
i)
Component-system identification code;
Electronic filing - Received, Clerk's Office, January 14, 2009
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ii)
Date of last accuracy test;
iii)
Accuracy test expiration date without extension;
iv)
Accuracy test expiration date with extension;
v)
Type of extension; and
vi)
Quarter and year.
CD)
For a single-load (or single-level) flow RATA claim:
i)
Monitoring system identification code;
ii)
Ending date of last annual flow RATA;
iii)
The relative frequency (percentage) of unit or stack
operation at each load (or operating)
level (low,
mid, and high) since the previous annual flow
RATA, to the nearest 0.1 percent;
iv)
End date of the historical load (or operating level)
data collection period; and
v)
Indication of the load (or operating) level (low, mid
or high) claimed for the single-load flow RATA.
69.
The Agency proposes amending Appendix B Section 1.13(d) to remove a reference
to missing data procedures. See errata item 36.
d)
DAHS Verification.
For each DAHS (missing data and formula)
verification that is required for initial certification, recertification, or for
certain diagnostic testing of a monitoring system, record the date and hour
that the DAHS verification is successfully completed. (This requirement
only applies to units that report monitoring plan data in accordance with
Section 1.10(d) of this Appendix.)
70.
The Agency proposes amending Appendix B Section 1.14(a) to replace the
general language “such a program” with the more specific “Part 225.”
Replaced language was unnecessarily vague.
a)
Applicability. The owner or operator of a unit must comply with the
requirements of this Appendix to the extent that compliance is required by
Part 225. For purposes of this Appendix, the term "affected unit" means
any coal-fired unit (as defined in 40 CFR 72.2, incorporated by reference)
Electronic filing - Received, Clerk's Office, January 14, 2009
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that is subject to Part 225. The term "non-affected unit" means any unit
that is not subject to such a programPart 225, the term "permitting
authority" means the Agency, and the term "designated representative"
means the responsible party under Part 225.
71.
The Agency proposes amending Appendix B Section 1.15(d)(1) to remove
language referring to electronic submission of data. See errata item 29.
1)
The results of the mercury emission testing performed under
paragraph (c) of this Section must be submitted as a certification
application to the permitting authority, no later than 45 days after
the testing is completed. The calculations demonstrating that the
unit emits 464 ounces (or less) per year of mercury must also be
provided, and the default mercury concentration that will be used
for reporting under Section 1.18 of this Appendix must be
specified in both
the electronic and hard copy portions of the
monitoring plan for the unit. The methodology is considered to be
provisionally certified as of the date and hour of completion of the
mercury emission testing.
72.
The Agency proposes amending Appendix B Section 1.15(d)(4)(C) for a minor
rewording.
C)
Thereafter, retesting must will be required either
semiannually or annually (i.e., by the end of the second or
fourth QA operating quarter following the quarter of the
previous test), depending on the results of the previous test.
To determine whether the next retest is due within two or
four QA operating quarters, substitute the highest mercury
concentration from the current test or 0.50 µg/scm
(whichever is greater) into the equation in paragraph (c)(2)
of this Section. If the estimated annual mercury mass
emissions exceeds 144 ounces, the next test is due within
two QA operating quarters. If the estimated annual mercury
mass emissions is 144 ounces or less, the next test is due
within four QA operating quarters.
73.
The Agency proposes amending Appendix B Section 1.18(c)(3) to correct an
erroneous reference.
3)
Contents of the monitoring plan. Each monitoring plan must
contain the information in Section 1.10(cd)(1) of this Appendix in
electronic format and the information in Section 1.10(cd)(2) in
hardcopy format.
74.
The Agency proposes amending Appendix B Section 1.18(e) to remove references
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to electronic data submission. See errata item 29.
e)
Monitoring plan reporting.
1)
Electronic submission. The designated representative for an
affected unit must submit to the Agency and USEPA, or an
alternate Agency designee if one is specified, a complete,
electronic, up-to-date monitoring plan file in a format specified by
the Agency for each affected unit or group of units monitored at a
common stack and each non-affected unit under Section
1.16(b)(2)(B) of this Appendix, as follows: No later than 21 days
prior to the commencement of initial certification testing; at the
time of a certification or recertification application submission; and
whenever an update of the electronic monitoring plan is required,
either under Section 1.10 of this Appendix or elsewhere in this
Appendix.
2)
Hardcopy submission. The designated representative of an affected
unit must submit all of the hardcopy information required under
Section 1.10 of this Appendix, for each affected unit or group of
units monitored at a common stack and each non-affected unit
under Section 1.16(b)(2)(B) of this Appendix, to the Agency prior
to initial certification. Thereafter, the designated representative
must submit hardcopy information only if that portion of the
monitoring plan is revised. The designated representative must
submit the required hardcopy information as follows: no later than
21 days prior to the commencement of initial certification testing;
with any certification or 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 Section 1.10(b)
of this Appendix. 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.
75.
The Agency proposes amending Section 1.18(f) to include requirements for
submitting quarterly reports in the appropriate manner, and to remove references
to electronic data submission consistent with errata item 29.
f)
Quarterly reports. EGUs using CEMS or excepted monitoring systems
must submit quarterly reports pursuant to the requirements in Section
225.290(b).
1)
Electronic submission. Electronic quarterly reports must be
submitted, beginning with the calendar quarter containing the
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
compliance date in Section 1.14(b) of this Appendix, unless
otherwise specified in 35 Ill. Admin. Code Part 225. The
designated representative for an affected unit must report the data
and information in this paragraph (f)(1) and the applicable
compliance certification information in paragraph (f)(2) of this
Section to the Agency and USEPA, or an alternate Agency
designee if one is specified, quarterly in a format specified by the
Agency, except as otherwise provided in 40 CFR 75.64(a),
incorporated by reference in Section 225.140, for units in long-
term cold storage. Each electronic report must be submitted to the
Agency within 45 days following the end of each calendar quarter.
Except as otherwise provided in 40 CFR 75.64(a)(4) and (a)(5),
incorporated by reference in Section 225.140, each electronic
report must include the date of report generation and the following
information for each affected unit or group of units monitored at a
common stack:
A)
The facility information in 40 CFR 75.64(a)(3),
incorporated by reference in Section 225.140; and
B)
The information and hourly data required in paragraphs (a)
and (b) of this Section, except for:
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)
For units with flue gas desulfurization systems or
with add-on mercury emission controls, the
parametric information in Section 1.12 of this
Appendix;
iv)
Information required by Section 1.11(d) of this
Appendix concerning the causes of any missing
data periods and the actions taken to cure such
causes;
v)
Hardcopy monitoring plan information required by
Section 1.10 of this Appendix and hardcopy test
data and results required by Section 1.13 of this
Appendix;
vi)
Records of flow polynomial equations and
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numerical values required by Section 1.13(a)(5)(E)
of this Appendix;
vii)
Stratification test results required as part of the
RATA supplementary records under Section
1.13(a)(7) of this Appendix;
viii)
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;
ix)
Supplementary RATA information required under
Section 1.13(a)(7) of this Appendix, except that: the
applicable data elements under Section
1.13(a)(7)(B)(i) through (xx) of this Appendix and
under Section 1.13(a)(7)(C)(i) through (xiii) of this
Appendix must be reported for flow RATAs at
circular or rectangular stacks (or ducts) in which
angular compensation for yaw and/or pitch angles is
used (i.e., Method 2F or 2G in appendices A-1 and
A-2 to 40 CFR 60, incorporated by reference in
Section 225.140), with or without wall effects
adjustments; the applicable data elements under
Section 1.13(a)(7)(B)(i) through (xx) of this
Appendix and under Section 1.13(a)(7)(C)(i)
through (xiii) of this Appendix must be reported for
any flow RATA run at a circular stack in which
Method 2 in appendices A-1 and A-2 to 40 CFR 60,
incorporated by reference in Section 225.140, is
used and a wall effects adjustment factor is
determined by direct measurement; the data under
Section 1.13(a)(7)(B)(xx) of this Appendix must be
reported for all flow RATAs at circular stacks in
which Method 2 in appendices A-1 and A-2 to 40
CFR 60, incorporated by reference in Section
225.140, is used and a default wall effects
adjustment factor is applied; and the data under
Section 1.13(a)(7)(I)(i) through (vi) must be
reported for all flow RATAs at rectangular stacks or
ducts in which Method 2 in appendices A-1 and A-2
to 40 CFR 60, incorporated by reference in Section
225.140, is used and a wall effects adjustment factor
is applied.
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x)
For units using sorbent trap monitoring systems, the
hourly gas flow meter readings taken between the
initial and final meter readings for the data
collection period; and
C)
Ounces of mercury emitted during quarter and cumulative
ounces of mercury emitted in the year-to-date (rounded to
the nearest thousandth); and
D)
Unit or stack operating hours for quarter, cumulative unit or
stack operating hours for year-to-date; and
E)
Reporting period heat input (if applicable) and cumulative,
year-to-date heat input.
2)
Compliance certification.
A)
The designated representative must certify that the
monitoring plan information in each quarterly electronic
report (i.e., component and system identification codes,
formulas, etc.) represent current operating conditions for
the affected unit(s)
B)
The designated representative must submit and sign a
compliance 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 must state that:
i)
The monitoring data submitted were recorded in
accordance with the applicable requirements of this
Appendix, including the quality assurance
procedures and specifications; and
ii)
With regard to a unit with an FGD system or with
add-on mercury emission controls, that for all hours
where mercury data is missing in accordance with
Section 1.13(b) of this Appendix, the add-on
emission controls were operating within the range
of parameters listed in the quality-assurance plan
for the unit (or that quality-assured SO
2
CEMS data
were available to document proper operation of the
emission controls).
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3)
Additional reporting requirements. The designated representative
must also comply with all of the quarterly reporting requirements
in 40 CFR 75.64(d), (f), and (g), incorporated by reference in
Section 225.140.
