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
)
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 THIRD
ERRATA SHEET TO ITS PROPOSAL TO AMEND 35 ILL. ADM. CODE 225 of the
Illinois Environmental Protection Agency a copy of which is herewith served upon you.
ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY
By: /s__Charles E Matoesian
Charles E. Matoesian
___
Assistant Counsel
Division of Legal Counsel
DATED: February 6, 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)
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 THIRD 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 Third 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, revised by the Agency’s First Errata, submitted to the Board on December 2,
2008, and further revised by the Agency’s Second Errata, submitted to the Board on
January 14, 2009:
1.
The Agency proposes correcting a punctuation error made in the Second Errata.
In item 2, changes were made to the definitions of “NIST traceable elemental
mercury standards” and “NIST traceable source of oxidized mercury.” Commas
that were added when extending both definitions were accidentally shown as
being stricken, and the existing periods were not shown as being stricken. The
correct definitions should have read:
“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
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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
.
2.
The Agency proposes amending Section 225.130 to remove the definition for
“Designated Representative.” This proposed amendment is in response to
industry comments that the term is not necessary and would lead to confusion.
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
natural person who is 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.
3.
The Agency proposes amending Section 225.230 to clarify that Section 225.235,
which concerns units scheduled for permanent shutdown, is part of the exception
established in subsection (a)(1).
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 225.235,
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,
2008, must comply with one of the following standards for each
EGU on a rolling 12-month basis:
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A)
An emission standard of 0.0080 lb mercury/GWh gross
electrical output; or
B)
A minimum 90-percent reduction of input mercury.
4.
The Agency proposes amending Section 225.
233
(a)(4) to reflect the removal of
the term “designated representative.”
4)
When an EGU is subject to the requirements of this Section, the
requirements apply to all owners or operators of the EGU,
and the
designated representative for the EGU.
5.
The Agency proposes amending Section 225.233(c)(2)(D). The Agency has
become aware of new information that indicates some sources with particulate
control devices downstream of the air preheater may inject activated carbon
upstream of the air preheater. This injection point was not contemplated during
the original determination of the required injection rates for units opting into the
MPS and CPS. It also brings to light a need to revise the rule so as to avoid an
incentive to inject at a point in the ductwork that may not be most desirable. This
is because determination of the flow rate at the point of injection creates an
incentive to inject where the flow rate is low (e.g., near the back end of the
ductwork close to the stack), thereby potentially making the injection point
location decision based on factors other than the ability to best control mercury
emissions.
Furthermore, the Agency believes that measurement of gas flow rate at the point
of injection is likely less reliable in comparison to gas flow rate measurement at
the stack due to there typically being a higher level of operating experience,
quality control, and quality assurance of stack gas flow meters. The requirement
for gas flow rate to be obtained from stack gas flow meters, which are operated
under the Acid Rain Program, will also result in a standardized point of gas flow
measurement rather than such measurements being taken at variable points in the
gas flow configuration.
The proposed revision requires determination of the gas flow rate at the stack
except in the case of units equipped with activated carbon injection prior to a hot-
side electrostatic precipitator. For these units, the gas flow rate will still be
determined at the inlet to the hot-side electrostatic precipitator. For this purpose,
the gas flow rate would actually be measured at the stack, however, the stack gas
flow rate will be adjusted for the differences in temperature in the stack and at the
inlet to the hot-side electrostatic precipitator. This adjustment is required since
the Agency was aware in its original determination of the required injection rates
that units equipped with hot-side electrostatic precipitators would be injecting
activated carbon prior to the hot-side electrostatic precipitator and it was
recognized that such units would typically get lower mercury control than those
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with more common configurations (e.g., cold-side electrostatic precipitators).
The proposed revision also recognizes that some units with hot-side electrostatic
precipitators may be equipped with secondary particulate control devices
downstream of the hot-side electrostatic precipitator and will inject activated
carbon downstream of the hot-side electrostatic precipitator. Such units will be
treated like other units and will not be required to adjust the gas flow rate for
temperature differences but will simply measure the gas flow rate at the stack.