76.
The Agency proposes amending Exhibit A, Section 2.1 to reflect language in
Exhibit A, Section 2.1.3.4, which provides that Section 2.1 does not apply to
mercury monitoring systems.
2.1 Instrument Span and Range
In implementing Sections 2.1.1 through 2.1.2 of this Exhibit, set the measurement
range for each parameter (CO
2
, O
2
, or flow rate) high enough to prevent full-scale
exceedances from occurring, yet low enough to ensure good measurement accuracy
and to maintain a high signal-to-noise ratio. To meet these objectives, select the range
such that the majority of the readings obtained during typical unit operation are kept,
to the extent practicable, between 20.0 and 80.0 percent of the full-scale range of the
instrument. These guidelines do not apply to mercury monitoring systems.
77.
The Agency proposes amending Exhibit A, Section 2.1.1. In response to a request
at the December 17, 2008, hearing, the Agency proposes deleting electronic
recordkeeping and/or reporting requirements where appropriate.
2.1.1 CO
2
and O
2
Monitors
For an O
2
monitor (including O
2
monitors used to measure CO
2
emissions or
percentage moisture), select a span value between 15.0 and 25.0 percent O
2
. For a
CO
2
monitor installed on a boiler, select a span value between 14.0 and 20.0 percent
CO
2
. For a CO
2
monitor installed on a combustion turbine, an alternative span value
between 6.0 and 14.0 percent CO
2
may be used. An alternative CO
2
span value below
6.0 percent may be used if an appropriate technical justification is included in the
hardcopy monitoring plan. An alternative O
2
span value below 15.0 percent O
2
may
be used if an appropriate technical justification is included in the monitoring plan
(e.g., O
2
concentrations above a certain level create an unsafe operating condition).
Select the full-scale range of the instrument to be consistent with Section 2.1 of this
Exhibit 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 Exhibit, as percentages of the span value. For O
2
monitors
with span values >=21.0 percent O
2
, purified instrument air containing 20.9 percent
O
2
may be used as the high-level calibration material. If a dual-range or autoranging
diluent analyzer is installed, the analyzer may be represented in the monitoring plan
as a single component, using a special component type code specified by the USEPA
to satisfy the requirements of 40 CFR 75.53(e)(1)(iv)(D), incorporated by reference in
Section 225.140.
78.
In response to a comment received from USEPA, the Agency proposes amending
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Exhibit A, Section 2.1.2.1 to delete portions regarding units that do not produce
electrical or thermal output, as such units are not subject to the Agency’s
proposed rule.
2.1.2.1 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 40 CFR 60, incorporated by
reference in Section 225.140. If using test values, use the highest average velocity
(determined from the Method 2 traverses) measured at or near the maximum unit
operating load (or, for units that do not produce electrical or thermal output, at the normal
process operating conditions corresponding to the maximum stack gas flow rate).
Express the MPV in units of wet standard feet per minute (fpm). For the purpose of
providing substitute data during periods of missing flow rate data in accordance with Sec
75.31 and 75.33 of 40 CFR Part 75 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 ft
2
) at the flow monitor location.
79.
In response to a request at the December 17, 2008, hearing that the Agency delete
remaining references to bias adjustment factor if appropriate, the Agency
proposes deleting Exhibit A, Sections 3.4, 3.4.1, and 3.4.2, and renumbering
Section 3.5 accordingly.
3.4 Bias
3.4.1 Flow Monitors
Flow monitors must not be biased low as determined by the test procedure in Section
7.4 of this Exhibit. The bias specification applies to all flow monitors including those
measuring an average gas velocity of 10.0 fps or less.
3.4.2 Mercury Monitoring Systems
Mercury concentration monitoring systems and sorbent trap monitoring systems must
not be biased low as determined by the test procedure in Section 7.4 of this Exhibit.
3.45
Cycle Time
The cycle time for mercury concentration monitors, oxygen monitors used to
determine percent moisture, and any other monitoring component of a continuous
emission monitoring system that is required to perform a cycle time test must not
exceed 15 minutes.
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80.
The Agency proposes amending Exhibit A, Section 6.3.2 by changing the date in
subsection (a) to July 1, 2009, in order to be consistent with dates in Part 225.
6.3.2 Flow Monitor 7-day Calibration Error Test
Flow monitors installed on peaking units (as defined in 40 CFR 72.2, incorporated by
reference in Section 225.140) are exempted from the 7-day calibration error test
requirements of this part. In all other cases, perform the 7-day calibration error test of
a flow monitor, when required for certification, recertification or diagnostic testing,
according to the following procedures. Introduce the reference signal corresponding
to the values specified in Section 2.2.2.1 of this Exhibit to the probe tip (or
equivalent), or to the transducer. During the 7-day certification test period, conduct
the calibration error test while the unit is operating once each unit operating day (as
close to 24-hour intervals as practicable). In the event that unit outages occur after the
commencement of the test, the 7 consecutive operating days need not be 7
consecutive calendar days. Record the flow monitor responses by means of the data
acquisition and handling system. Calculate the calibration error using Equation A-6 of
this Exhibit. 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 Exhibit B to this Appendix. 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 must be determined
as follows:
(a) For initial certification, data from the monitor are considered invalid until all
certification tests, including the 7-day calibration error test, have been successfully
completed, unless the conditional data validation procedures in Section 1.4(b)(3) of
this Appendix are used. When the procedures in Section 1.4(b)(3) of this Appendix
are followed, the words "initial certification" apply instead of "recertification," and
complete all of the initial certification tests by JulyJanuary
1, 2009, rather than within
the time periods specified in Section 1.4(b)(3)(D) of this Appendix 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 Section 1.4(b)(3).
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
×
100
−
=
S
RA
CE
(Equation A-6)
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 Exhibit.
A = Actual flow monitor response to the reference value.
S = Flow monitor calibration span value as determined under Section 2.1.2.2 of this
Exhibit.
81.
The Agency proposes amending Exhibit A, Section 6.4 to change references to
January 1, 2009, to July 1, 2009, in order to be consistent with dates in Part 225.
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. Use a zero-level and a high-level calibration gas (as defined in Section
5.2 of this Exhibit) alternately. For mercury monitors, the calibration gas used for this
test may either be the elemental or oxidized form of mercury. To determine the
downscale cycle time, measure the concentration of the flue gas emissions until the
response stabilizes. Record the stable emissions value. Inject a zero-level
concentration calibration gas into the probe tip (or injection port leading to the
calibration cell, for in situ systems with no probe). Record the time of the zero gas
injection, using the data acquisition and handling system (DAHS). Next, allow the
monitor to measure the concentration of the zero gas until the response stabilizes.
Record the stable ending calibration gas reading. Determine the downscale cycle time
as the time it takes for 95.0 percent of the step change to be achieved between the
stable stack emissions value and the stable ending zero gas reading. Then repeat the
procedure, starting with stable stack emissions and injecting the high-level gas, to
determine the upscale cycle time, which is the time it takes for 95.0 percent of the
step change to be achieved between the stable stack emissions value and the stable
ending high-level gas reading. Use the following criteria to assess when a stable
reading of stack emissions or calibration gas concentration has been attained. A stable
value is equivalent to a reading with a change of less than 2.0 percent of the span
value for 2 minutes, or a reading with a change of less than 6.0 percent from the
measured average concentration over 6 minutes. Alternatively, the reading is
considered stable if it changes by no more than 0.5 ppm, 0.5 ?g/m
3
(for mercury) for
two minutes. (Owners or operators of systems which do not record data in 1-minute
or 3-minute intervals may petition the Agency 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
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
produce the longest possible cycle time. Refer to Figures 6a and 6b in this Exhibit for
example calculations of upscale and downscale cycle times. Report the slower of the
two cycle times (upscale or downscale) as the cycle time for the analyzer. On and
after JulyJanuary
1, 2009, record the cycle time for each component analyzer
separately. For time-shared systems, perform the cycle time tests at each probe
locations that will be polled within the same 15-minute period during monitoring
system operations. To determine the cycle time for time-shared systems, at each
monitoring location, report the sum of the cycle time observed at that monitoring
location plus the sum of the time required for all purge cycles (as determined by the
continuous emission monitoring system manufacturer) at each of the probe locations
of the time-shared systems. For monitors with dual ranges, report the test results for
each range separately. Cycle time test results are acceptable for monitor or
monitoring system certification, recertification or diagnostic testing if none of the
cycle times exceed 15 minutes. The status of emissions data from a monitor prior to
and during a cycle time test period must be determined as follows:
(a) For initial certification, data from the monitor are considered invalid until all
certification tests, including the cycle time test, have been successfully completed,
unless the conditional data validation procedures in Section 1.4(b)(3) of this
Appendix are used. When the procedures in Section 1.4(b)(3) of this Appendix are
followed, the words "initial certification" apply instead of "recertification," and
complete all of the initial certification tests by JulyJanuary
1, 2009, rather than within
the time periods specified in Section 1.4(b)(3)(D) of this Appendix 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 Section 1.4(b)(3) of this Appendix.
82.
In response to a request at the December 17, 2008, hearing that the Agency delete
remaining references to bias adjustment factor if appropriate, the Agency
proposes deleting the reference to bias tests in the title of Exhibit A, Section 6.5.
6.5 Relative Accuracy and Bias Tests (General Procedures)
83.
In response to a comment received from USEPA, the Agency proposes deleting
subsection (e) of Exhibit A, Section 6.5.2, as units that do not produce electrical
or thermal output are not subject to the Agency’s proposed rule.
6.5.2 Flow Monitor RATAs (Special Considerations)
(a) Except as otherwise provided in paragraph (b) or (e)
of this Section, perform
relative accuracy test audits for the initial certification of each flow monitor at three
different exhaust gas velocities (low, mid, and high), corresponding to three different
load levels or operating levels within the range of operation, as defined in Section
6.5.2.1 of this Exhibit. For a common stack/duct, the three different exhaust gas
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
velocities may be obtained from frequently used unit/load or operating level
combinations for the units exhausting to the common stack. Select the three exhaust
gas velocities such that the audit points at adjacent load or operating levels (i.e., low
and mid or mid and high), in megawatts (or in thousands of lb/hr of steam production
or in ft/sec, as applicable), are separated by no less than 25.0 percent of the range of
operation, as defined in Section 6.5.2.1 of this Exhibit.
(b) For flow monitors on bypass stacks/ducts and peaking units, the flow monitor
relative accuracy test audits for initial certification and recertification must be single-
load tests, performed at the normal load, as defined in Section 6.5.2.1(d) of this
Exhibit.
(c) Flow monitor recertification RATAs must be done at three load level(s) (or three
operating levels), unless otherwise specified in paragraph (b) or (e)
of this Section or
unless otherwise specified or approved by the Agency.
(d) The semiannual and annual quality assurance flow monitor RATAs required
under Exhibit B to this Appendix must be done at the load level(s) (or operating
levels) specified in Section 2.3.1.3 of Exhibit B to this Appendix.
(e) For flow monitors installed on units that do not produce electrical or thermal
output, the flow RATAs for initial certification or recertification may be done at
fewer than three operating levels, if:
(1) The owner or operator provides a technical justification in the hardcopy portion of
the monitoring plan for the unit required under 40 CFR 75.53(e)(2), incorporated by
reference in Section 225.140, demonstrating that the unit operates at only one level or
two levels during normal operation (excluding unit startup and shutdown).
Appropriate documentation and data must be provided to support the claim of single-
level or two-level operation; and
(2) The justification provided in paragraph (e)(1) of this Section is deemed to be
acceptable by the permitting authority.
84.
In response to a comment received from USEPA, the Agency proposes amending
Exhibit A, Section 6.5.2.1 to delete portions of the Section concerning units that
do not produce electrical or thermal output, as such units are not subject to the
Agency’s proposed rule.
6.5.2.1 Range of Operation and Normal Load (or Operating) Level(s)
(a) The owner or operator must determine the upper and lower boundaries of the
"range of operation" as follows for each unit (or combination of units, for common
stack configurations):
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
(1) For affected units that produce electrical output (in megawatts) or thermal output
(in klb/hr of steam production or mmBtu/hr), the lower boundary of the range of
operation of a unit must be the minimum safe, stable loads for any of the units
discharging through the stack. Alternatively, for a group of frequently-operated units
that serve a common stack, the sum of the minimum safe, stable loads for the
individual units may be used as the lower boundary of the range of operation. The
upper boundary of the range of operation of a unit must be the maximum sustainable
load. The "maximum sustainable load" is the higher of either: the nameplate or rated
capacity of the unit, less any physical or regulatory limitations or other deratings; or
the highest sustainable load, based on at least four quarters of representative historical
operating data. For common stacks, the maximum sustainable load is the sum of all of
the maximum sustainable loads of the individual units discharging through the stack,
unless this load is unattainable in practice, in which case use the highest sustainable
combined load for the units that discharge through the stack. Based on at least four
quarters of representative historical operating data. The load values for the unit(s)
must be expressed either in units of megawatts of thousands of lb/hr of steam load or
mmBtu/hr of thermal output.
; or
(2) For affected units that do not produce electrical or thermal output, the lower
boundary of the range of operation must be the minimum expected flue gas velocity
(in ft/sec) during normal, stable operation of the unit. The upper boundary of the
range of operation must be the maximum potential flue gas velocity (in ft/sec) as
defined in Section 2.1.2.1 of this Exhibit. The minimum expected and maximum
potential velocities may be derived from the results of reference method testing or by
using Equation A-3a or A-3b (as applicable) in Section 2.1.2.1 of this Exhibit. If
Equation A-3a or A-3b is used to determine the minimum expected velocity, replace
the word "maximum" with the word "minimum" in the definitions of "MPV," "Hf,"
" %
O
2
d
," and %
H
2
0 ," and replace the word "minimum" with the word "maximum"
in the definition of "CO
2d
." Alternatively, 0.0 ft/sec may be used as the lower
boundary of the range of operation.
(b) The operating levels for relative accuracy test audits will, except for peaking
units, be defined as follows: the "low" operating level will be the first 30.0 percent of
the range of operation; the "mid" operating level will be the middle portion (>30.0
percent, but <=60.0 percent) of the range of operation; and the "high" operating level
will be the upper end (>60.0 percent) of the range of operation. For example, if the
upper and lower boundaries of the range of operation are 100 and 1100 megawatts,
respectively, then the low, mid, and high operating levels would be 100 to 400
megawatts, 400 to 700 megawatts, and 700 to 1100 megawatts, respectively.
(c) Units that do not produce
electrical or thermal output are exempted from the
requirements of this paragraph, (c). The owner or operator must identify, for each
affected unit or common stack, the "normal" load level or levels (low, mid or high),
based on the operating history of the unit(s). To identify the normal load level(s), the
owner or operator must, 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
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
representative operating quarters. The owner or operator must 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 must be kept on-site in a format suitable for
inspection. For new units or newly-affected units, the data analysis in this paragraph
may be based on fewer than four quarters of data if fewer than four representative
quarters of historical load data are available. Or, if no historical load data are
available, the owner or operator may designate the normal load based on the expected
or projected manner of operating the unit. However, in either case, once four quarters
of representative data become available, the historical load analysis must be repeated.
(d) Determination of normal load (or operating level)
(1)
Based on the analysis of the historical load data described in paragraph (c) of this
Section, the owner or operator must, for units that produce electrical or thermal
output, designate the most frequently used load level as the normal load level for the
unit (or combination of units, for common stacks). The owner or operator may also
designate the second most frequently used load level as an additional normal load
level for the unit or stack. 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 must repeat the historical load analysis and must
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.
Update the electronic monitoring plan whenever the normal load level(s) and the two
most frequently-used load levels are redesignated.
(2) For units that do not produce electrical or thermal output, the normal operating
level(s) must be determined using sound engineering judgment, based on knowledge
of the unit and operating experience with the industrial process.
(e) The owner or operator must report the upper and lower boundaries of the range of
operation for each unit (or combination of units, for common stacks), in units of
megawatts or thousands of lb/hr or mmBtu/hr of steam production or ft/sec (as
applicable), in the electronic monitoring plan required under Section 1.10 of this
Appendix.
85.
The Agency proposes amending Exhibit A, Section 6.5.2.2 to delete a reference to
Section 6.5.2(e). The Agency is proposing to delete Section 6.5.2(e).
6.5.2.2 Multi-Load (or Multi-Level) Flow RATA Results
For each multi-load (or multi-level) flow RATA, calculate the flow monitor relative
accuracy at each operating level. If a flow monitor relative accuracy test is failed or
aborted due to a problem with the monitor on any level of a 2-level (or 3-level)
relative accuracy test audit, the RATA must be repeated at that load (or operating)
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
level. However, the entire 2-level (or 3-level) relative accuracy test audit does not
have to be repeated unless the flow monitor polynomial coefficients or K-factor(s) are
changed, in which case a 3- level RATA is required (or, a 2-level RATA, for units
demonstrated to operate at only two levels, under Section 6.5.2(e) of this Exhibit).
86.
In response to a request at the December 17, 2008, hearing that the Agency delete
remaining references to bias adjustment factor if appropriate, the Agency
proposes deleting Exhibit A, Sections 7.4, 7.4.1, 7.4.2, 7.4.3, and 7.4.4.
7.4 Bias Test
Test the following relative accuracy test audit data sets for bias: flow monitors;
mercury concentration monitoring systems, and sorbent trap monitoring systems,
using the procedures outlined in Sections 7.4.1 through 7.4.4 of this Exhibit. For
multiple-load flow RATAs, perform a bias test at each load level designated as
normal under Section 6.5.2.1 of this Exhibit.
7.4.1 Arithmetic Mean
Calculate the arithmetic mean of the difference, "d", of the data set using Equation A-
7 of this Exhibit. To calculate bias for a flow monitor, "d" is, for each paired data
point, the difference between the flow rate values (in scfh) obtained from the
reference method and the monitor. To calculate bias for a mercury monitoring system
when using the Ontario Hydro Method or Method 29 in appendix A-8 to 40 CFR 60,
incorporated by reference in Section 225.140, "d" is, for each data point, the
difference between the average mercury concentration value (in ?g/m
3
) from the
paired Ontario Hydro or Method 29 in appendix A-8 to 40 CFR 60 sampling trains
and the concentration measured by the monitoring system. For sorbent trap
monitoring systems, use the average mercury concentration measured by the paired
traps in the calculation of "d".
7.4.2 Standard Deviation
Calculate the standard deviation, S
d
, of the data set using Equation A-8.
7.4.3 Confidence Coefficient
Calculate the confidence coefficient, cc, of the data set using Equation A-9.
7.4.4 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.
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
87.
In response to a comment received from USEPA, the Agency proposes amending
Exhibit A, Section 7.6 to delete portions of the Section concerning units that do
not produce electrical or thermal output, as such units are not subject to the
Agency’s proposed rule.
7.6 Flow-to-Load Test Exemptions
(a)
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 USEPA under 40 CFR 75.66, incorporated by reference in Section
225.140, for an exemption from the requirements of Section 7.7 to Appendix A to 40
CFR Part 75 and Section 2.2.5 of Exhibit B to Appendix B. 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.
(b) Units that do not produce electrical output (in megawatts) or thermal output (in
klb of steam per hour) are exempted from the flow-to-load ratio test requirements of
Section 7.5 of this Exhibit and Section 2.2.5 of Exhibit B to Appendix B.