Therefore, the Agency proposes amending this Section as follows:
D)
For the purposes of subsection (c)(2)(C) of this Section, the
flue gas flow rate must be determined for the point of
sorbent injection; provided that this flow rate may shall be
assumed to be identical to
the stack gas flow rate in the
stack for all units except for those equipped with activated
carbon injection prior to a hot-side electrostatic
precipitator; for units equipped with activated carbon
injection prior to a hot-side electrostatic precipitator, the
flue gas flow rate shall be the gas flow rate at the inlet to
the hot-side electrostatic precipitator, which shall be
determined as the stack flow rate adjusted through the use
of Charles’s Law for the differences in gas temperatures in
the stack and at the inlet to the electrostatic precipitator
(V
esp
= V
stack
x T
esp
/T
stack
, where V = gas flow rate in acf
and T = gas temperature in Kelvin or Rankine). if the gas
temperatures at the point of injection and the stack are
normally within 100
o
F, or the flue gas flow rate may
otherwise be calculated from the stack flow rate, corrected
for the difference in gas temperatures.
6.
The Agency proposes amending Section 225.233(f)(5) for clarification purposes,
in response to a request by industry.
f)
Requirements for NO
x
and SO
2
Allowances.
***
5)
By
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
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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
allowances from the previous year by August 31, the final report
will be due, and all allowances required to be surrendered must be
surrendered, within 30 days after such deduction occurs.
7.
The Agency proposes amending Section 225.234(b)(2) for the same reasons set
forth in errata item 5.
2)
The owner or operator of the EGU is injecting halogenated
activated carbon in an optimum manner for control of mercury
emissions, which must include injection of Alstom, Norit, Sorbent
Technologies,
Calgon Carbon's FLUEPAC MC Plus, or other
halogenated activated carbon that the owner or operator of the
EGU has demonstrated to have similar or better effectiveness for
control of mercury emissions, at least at the following rates set
forth in subsections (b)(2)(A) through (b)(2)(D) of this Section,
unless other provisions for injection of halogenated activated
carbon are established in a federally enforceable operating permit
issued for the EGU, using an injection system designed for
effective absorption of mercury, considering the configuration of
the EGU and its ductwork. For the purposes of this subsection
(b)(2), the flue gas flow rate shall be the flow rate in the stack for
all units except for those equipped with activated carbon injection
prior to a hot-side electrostatic precipitator; for units equipped with
activated carbon injection prior to a hot-side electrostatic
precipitator, the flue gas flow rate shall be the gas flow rate at the
inlet to the hot-side electrostatic precipitator, which shall be
determined as the stack flow rate adjusted through the use of
Charles’s Law for the differences in gas temperatures in the stack
and at the inlet to the electrostatic precipitator (V
esp
= V
stack
x
T
esp
/T
stack
, where V = gas flow rate in acf and T = gas temperature
in Kelvin or Rankine).must be determined for the point of sorbent
injection (provided, however, 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 may
otherwise be calculated from the stack flow rate, corrected for the
difference in gas temperatures.
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8.
The Agency proposes amending Section 225.238(b)(2) for the same reasons set
forth in errata item 5.
2)
For an EGU for which injection of a sorbent or other mercury
control technique is required pursuant to subsection (b)(1) of this
Section, the owner or operator of the EGU is injecting sorbent or
other mercury control technique in an optimum manner for control
of mercury emissions, which must include injection of Alstom,
Norit, Sorbent Technologies, Calgon Carbon's FLUEPAC MC
Plus, or other sorbent or other mercury control technique that the
owner or operator of the EGU demonstrates to have similar or
better effectiveness for control of mercury emissions, at least at the
rate set forth in the appropriate of subsections (b)(2)(A) through
(b)(2)(C) of this Section, unless other provisions for injection of
sorbent or other mercury control technique are established in a
federally enforceable operating permit issued for the EGU, with an
injection system designed for effective absorption of mercury. For
the purposes of this subsection (b)(2), the flue gas flow rate shall
be the gas flow rate in the stack for all units except for those
equipped with activated carbon injection prior to a hot-side
electrostatic precipitator; for units equipped with activated carbon
injection prior to a hot-side electrostatic precipitator, the flue gas
flow rate shall be the gas flow rate at the inlet to the hot-side
electrostatic precipitator, which shall be determined as the stack
flow rate adjusted through the use of Charles’s Law for the
differences in gas temperatures in the stack and at the inlet to the
electrostatic precipitator (V
esp
= V
stack
x T
esp
/T
stack
, where V = gas
flow rate in acf and T = gas temperature in Kelvin or
Rankine).must be determined for the point of sorbent injection or
other mercury control technique (provided, however, 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 flow rate may otherwise be calculated from
the stack flow rate, corrected for the difference in gas
temperatures.