88.
In response to a comment received from USEPA, the Agency proposes amending
Section 2.3.1.3(b) of Exhibit B to remove references to Section 6.5.2(e) of Exhibit
A. Section 6.5.2(e) concerns EGUs not producing electricity.
2.3.1.3 RATA Load (or Operating) Levels and Additional RATA Requirements
(a) For CO
2
or O
2
diluent monitors used to determine heat input, mercury
concentration monitoring systems, sorbent trap monitoring systems, moisture
monitoring systems, the required semiannual or annual RATA tests must be done at
the load level (or operating level) designated as normal under Section 6.5.2.1(d) of
Exhibit A to this Appendix. If two load levels (or operating levels) are designated as
normal, the required RATA(s) may be done at either load level (or operating level).
(b) For flow monitors installed and bypass stacks, and for flow monitors that qualify
to perform only single-level RATAs under Section 6.5.2(e) of Exhibit A to this
Appendix, all required semiannual or annual relative accuracy test audits must be
single-load (or single-level) audits at the normal load (or operating level), as defined
in Section 6.5.2.1(d) of Exhibit A to this Appendix.
(c) For all other flow monitors, the RATAs must be performed as follows:
(1) An annual 2-load (or 2-level) flow RATA must be done at the two most
frequently used load levels (or operating levels), as determined under Section
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
6.5.2.1(d) of Exhibit A to this Appendix, or (if applicable) at the operating levels
determined under Section 6.5.2(e) of Exhibit A to this Appendix. Alternatively, a 3-
load (or 3-level) flow RATA at the low, mid, and high load levels (or operating
levels), as defined under Section 6.5.2.1(b) of Exhibit A to this Appendix, may be
performed in lieu of the 2-load (or 2-level) annual RATA.
(2) If the flow monitor is on a semiannual RATA frequency, 2-load (or 2-level) flow
RATAs and single-load (or single-level) flow RATAs at the normal load level (or
normal operating level) may be performed alternately.
(3) A single-load (or single-level) annual flow RATA may be performed in lieu of the
2-load (or 2-level) 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 21 days prior to the date of the current annual flow RATA,
the unit (or combination of units, for a common stack) has operated at a single load
level (or operating level) (low, mid, or high), for >=85.0 percent of the time.
Alternatively, a flow monitor may qualify for a single-load (or single-level) RATA if
the 85.0 percent criterion is met in the time period extending from the beginning of
the quarter in which the last annual flow RATA was performed through the end of the
calendar quarter preceding the quarter of current annual flow RATA.
(4) A 3-load (or 3-level) RATA, at the low-, mid-, and high-load levels (or operating
levels), as determined under Section 6.5.2.1 of Exhibit A to this Appendix, must be
performed at least once every twenty consecutive calendar quarters, except for flow
monitors that are exempted from 3-load (or 3-level) RATA testing under Section
6.5.2(b) or 6.5.2(e)
of Exhibit A to this Appendix.
(5) A 3-load (or 3-level) RATA is required whenever a flow monitor is re-linearized,
i.e., when its polynomial coefficients or K factor(s) are changed, except for flow
monitors that are exempted from 3-load (or 3-level) RATA testing under Section
6.5.2(b) or 6.5.2(e)
of Exhibit A to this Appendix. For monitors so exempted under
Section 6.5.2(b), a single-load flow RATA is required. For monitors so exempted
under Section 6.5.2(e), either a single-level RATA or a 2-level RATA is required,
depending on the number of operating levels documented in the monitoring plan for
the unit.
(6) For all multi-level flow audits, the audit points at adjacent load levels or at
adjacent operating levels (e.g., mid and high) must be separated by no less than 25.0
percent of the "range of operation," as defined in Section 6.5.2.1 of Exhibit A to this
Appendix.
(d) A RATA of a moisture monitoring system must be performed whenever the
coefficient, K factor or mathematical algorithm determined under Section 6.5.6 of
Exhibit A to this Appendix is changed.
89.
In response to a request at hearing on December 17, 2008, the Agency proposes
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
removing subsection 2.3.2(h) and (i) of Exhibit B, as they concern bias tests.
2.3.2 Data Validation
***
(h) Each time that a hands-off
RATA of a mercury concentration monitoring system,
a sorbent trap monitoring system, or a flow monitor is passed, perform a bias test in
accordance with Section 7.4.4 of Exhibit A to this Appendix.
(i) Failure of the bias test does not result in the monitoring system being out-of-
control.
90.
In response to a comment received from USEPA, the Agency proposes amending
Footnote 2 in Figure 1 to Exhibit B to remove references to Section 6.5.2(e) to
Exhibit A. Section 6.5.2(e) concerns EGUs not producing electricity.
[FN2] For flow monitors installed on peaking units, bypass stacks, or units
that qualify for single-level RATA testing under Section 6.5.2(e) of this
part, conduct all RATAs at a single, normal load (or operating level). For
other flow monitors, conduct annual RATAs at two load levels (or operating
levels). Alternating single-load and 2-load (or single-level and 2-level)
RATAs may be done if a monitor is on a semiannual frequency. A single-load
(or single-level) RATA may be done in lieu of a 2-load (or 2-level) RATA if,
since the last annual flow RATA, the unit has operated at one load level (or
operating level) for >=85.0 percent of the time. A 3-level RATA is required
at least once every five calendar years and whenever a flow monitor is
re-linearized, except for flow monitors exempted from 3-level RATA testing
under Section 6.5.2(b) or 6.5.2(e)
of Exhibit A to this Appendix.
91.
In response to a request at hearing on December 17, 2008, the Agency proposes
to amend Section 4.1.1 of Exhibit C to remove references to bias adjustment
factors from the equation. Similarly, the Agency suggests amending Section 4.1.2
of Exhibit C to remove references to Bias Adjustment Factors from the equation.
Finally, the Agency proposes amending Section 4.3 of Exhibit C to place the
“4.3” on its own line. The formatting in the original proposal was incorrect.
4. Procedures for Mercury Mass Emissions.
4.1
Use the procedures in this Section to calculate the hourly mercury mass emissions (in
ounces) at each monitored location, for the affected unit or group of units that
discharge through a common stack.
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
4.1.1
To determine the hourly mercury mass emissions when using a mercury
concentration monitoring system that measures on a wet basis and a flow monitor, use
the following equation:
M
h
=
KC
h
Q
h
t
h
(Equation F-28)
Where:
M
h
= Mercury mass emissions for the hour, rounded off to three decimal places,
(ounces).
K = Units conversion constant, 9.978 x 10
-10
oz-scm/?g-scf
C
h
= Hourly mercury concentration, wet basis, adjusted for bias if the bias-test
procedures in Exhibit A to this Appendix show that a bias-adjustment factor is
necessary, (?g/wscm).
Q
h
= Hourly stack gas volumetric flow rate, adjusted for bias, where the bias-test
procedures in Exhibit A to this Appendix shows a bias-adjustment factor is necessary,
(scfh)
t
h
= Unit or stack operating time, as defined in 40 CFR 72.2, (hr)
4.1.2
To determine the hourly mercury mass emissions when using a mercury
concentration monitoring system that measures on a dry basis or a sorbent trap
monitoring system and a flow monitor, use the following equation:
M
h
=
KC
h
Q
h
t
h
(
1
−
B
ws
)
(Equation F-29)
Where:
M
h
= mercury mass emissions for the hour, rounded off to three decimal places,
(ounces).
K = Units conversion constant, 9.978 x 10
-10
oz-scm/<<mu>>g-scf
C
h
= Hourly mercury concentration, dry basis, adjusted for bias if the bias-test
procedures in Exhibit A to this Appendix show that a bias-adjustment factor is
necessary, (?g/dscm). For sorbent trap systems, a single value of
C
h
(i.e., a flow-
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
proportional average concentration for the data collection period), is applied to each
hour in the data collection period, for a particular pair of traps.
Q
h
= Hourly stack gas volumetric flow rate, adjusted for bias, where the bias-test
procedures in Exhibit A to this Appendix shows a bias-adjustment
factor is necessary,
(scfh).
B
ws
= Moisture fraction of the stack gas, expressed as a decimal (equal to %
H
2
0 100)
t
h
= Unit or stack operating time, as defined in 40 CFR 72.2, (hr)
4.3
4.3
If heat input rate monitoring is required, follow the applicable procedures for heat
input apportionment and summation in Sections 2.3, 2.4 and 2.5 of this Exhibit.
Respectfully submitted,
ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY
Charles E. Matoesian
Assistant Counsel
____________________________________
Dana Vetterhoffer
Assistant Counsel
DATED:
1021 North Grand Avenue East
P.O. Box 19276
Springfield, Illinois 62794-9276
(217) 782-5544
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY
DIVISION OF AIR POLLUTION CONTROL –
COMPLIANCE SECTION
P.O. BOX 19276
SPRINGFIELD, ILLINOIS 62794-9276
FOR APPLICANT'S USE
Revision #: ________________
Date: _____ / _____ / _____
Page _________ of ________
Source Designation:
_________________________
THIS AGENCY IS AUTHORIZED TO REQUIRE THIS INFORMATION UNDER ILLINOIS REVISED STATUTES, 1991, AS AMENDED 1992,
CHAPTER 111 1/2, PAR. 1039.5. DISCLOSURE OF THIS INFORMATION IS REQUIRED UNDER THAT SECTION. FAILURE TO DO SO MAY
PREVENT THIS FORM FROM BEING PROCESSED AND COULD RESULT IN THE APPLICATION BEING DENIED. THIS FORM HAS BEEN
APPROVED BY THE FORMS MANAGEMENT CENTER.
PAGE _______
FOR APPLICANT'S USE
______________
Printed on Recycled Paper
450-CAAPP
Page 1 of 3
FOR AGENCY USE ONLY
Back to top
MERCURY MONITORING REPORTING
Back to top
FORM
ID NUMBER:
PERMIT #:
DATE:
THIS FORM IS USED TO REPORT AND CERTIFY
COMPLIANCE OF A SOURCE AND SPECIFIC
ELECTRICAL GENERATING UNITS (“EGU”)
WITH ALL APPLICABLE CEMS AND EXCEPTED
MONITORING SYSTEM MONITORING DURING A
REPORTING PERIOD.
Back to top
SOURCE INFORMATION
1) SOURCE NAME:
2) DATE FORM
PREPARED:
3) SOURCE ID NO.
Back to top
GENERAL INFORMATION
4) PERIOD COVERED BY THIS REPORT:
FROM: _______ / _______ / _______
TO: _______ / _______ / _______
5) NAME AND PHONE NUMBER OF PERSON TO CONTACT FOR QUESTIONS REGARDING THIS REPORT:
NAME: ______________________________________________ TITLE:_________________________________________
PHONE#: ( ________) _________-________________ EXT:________________
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
PAGE _______
FOR APPLICANT'S USE
______________
Printed on Recycled Paper
450-CAAPP
Page 2 of 3
6)
LIST ALL EGU(S) AT THE SOURCE (IF ADDITIONAL SPACE IS NEEDED FOR ITEM 6, ATTACH AND LABEL AS
EXHIBIT 450-A) AND IDENTIFY THE APPLICABLE 35 ILL ADM. CODE PART 225 REQUIREMENT(S) FOR EACH EGU
FOR WHICH THIS FORM IS BEING USED TO REPORT AND CERTIFY COMPLIANCE WITH:
Note: EGUs using periodic emissions testing (including LME EGUs) will be listed here, but excluded from the emissions table
(pg 3)
COMPLIANCE OF ELECTRICAL GENERATING UNITS DURING REPORTING PERIOD
7)
WERE THOSE EGUS, WHICH ARE USING A MONITORING SYSTEM, IN ITEM 6 IN
COMPLIANCE WITH ALL APPLICABLE MONITORING AND RECORDKEEPING
REQUIREMENTS FOR THE ENTIRE REPORTING PERIOD?
YES
NO
8)
FOR AN EGU WHERE MERCURY DATA WAS UNAVAILABLE OR OUT OF CONTROL,
WERE THE ADD-ON MERCURY EMISSION CONTROLS, A FGD SYSTEM, A SCR
SYSTEM, OR A COMPACT HYBRID PARTICULATE COLLECTOR SYSTEM OPERATING
WITHIN ESTABLISHED PARAMETERS?
YES
NO
IF NO, THEN COMPLETE AND SUBMIT FORM CAAPP-405 – “EXCESS EMISSSIONS, MONITORING EQUIPMENT
DOWNTIME, AND MISCELLANEOUS REPORTING FORM.”
Back to top
SIGNATURE BLOCK
NOTE: THIS CERTIFICATION MUST BE SIGNED BY A RESPONSIBLE OFFICIAL. REPORTS WITHOUT A SIGNED CERTIFICATION WILL BE
RETURNED AS INCOMPLETE.
9) I CERTIFY UNDER PENALTY OF LAW THAT, BASED ON INFORMATION AND BELIEF FORMED AFTER REASONABLE
INQUIRY
OF THOSE PERSONS WITH PRIMARY RESPONSIBILITY FOR ENSURING THAT ALL OF THE EGUS'
EMISSIONS ARE CORRECTLY AND FULLY MONITORED, THE STATEMENTS AND INFORMATION CONTAINED IN
THIS REPORT ARE TRUE, ACCURATE, AND COMPLETE.
AUTHORIZED SIGNATURE:
BY:
_________________________________________________
_________________________________________________
AUTHORIZED SIGNATURE
TITLE OF SIGNATORY
_________________________________________________
_______________ / _______________ / _______________
TYPED OR PRINTED NAME OF SIGNATORY
DATE
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY
DIVISION OF AIR POLLUTION CONTROL -- COMPLIANCE SECTION
P.O. BOX 19276
SPRINGFIELD, ILLINOIS 62794-9276
FOR APPLICANT'S USE
Revision #: ________________
Date: _____ / _____ / _____
Page _________ of ________
Source Designation:
_________________________
Back to top
PAGE _______
Back to top
FOR APPLICANT'S USE
______________
Printed on Recycled Paper
450-CAAPP
Page 3 of 3
QUARTERLY AND MONTHLY MERCURY EMISSIONS DATA
(1)
EGU or
STACK
ID
(2)
EGU
Quarterly
Operating
Hours
(hrs/quarter)
CEMS
Quarterly
Operating
Hours
(hrs/quarter)
CEMS
Quarterly Data
Availability
(%)
Avg. Monthly Hg
Coal
Concentration
(3)(8)
(ppm)
Total Hg
Content of
Coal Fired in
EGU
(4)(8)
(oz./quarter)
Monitored
Quarterly
Hg
Emitted
(5)
(oz./quarter)
Avg. Monthly
and Quarterly
Hg Control
(6)(8)
(%)
Avg. Monthly
and Quarterly Hg
Emission Rate
(7)
(lb/GWh)
12-Month Rolling
Avg. Control or
Emission Rate
(8)(9)
(% or lb/GWh)
1
2
3
1
2
3
Q
1
2
3
Q
1
2
3
1
2
3
1
2
3
Q
1
2
3
Q
1
2
3
1
2
3
1
2
3
Q
1
2
3
Q
1
2
3
1
2
3
1
2
3
Q
1
2
3
Q
1
2
3
Notes:
1. Specific records pursuant to 35 Ill Adm. Code Part 225 may be requested by the Agency to support the information provided here. EGUs using periodic emissions testing should be excluded.
2. If EGUs share a common stack, list Stack ID and associated EGUs.
3. Determined by averaging all analyzed coal samples in the month.
4. Multiply the average monthly coal concentration by the amount of coal used each month, then add together for the quarter.
5. The amount of mercury emitted during the CEMS quality-assured monitor operating hours.
6. Calculated using the emissions data available during CEMS quality-assured monitor operating hours and total Hg content of coal modified by data availability percentage.
7. During the CEMS quality-assured monitor operating hours.
8. As applicable, according to method of calculation (Hg emission rate or Hg reduction standard-see Section 225.290(b)(3)(H)).
9. Or a lesser number of continuous months if a full 12 months of data is not available.
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
IN THE MATTER OF:
)
)
R09-10
AMENDMENTS TO 35 ILL. ADM.
)
CODE 225: CONTROL OF EMISSIONS
)
(Rulemaking – Air)
FROM LARGE COMBUSTION SOURCES
)
MOTION FOR WAIVER OF REQUIREMENTS
NOW COMES Proponent, the ILLINOIS ENVIRONMENTAL PROTECTION
AGENCY (“Illinois EPA”), by its attorney, Charles E. Matoesian, and pursuant to 35 Ill. Adm.
Code and 101.500, 102.110, 102.402, moves that the Illinois Pollution Control Board (“Board”)
waive certain requirements, namely that the Illinois EPA submit copies of the documents in
which are incorporated by reference. In support of its Motion, Illinois EPA states as follows:
Section 5-75(a) of the Illinois Administrative Procedure Act (“IAPA”) provides in
relevant part that an agency may incorporate by reference the regulations, standards and
guidelines of an agency of the United States or a nationally recognized organization or
association without publishing the incorporated material in full. 5 ILCS 100/5-75(a). Further,
Section 5-75(b) of the IAPA provides in relevant part that the agency adopting a rule or
regulation under the IAPA shall maintain a copy of the referenced rule, regulation, standard or
guideline in at least one of its principal offices and shall make it available to the public upon
request. 5 ILCS 100/5-75(b). In this submittal the Illinois EPA amended the incorporations by
reference section and in doing so added the following documents:
Appendices A-1 through A-8
, Subpart A, and Performance Specifications 2 and 3
of Appendix B of 40 CFR Part 60 (2005).
40 CFR Part 75 (2006)
.
ASTM D6722-01, Standard Test Method for Total Mercury in Coal and Coal
Combustion Residues by Direct Combustion Analysis.
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
2
First, the Illinois EPA requests that the Board waive the normal copy requirements of Section
102.200 of the Board’s procedural rules and allow Illinois EPA to file only the original of the
American Society for Testing and Materials (“ASTM”) Standards that are incorporated by
reference. The ASTM standards are copyright protected. The Illinois EPA is subject to
additional fees in order to provide the Board with a copy. Accordingly, the Illinois EPA has
incurred costs, and to keep these costs at a minimum, the Illinois EPA requests that the Board
waive the requirement stated above. Attached with the ASTM standards being filed is a copy of
the License Agreement utilized by ASTM. The Illinois EPA directs the Board’s attention to that
document so that the Board may conform its handling of the standards consistent with that
Agreement.
Secondly, the Illinois EPA requests that it not be required to submit copies of the Code of
Federal Regulations that have been incorporated by reference in this proposed submittal. The
Illinois EPA's request is consistent with the Illinois Administrative Procedure Act, 5 ILCS 100/1-
1
et seq
., and reasonable in light of the fact that these documents are quite lengthy and are readily
available.
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
3
WHEREFORE, for the reasons set forth above, Illinois EPA requests that the Board
waive the copy requirement and allow Illinois EPA to file only the original of the American
Society for Testing and Materials (“ASTM”) Standard that is incorporated by reference. The
Illinois EPA also requests that the Board waive the requirements that the Agency file the Code of
Federal Regulations incorporated by reference above.