9.
In response to industry comments, the Agency proposes amending Section
225.239(g) to provide that an unsuccessful stack test only indicates
noncompliance dating back to the beginning of the quarter, the last day of
certified CEMS data (or certified data from an excepted monitoring system)
demonstrating compliance, or to the date on which a significant change was
made. The language is now consistent with the Agency’s statements that a
successful stack test determines compliance for an entire quarter, and it also
acknowledges that a significant change could be the event that triggers
noncompliance, so noncompliance should not be assumed to predate such a
change.
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g)
Compliance Determination
1)
Each successful
quarterly emissions test shall determine
compliance with this Subpart for that quarter, except for days in
the quarter before and after a failed test and until a successful re-
test as described in subsection(g)(2) below, 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 first
day after the most recent emissions test that
demonstrated compliance or of the current quarter, the last day of
certified CEMS data (or certified data from an excepted
monitoring system) demonstrating compliance, or the date on
which a significant change was made pursuant to subsection (h)(2)
of this Section if such a change was made, whichever is later; 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.
10.
The Agency proposes amending Section 225.
239
(i)(1) to reflect the removal of the
term “designated representative.”
1)
The owner or operator of an EGU and its designated representative
must comply with all applicable recordkeeping and reporting
requirements in this Section.
11.
The Agency proposes amending Section 225.240(b)(1) in response to a request by
Midwest Generation that the monitor date match the control installation date.
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:
1)
For the owner or operator of an EGU that commences commercial
operation before July 1, 2008, by July 1, 2009, except that an EGU
in an MPS Group for which an SO
2
scrubber or fabric filter is
being installed to be in operation by December 31, 2009, as
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described in Section 225.233(c)(1)(A), shall have a date of January
1, 2010.
12.
The Agency proposes amending Section 225.240(d)(2) because EGUs are not
actually required to account for all
emissions (as a result of the removal of data
substitution requirements and the addition of the 75% monitor availability
requirement, for example).
d)
Prohibitions.
1)
No owner or operator of an EGU may use any alternative
emissions monitoring system, alternative reference method for
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.
13.
The Agency proposes amending Section 225.240(d)(4)(B) to reflect the removal of
the term “designated representative.”
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
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9
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).
14.
In response to comments by industry and to ensure the regulation matches the
Agency’s original intent, the Agency proposes amending Section 225.260(b) to
clarify that all units using CEMS are subject to the 75% uptime requirement.
b)
Monitor data availability for all EGUs using a CEMS (or an excepted
monitoring system) shall be greater than or equal to 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.
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), 225.237(a)(1)(B), or
225.294(c)(2), or the emissions concentration standard in Section
225.230(a)(1)(A), 225.233(d)(1)(A) or (d)(2)(A), 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.
15.
In response to comments from Ameren, the Agency proposes amending Section
225.265(a)(1) to provide greater flexibility regarding the location at which
sources are required to collect a grab sample.
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 or, in
cases where a crusher house or breaker building are not present, at
a reasonable point close to the boiler of a subject EGU, 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
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10
must average those tests to arrive at the final mercury content for
that time period. The owner or operator of the EGU must perform
coal sampling as follows:
16.
The Agency proposes amending Section 225.290(a)(1) to reflect the removal of
the term “designated representative.”
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.
17.
The Agency proposes amending Section 225.290(b)(3)(F) in response to
stakeholder comments that certain DAHS systems have the ability to record the
amount of coal combusted.
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 weighted
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 DAHS for the
EGU has the ability to record the amount of coal
combusted during QAMO hours, the average monthly and
quarterly control efficiency shall be reported without the
calculation above. 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.
18.
The Agency proposes amending Section 225.292(e) to reflect the removal of the
term “designated representative.”
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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
designated representative for the EGU.
19.
The Agency proposes amending Section 225.294(g)(4) for the same reasons set
forth in errata item 5.