Respectfully submitted,
ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY
By:
__________________
Charles E. Matoesian
Assistant Counsel
Division of Legal Counsel
DATED: January 14, 2009
1021 N. Grand Ave., East
P.O. Box 19276
Springfield, Illinois 62794-9276
217.782.5544
217.782.9143 (TDD)
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
STATE OF ILLINOIS
)
)
SS
COUNTY OF SANGAMON
)
)
CERTIFICATE OF SERVICE
I, the undersigned, an attorney, state that I have served electronically the attached
the ILLINOIS ENVIRONMENTAL PROTECTION AGENCY’S POST-HEARING
COMMENTS TO THE DECEMBER 17, 2008, HEARING ON THE PROPOSAL FOR
AMENDING 35 ILL. ADM. CODE 225, ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY’S SECOND ERRATA SHEET TO ITS PROPOSAL TO
AMEND 35 ILL. ADM. CODE 225 and MOTION FOR WAIVER OF
REQUIREMENTS, upon the following person:
John Therriault, Assistant Clerk
Illinois Pollution Control Board
James R. Thompson Center
100 West Randolph St., Suite 11-500
Chicago, IL 60601
and mailing it by first-class mail from Springfield, Illinois, with sufficient postage affixed
to the following persons:
SEE ATTACHED SERVICE LIST
ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY,
__________________________
Charles E. Matoesian
Assistant Counsel
Division of Legal Counsel
Dated: January 14, 2009
1021 North Grand Avenue East
P.O. Box 19276
Springfield, Illinois 62794-9276
217.782.5544
217.782.9143 (TDD)
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
R09-10 Service List
Tim Fox, Hearing Officer
Illinois Pollution Control Board
James R. Thompson Center
100 West Randolph St., Suite 11-500
Chicago, IL 60601-3218
Stephen J. Bonebrake
Kathleen C. Bassi
Schiff Hardin, LLP
233 S. Wacker Dr
6600 Sears Tower
Chicago, IL 60606
S. David Farris
City of Springfield, Office of Public Works
201 East Lake Shore Dr.
Springfield, IL 62757
Electronic filing - Received, Clerk's Office, January 14, 2009
* * * * * PC #1 * * * * * *
ILLINOIS
ENVIRONMENTAL
PROTECTION
AGENCY
1021
NORTH
GRAND
AVENUE
EAST,
P.O.
Box
19276,
SPRINGFIELD,
ILLINOIS
62794-9276
-(217)
782-2829
JAMES
R.
THOMPSON
CENTER,
100
WEST
RANDOLPH,
SUITE 11-300,
CHICAGO,
IL
60601
- (312)
814-6026
January
13,
2009
ROD
R.
BLAGOJEVICH,
GOVERNOR
DOUGLAS
P.
Scon,
DIRECTOR
Tim
Fox,
Hearing
Officer
Illinois
Pollution Control
Board
James
R.
Thompson
Center
100
West
Randolph
St.,
Suite
11-500
Chicago,
IL
60601
Re:
In
the
Matter
of:
Amendments
to 35
Ill.
Adm.
Code
225:
Control
of
Emissions
from
Large
Combustion
Sources,
R09-10
Mr. Fox.
Attached
please
find
the
ASTM
Standard
which
accompanies
the
Illinois
Environmental
Protection
Agency’s
Post-Hearing
Comments,
which
will
be
electronically
filed
shortly.
Charles
E.
Matoesian
Assistant
Counsel
Illinois
Environmental
Protection
Agency
ROCKFORD
— 4302
North
Main
Street,
Rockford,
IL 61103
—
(815) 987-7760
•
DES
PLAINES
— 9511
W.
Harrison
St.,
Des
Plaines,
IL
60016
— (847)
294-4000
ELGIN
—
595
South
State,
Elgin,
IL 60123
— (847)
608-3131
PEORIA
— 5415
N. University
St., Peoria,
IL
61614—
(309)
693-5463
BUREAU
OF
LAND
- PEORIA
— 7620
N.
University
St.,
Peoria,
IL 61614-
(309)
693-5462
.
CHAMPAIGN
-2125
South First
Street,
Champaign,
IL 61820
—(217)
278-5800
COLLINSVILLE
—2009
MalI
Street,
Collinsville,
IL
62234
—(618)
346-5120
.
MARION
—2309W.
Main
St.,
Suite 116,
Marion,
IL 62959
—(618)
993-7200
PRINTED
ON
RECYCLED
PAPER
Originally
Approved
28
April
1999
INTELLECTUAL
PROPERTY
POLICY
OF
ASTM
INTERNATIONAL
(“POLICY”)
I.
INTRODUCTION.
Ownership
and
use of
ASTM
International’s
Intellectual
Property
(e.g.
Standards,
Draft
Standards,
Adjuncts,
Technical
Papers,
Research
Reports,
Manuals,
Software,
Training
Course
Materials and Logos
collectively
referred
to
as “ASTM
IP”)
are
vital
to the
ability
of
ASTM
International
to
fulfill
its mission.
ASTM
International
owns
and
maintains the
rights
to
its
Intellectual
Property;
it is the
responsibility
of
ASTM
International’s
Board
of Directors
(“Board”),
staff,
members,
and
others
who
participate
in
the creation
of ASTM
IP
(collectively
“Participants”),
as
well
as authorized
resellers/distributors
of
ASTM
IP,
to
protect
these
valuable
assets
and
ensure
that
they
are
used
in
accordance
with
this
Policy.
A.
Section
1 of
the ASTM
International
Charter states
in part:
“The
corporation
is
formed
for
the
development
of
standards
on
characteristics
and
performance
of
materials,
products,
systems
and
services;
and
the
promotion
of related
knowledge.”
B. ASTM
International
By-law
4.4
states:
“The
Board
shall
delegate
to
such
committees
and
other
groups
those
powers
necessary
for
the
fulfillment
of their
assigned
function.”
C.
ASTM
International
By-law
7.1
states:
“The
Board
of
Directors
is empowered
to
promulgate
procedures
for
the
development
and
adoption
of
voluntary
consensus
standards
...“
D.
The
Standing
Committee
on Publications (“COP”)
advises
the Board
on
the
formulation
of
publications
policy.
COP is
responsible
for
all publications
programs
of
the
Society
except
the
acceptance
for
publication
of
ASTM
International’s
standards.
E.
The
Committee
on
Technical
Committee
Operations
(“COTCO”)
is responsible
for
the
Regulations Governing
ASTM’s
Technical
Committees
(“Regulations”),
of which
Regulation
17.1
states:
“Documents
[including
standards
and
provisional
standards],
technical
papers,
reports,
minutes,
letters
to the
editor,
and
related
materials
should
be
released
for publication
only through
ASTM’s
headquarters.”
F.
Regulation
10.7 requires
that
the
current
edition
of
the
manual,
Form
and
Style
for
ASTM
Standards (“Form
&
Style”)
will
be
followed
in
the
writing
of
standards
(the
Committee on
Standards
(“COS”)
is
responsible
for
Form
& Style).
Section
F of
Form
&
Style
sets
forth
policies
and
procedures
governing,
among
other
matters,
reference
to
patents,
trademarks,
similar
marks,
and
reference
to standards
of
other
organizations,
in
ASTM
International
documents.
Regulation
15 governs
the
use
or
reference
to a patent
in
an
ASTM
International
standard.
II.
TYPES
OF
INTELLECTUAL
PROPERTY.
Intellectual property
includes
patents,
trademarks
and
copyrights,
as
defined
in
various
federal
and
state
statutes.
A.
Patent.
A
patent
is
a
property
right
granted
by
the
government
to
inventors
of
new
and
useful
inventions.
Patents
may
be
granted
on any
new
and useful
process,
machine,
manufactured article,
composition
of matter,
or any
new
and
useful
improvements
thereof.
During
a
patent’s
limited
term,
its
owner
has
the right
to
exclude
others
from
government
or
agency
has
not
and
will
not
effect,
transfer,
modifr
or
alter
the
copyrights
of
the
ASTM
IP
in
any
way.
V.
POLICY.
A.
All
of
ASTM
International’s
Intellectual
Property
rights
must
be
protected,
regulated
and
maintained,
no
matter
how
wide
the
information
is
distributed
in
print,
electronically,
or
otherwise.
Such
protection
is
essential
to
ASTM
International’s
ability
to
fulfill
its
mission
and
maintain
its
Intellectual
Property.
The
Board
of
Directors
has
approved
the
Principles
for
the
Use
of
ASTM
Intellectual
Property
by
Other
Standards
Organizations.
B.
ASTM
International
owns
and
maintains
the
rights
to
its
Intellectual
Property.
C.
ASTM
International
reserves
the
right
to
copyright
any
of
its
print,
electronic
products,
databases,
audio/visual
products
and
any
other
subject
matter
covered
by
the
Copyright
Act.
This
is
intended
to
protect
ASTM
International
and
its
members
from
unauthorized
copying
and
distribution
of
ASTM
IP.
B.
By
participating
in
any
ASTM
International
technical
committee
and/or
participating
in
the
creation,
development
and/or
adoption
of
ASTM
IP,
Participants
and
committee
members
acknowledge
that
the
copyright
to
such
Intellectual
Property
resides
in
ASTM
International.
Each
member
agrees,
by
such
participation
and
enjoyment
of
his/her
annual
membership
benefits,
to
have
transferred
any
and
all
ownership
interest,
including
copyright,
they
possess
or
mayposses
in
the
ASTM
IP
to
ASTM.
If
requested
by
ASTM
International,
such
Participants
and
committee
members
agree
to
execute
any
and
all
documents
deemed
necessary
or
appropriate
by
ASTM
International
to
transfer
and
effectuate
ownership
of
all
such
rights,
including
but
not
limited
to
copyrights,
they
may
possibly
have
in
ASTM
IP.
The
rights
granted
to
ASTM
International
by
this
assignment
or
transfer
shall
belong
to
ASTM
International
in
perpetuity.
E.
All
Participants,
members
and
staff
agree
to
abide
by
and
follow
the
requirements
of
the
ASTM
International
Charter,
ASTM
International
By-laws,
Regulations
Governing
ASTM
Technical
Committees,
and
Form
and
Style
for
ASTM
Standards,
ASTM
International
Logo
Policy,
as
well
as
this
Policy,
as
each
may
be
amended
from
time
to
time,
when
creating,
developing
or
utilizing
ASTM
IP.
F.
It
is
ASTM
International’s
policy,
reflected
in
Form
&
Style
F5,
that
the
copyrights
and
other
intellectual
property
rights
of
third
parties
be
respected
and
not
infringed
by
ASTM
International
or
any
of
its
committees,
or
any
employee,
member
or
other
person
acting
on
behalf
of
ASTM
International.
G.
It
is
ASTM
International
policy
that,
if
at
all
possible,
proprietary
and/or
patented
equipment,
apparatus,
material
or
information
not
be
Included
in
a
standard.
If
such
inclusion
is
necessary,
ASTM
International’s
Patent
Policy
(Regulation
15)
must
be
complied
with.
H.
ASTM
International
registers
its
trademarks
and
service
marks
in
the
United
States
and
in
countries
around
the
world.
As
a
condition
of
membership,
members
agree
that
the
marks
are
the
property
of
ASTM
International
at
all
times.
Use
of
the
marks
is
subject
to,
among
other
things,
ASTM
International’s
Logo
Policy.
I.
Electronic
Networks.
1.
The
Copyright
Act
provides
copyright
protection
for
certain
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either
directly
or
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the
aid
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technology.
2.
As
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and
more
sophisticated
technology
becomes
available,
it
may
become
b)
When
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execute
such
agreements.
As
amended
by
the
ASTM
International
Board
of
Directors,
October
28,
2003.
1.
Scope
1.1
These test methods
cover procedures
to determine the
total
mercury
content
in a
sample of coal
or
coal
combustion
residue.
1.2
The
values
stated in SI
units
are regarded
as
the
standard.
1.3 This
standard does not
purport
to
address
all
of the
safety
concerns,
if any, associated
with its use. It
is the
responsibility of
the user of this standard
to establish
appro
priate
safety
and health
practices and
determine
the
applica
bilily of regulatory
limitations
prior to use.
2. Referenced
Documents
2.1
ASTM Standards:
D
121
Terminology of
Coal and Coke2
D 2013
Method
of
Preparing
Coal Samples for Analyses
2
D
3173
Test Method
for Moisture
in the Analysis Sample of
Coal
and
Coke
2
D 3180
Practice for
Calculating Coal and
Coke Analyses
from
As-Determined
to Different Bases
2
D 4621 Guide
for
Acäountability
and Quality Control
in the
Coal
Analysis
Laboratory
2
D
5142
Test Methods for the
Proximate Analysis
of the
Analysis
Sample
of Coal
and
Coke
by
Instrumental
Procedures
2
IEEE/ASTM
SI 10
Standard
for
Use
of the International
System
of
Units
(SI): The
Modern
Metric System
3
3.
Terminology
3.1
For
definitions
of terms used
in
this standard,
refer to
Terminology
D 121.
4. Summary
of
Test
Method
4.1 Controlled
heating
of
the analysis sample
in oxygen is
used
to
liberate mercury.
The
sample is heated to dryness
in the
This
test
method
is under
the jurisdiction
of ASTM
Committee D05 on
Coal
and Coke and
is
the direct
responsibility
of Subcommittee D05.29
on
Major
Elements in Ash
and
Trace
Elements
of Coal.
Current edition
approved
October 10, 2001.
Published
December 2001.
2
Book of
ASTM
Standards, Vol 05.06.
Book
ofASTM
Standards,
Vol 14.02.
instrument and
then
thermally
and chemically
decompose...:j
The decomposition products
are carried by flowing
oxygen
the
catalytic
section
of the furnace,
where oxidation
is
corn
pleted and
halogens as well as nitrogen
and sulfur
oxides
are
trapped. The remaining
decomposition
products
are
carried
to--,
a
gold amalgamator
that
selectively
traps
mercury.
After
th&.
system
is
flushed with
oxygen to
remove any
remaining.:;.
decomposition
products, the
amalgamator
is
rapidly
heated,:,
releasing mercury
vapor. Flowing oxygen
carries
the
mercury
vapor
through
absorbance
cells positioned in the light
path
of.:
single wavelength atomic
absorption
spectrophotometer.
Ab.
sorbance peak height or
peak area,
as a function of
mercury
concentration,
is
measured
at 253.7 nm.
NOTE
1—Mercury and
mercury
salts
can be volatized at low
tempera
tures.
Precautions
against inadvertent mercury
loss
should
be
taken
when
using this method.
5. Significance and Use
5.1 The
emission
of mercury during
coal combustion
can be
an
environmental
concern.
5.2 When representative
test portions
are analyzed accord
ing to
this procedure,
the total mercury
is representative of
concentrations
in
the sample.
6. Apparatus
6.1 There
are
several
configurations of the
instrumental
components
that
can
be used
satisfactorily
for this test
method.
Functionally,
the instrument shall
have
the
following compo
nents: drying
compartment,
decomposition
tube,
catalyst
tube,
gold
amalgamator,
amalgamator
furnace, measuring
cuvettes,
mercury
lamp, and detector. The
following
requirements
are
specified for
all approved
instruments. (Note 2).
Nore 2—The
approval
of an instrument
with respect to these
functions
is paramount
to
this test
method, since
such approval
tacitly
provides
approval
of both
the
materials and
the procedures used with
the system to
provide these
functions.
6.1.1 The instrument shall
be
capable
of
drying
the sample
once it. is
weighed and introduced.
8.R
8.1
ment
8.
Refe
ues
certi
and’
the
for
8.
hav
abil
be
100
refe
ou
9.
Designation:
D 6722 —01
INTERNATIONAL
‘uIl
Standard Test
Method for
Total Mercury
in Coal and Coal
Combustion
Residues
by
Direct
Combustion
Analysis
1
This
standard
is
issued under the fixed designation
D
6722; the
number immediately following
the designation indicates
the year of
original adoption
or, in
the case
of revision, the year
of
last revision.
A
number
in parentheses indicates
the year of last reapproval. A
superscript epsilon (e)
indicates
an editorial change
since the last revision or
reapproval.
6.1.2
11
be
inpc
go0°C.
6.1.3
0
oinpleti
:asWelli
tempera
6.1.4
an
i
-
tnercUr3
6.1.5
•
:raPjY
6.1.6
•ineaSut
release(
heated
sition
f
6.1.7
shall
b
6.1.
tor,
ca
I
used.
6.1.’
the
vai
for
rei
6.2
6.3
nient
7.
Sa
7.1
Metht
(No.
7.2
accor
Copyright
©ASTM
International,
100
Barr Harbor
Drive,
P0
Box C700, West Conshohocken,
PA
19428-2959,
United
States.
C
the
636
6.1.2
The
instrument
shall
have
a
decomposition
tube
which
shall
be
operated
at
a
temperature
high
enough
to
completely
decompose
the
sample.
The
suggested
operating
temperature
is
800°C.
6.1.3
The
catalyst
in
the
catalytic
tube
shall
be
capable
of
completing
the
oxidation
of
the
sample
and
trapping
halogens
as
well
as
nitrogen
and
sulfur
oxides.
The
suggested
operating
•
temperature
of
the
catalytic
tube
is
550°C.
6.1.4
The
instrument
shall
contain
a
gold
amalgamator
fixed
to
an
inert
material
and
shall
be
capable
of
trapping
all
mercury.
•
6.1.5
The
amalgamator
shall
contain
a
furnace
capable
of
rapidly
heating
the
amalgamator
to
release
all
trapped
mercury.
6.1.6
The
instrument
shall
have
a
absorption
cell
with
measuring
cuvettes
through
which
the
elemental
mercury
released
from
the
gold
amalgamator
flows.
The
cell
shall
be
heated
to
avoid
any
condensation
of
water
or
other
decompo
sition
products.
6.1.7
The
light
source
for
the
atomic
absorption
process
shall
be
a
low
pressure
mercury
lamp.
6.1.8
A
narrow
bandpass
interference
filter
or
monochroma
tor,
capable
of
isolating
the
253.65
nm
mercury
line,
shall
be
used.
6.1.9
The
system
may
contain
a
computer
for
controlling
the
various
operations
of
the
apparatus,
for
recording
data,
and
for
reporting
results.
6.2
Analytical
Balance,
with
a
sensitivity
of
0.1
mg.
6.3
Sample
Combustion
Boats,
made
of
nickel
and
conve
nient
size
suitable
for
use
in
the
instrument
being
used.
7.
Sample
7.1
Prepare
the
analysis
sample
of
coal
in
accordance
with
Method
D
2013
by
pulverizing
the
material
to
pass
a
250-mm
::(N0.
60)
sieve.
7.2
Analyze
separate
test
portions
for
moisture
content
in
accordance
with
Test
Method
D
3173
or
TestMethods
D
5142.
‘i.
Reagents
8.1
Oxygen—High
purity
oxygen,
as
specified
by
the
instru
t
manufacturer,
shall
be
used.
8.2
Certified
Reference
Materials
(CRMs)—Use
Certified
leference
Material
(CRM)
coals
with
dry-basis
mercury
val
•s
for
which
confidence
limits
are
issued
by
a
recognized
ertifying
agency
such
as
the
National
Institute
of
Standards
ic
Technology
(NIST).
It
is
recommended
that
the
user
verify
value
with
the
certifying
agency
before
using
the
CRM
coal
..t
quality
control
purposes.
8.3
All
CRMs,
reference
coals,
or
calibrating
agents
must
precision
values
‘of
less
than
or
equal
to
method
repeat
bility.
Such
CRMS,
reference
coals,
or
calibrating
agents
must
with
respect
to
moisture
and
be
pulverized
to
pass
%
through
a
250
um
(No.
60)
USA
Standard
Sieve.
CRMs,
lerence
coals,
or
calibrating
agents
must
be
mixed
thor
hly
before
each
use.
rument
Preparation
.1
Assemble
the
instrumental
system
in
accordance
with
manufacturer’s
instructions.
Follow
the
instrument
manu
D6722
facturer’s
recommended
procedure
to
optimize
mance
of
the
instrument.
9.2
Adjustment
of
Response
of
Measure,
7
jt
Weigh
an
appropriate
test
portion
of
certified
referñc
rial
(CRM),
calibrating
agent,
or
reference
coal
Aiij:
test
portion
(see
9.1).
Repeat
this
procedure.
Adjust
i±iheiit’
response,
as
recommended
by
the
manufacturer
until
tie*
absence
of
drift
is
indicated.
9.3
Calibration—Select
coal
CRMs
or
other
caIibratjtg;
agents
and
materials
specified
by
the
manufacturer
that
have.
certified
mercury
values
in
the
range
of
samples
to
be
analyzed.
Three
such
CRMs
or
calibrating
agents
are
reconm1endl
for
each
range
of
mercury
values
to
be
tested.
When
possible,
two
of
the
CRMs
or
calibrating
agents
shall
bracket
the
range
of
mercury
to
be
tested,
with
the
third
falling
within
the
range.
9.3.1
All
coal
CRMs
should
be
in
accordance
with
8.2
and
shall
be
supplied
by
or
have
traceability
to
an
internationally
recognized
certifying
organization.
CAUTION:
An
indicated
problem
with
linearity
of
the
instrument
during
calibration
can
result
from
contamination
of
the
CRM
or
calibrating
agent
as
the
container
becomes
depleted.
It
is
therefore
recommended
that
the
CRM
or
calibrating
agent
be
discarded
when
less
than
five
grams
remain
in
the
container.
9.3.2
Calibration
Procedure—Analyze,
as
samples,
por
tions
of
a
CRM,
reference
coal,
or
calibrating
agent
chosen
to
represent
the
level
of
mercury
in
the
samples
to
be
tested.
Use
the
“as-determined”
mercury
values
for
calibration.
These
values
must
have
been
calculated
previously
from
the
certified
“dry
basis”
mercury
values
and
residual
moisture
detennined
using
either
Test
Methods
D
3173
or
D
5142.
Continue
ana
lyzing
until
the
results
from
five
consecutive
determinations
fall
within
the
repeatability
interval
of
these
test’
methods.
Calibrate
the
instrument
according
to
the
manufacturer’s
in
structions
using
these
values.
Analyze,
as
samples,
two
CRM
reference
coals
or
calibrating
agents
that
bracket
the
range
of
values
to
be
tested.
The
results
obtained
for
these
samples
much
be
within
the
stated
precision
limits
of
the
CRM,
reference
coal,
or
calibrating
agent
or
the
calibration
procedure
must
be
repeated.
Records
for
all
calibrations
must
be
in
accordance
with
Guide
D
4621.
9.3.3
Periodic
Calibration
Verflcation
and
Recalibration—In
accordance
with
Guide
D
4621,
analyze
a
control
sample
on
a
periodic
basis.
Results
obtained
for
the
control
sample
must
be
within
established
limits,
or
all
results
obtained
.
sincethe
last
successful
control
check
must
be
rejected
and
the
calibration
procedure
repeated.
10.
Procedure
10.1
Analyze
a
test
specimen
of
the
analysis
sample
in
accordance
with
the
manufacturer’s
instructions.
11.
Calculation
1.1
.1
Calculate
the
concentration
of
mercury,
on
the
appro
priate
sample
basis,
as
follows:
posed.
ygen
to
s
corn-
des
are
rried
to
fter
the
aaining
heated,.
iercury
path
of
r.
Ab
iercury
empera
n
when
canbe
ccord
:ive
of
nental;
ethod...
ompO-,
t
tub,,’
vetteS..,
its
are.
flCt1P1
rovi4..
stein
where:
637
(BXC)
D
(1)
mg/Kg
of
the
analyte,
detector
response
for
that
analyte,
unit
mass
per
detector
response
established
for
the
analyte
during
calibration,
and
D
=
mass
of
test
specimen,
g.
The
calculations
can
be
provided
automatically
by
the
instrumental
system
used
for
these
methods.
12.
Report
12.1
Report
results
from
the
mercury
determination
on
any
of
the
several
common
bases
that
differ
solely
with
respect
to
moisture.
Procedures
for
converting
the
as-determined
concen
trations
to
the
other
bases
are
specified
in
Practice
D
3180.
13.
Precision
and
Bias
13.1
Precision—The
precision
of
this
test
method
for
the
determination
of
mercury
in
coal,
is
shown
in
Table
1.
The
precision
characterized
by
the
repeatability
(Sr,
r)
and
repro
ducibility
(SR,
R)
is
described
in
Table
Al.1
in
Annex
Al.
13.1.1
Repeatability
Limit
(r)—The
value
below
which
the
absolute
difference
between
two
test
results
of
separate
and
consecutive
test
determinations,
carried
out
on
the
same
sample
in
the
same
laboratory
by
the
same
operator
using
the
same
apparatus
on
samples
taken
at
random
from
a
single
quantity
of
homogeneous
material,
may
be
expected
to
occur
with
a
probability
of
approximately
95
%.
13.1.2
Reproducibility
Limit
(R)—The
value
below
which
the
absolute
difference
between
two
test
results,
caffied
out
in
TABLE
1
Concentration
Range
and
Limits
for
Repeatability
and
Reproducibility
for
Mercury
in
Coal
Concentration
Repeatability
Limit
Reproducibility
Limit
Range,
ppm
r
R
Hg
0.017
—
0.586
0.008
+
0.06
0.007
+
0.13
Al
.1
The
precision
of
this
test
method,
characterized
by
repeatability
(Sr,
r)
and
reproducibility
(Sn,
R)
has
been
determined
for
the
following
materials
as
listed
in
Table
Al
.1.
A
1.2
Repeatability
Standard
Deviation
(Sr)—The
standard
deviation
of
test
results
obtained
under
repeatability
condi
tions.
different
laboratories
usirig
samples
taken
at
single
quantity
of
material
that
is
as
homogeneous
aspo
may
be
expected
to
occur
with
a
probability
of
approxji
95%.
13.2
Bias—Certified
Reference
Materials
NIST
NIST
2692b,
and
SARM
20
were
included
in
the
intel
tory
study
to
ascertain
possible
bias
between
values
and
those
determined
by
this
method.
A
comparj
the
NIST
and
SARM
values
and
those
obtained
in
interlaboratory
study
are
given
in
Table
2.
NOTE
3—Whenever
possible,
the
analysis
of
several
reference
11
als,
spanning
the
concentration
range
of
interest,
is
the
most
mean
way
to
investigate
measurement
bias.
When
a
matrix
match
is
possible
uncertainty
in
sample
measurements
can
be
equated
to
that
observ
measurement
of
the
Certified
Reference
Matenal
(CRM).
When
iueh
match
is
not
possible,
but
a
CRM
with
a
related
matrix
is
available,
the.
sample
uncertainty
may
be
related
to
those
observed
when
measuring
‘
CRM.
Different
methods
of
measurement
of
a
property
may
not
capable
of
equal
repeatability.
Accordingly,
instances
could
arise
--
the
method
of
measurement
has
greater
variability
than
that
or
thosud:..
in
certification
of
the
CRM.
13.3
An
interlaboratory
study,
designed
consistent
wit1jr
Practice
E
691,
was
conducted
in
2000.
Eight
labs
participãted:
The
details
of
thestudy
and
supporting
data
are
given
in
ASTM
Research
Report
RR:D-5
.1026
filed
at
ASTM
headquarters
TABLE
2
Comparison
of
Certified
Values
for
NIST
1630a,
NlST..r
2692b,
and
SARM
20
with
lnterlaboratory
Study
Values
for
Total
Mercury
In
Coal
CRM
Value,
Bias,
Significant
ppm
ppm
(95%
Confidence).
0.0938
—0.0026
no
0.1333
—0.0093
yes
0.25
0
no
A1.3
Reproducibility
Standard
Deviation
(S)—The
stan-
-
dard
deviation
of
test
results
obtained
under
reproducibility
conditions.
B=
c=
4ifr
D
6722
Reference
CRM
Level
NIST
1630a
NIST
2692b
SARM
20
RR Value,
ppm
0.0912
0.124
0.25
ANNEX
(Mandatory
Information)
Al.
PRECISION
STATISTICS
638
41fr
D
6722
TABLE
A1.1
Repeatability
(Sr,
r)
and
Reproducibility
(SR,
R)
Parameters
Used
for
Calculation
of
Precision
Statement
Material
Average
Sr
SR
r
R
hvCb
Arizona
0.017393
0.002358
0.002930
0.006602
0.008203
hvAb
NIST
2692b
0.124464
0.003669
0.007333
0.010274
0.020533
hvCb
SARM
20
0.249750
0.006167
0.015203
0.017268
0.042568
FGD
A-i
0.585786
0.01
9241
0.031515
0.053875
0.088241
FGD
A-2
0.318536
0.004404
0014187
0.012330
0.039725
HvAb
Pennsylvania
0.114357
0.004501
0.007793
0.012604
0.021821
hvBb
Ohio
0.116679
0.004924
0.007548
0.013788
0.021135
hvBb
Colorado
0.033107
0.005618
0.007377
0.015730
0.020655
sub
A
Wyoming
0.074857
0.006189
0.006189
0.017331
0.017331
ligATexas
0.101214
0.008171
0.008171
0.022878
0.022878
hvAb
NIST
1630a
0.091250
0.005386
0.005386
0.015082
0.015082
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