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 shall be assumed to be identical to the gas
stack flow rate in the stack for all units except for those equipped
with activated carbon injection prior to a hot-side electrostatic
precipitator; for units equipped with activated carbon injection
prior to a hot-side electrostatic precipitator, the flue gas flow rate
shall be the gas flow rate at the inlet to the hot-side electrostatic
precipitator, which shall be determined as the stack flow rate
adjusted through the use of Charles’s Law for the differences in
gas temperatures in the stack and at the inlet to the electrostatic
precipitator (V
esp
= V
stack
x T
esp
/T
stack
, where V = gas flow rate in
acf and T = gas temperature in Kelvin or Rankine).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.
20.
The Agency proposes amending Section 225.298(a) 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,
and 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.
Further changes throughout Section 225.298 reflect the removal of the term
“designated representative.” Finally, as with the MPS, the Agency is changing
“Before” to “By” for clarification purposes. This change is in response to a
request by industry.
Section 225.298
Combined Pollutant Standard: Requirements for NO
x
and SO
2
Allowances
a)
The following requirements apply to the owner and
, the operator, and the
designated representative with respect to SO
2
and NO
x
allowances, which
mean, for the purposes of this Section 225.298, allowances necessary for
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compliance with Section 225.310, 225.410, or 225.510, 40 CFR 72, or
Subparts AA and AAAA of 40 CFR 96, or any future federal NO
x
or SO
2
emissions trading programs that modify or replace these programs:
1)
The owner,
or operator, and designated representative of specified
EGUs in a CPS group is permitted to sell, trade, or transfer SO
2
and NO
x
emissions allowances of any vintage owned, allocated to,
or earned by the specified EGUs (the "CPS allowances") to its
affiliated Homer City, Pennsylvania, generating station for as long
as the Homer City Station needs the CPS allowances for
compliance.
2)
When and if the Homer City Station no longer requires all of the
CPS allowances, the owner,
or operator, or designated
representative of specified EGUs in a CPS group may sell any and
all remaining CPS allowances, without restriction, to any person or
entity located anywhere, except that the owner or operator may not
directly sell, trade, or transfer CPS allowances to a unit located in
Ohio, Indiana, Illinois, Wisconsin, Michigan, Kentucky, Missouri,
Iowa, Minnesota, or Texas.
3)
In no event shall this subsection (a) require or be interpreted to
require any restriction whatsoever on the sale, trade, or exchange
of the CPS allowances by persons or entities who have acquired
the CPS allowances from the owner,
or operator, or designated
representative of specified EGUs in a CPS group.
b)
The owner,
or operator, and designated representative of EGUs in a
specified CPS group is prohibited from purchasing or using SO
2
and NO
x
allowances for the purposes of meeting the SO
2
and NO
x
emissions
standards set forth in Section 225.295.
c)
By
Before March 1, 2010, and continuing each year thereafter, the owner
or operator designated representative of the EGUs in a CPS group must
submit a report to the Agency that demonstrates compliance with the
requirements of this Section for the previous calendar year and ozone
season control period (May 1 through September 30), and includes
identification of any NO
x
or SO
2
allowances that have been used for
compliance with any NO
x
or SO
2
trading programs, and any NO
x
or SO
2
allowances that were sold, gifted, used, exchanged, or traded. A final
report must be submitted to the Agency by August 31 of each year,
providing either verification that the actions described in the initial report
have taken place, or, if such actions have not taken place, an explanation
of the changes that have occurred and the reasons for such changes.
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21.
The Agency proposes amending Appendix B, Section 1.2(f) to reflect the removal
of the term “designated representative.”
f)
Minimum recording and recordkeeping requirements. The owner or
operator must record and the designated representative must
report the
hourly, daily, quarterly, and annual information collected under the
requirements as specified in subpart G of 40 CFR 75, incorporated by
reference in Section 225.140, and Section 1.11 through 1.13 of this
Appendix.
22.
The Agency proposes amending Appendix B, Section 1.4(a)(1) to reflect the
removal of the term “designated representative.”
Section 1.4
Initial certification and recertification procedures
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.
1)
Notification of initial certification test dates. The owner or operator
or designated representative
must submit a written notice of the
dates of initial certification testing at the unit as specified in 40
CFR 75.61(a)(1), incorporated by reference in Section 225.140.
23.
The Agency proposes amending Appendix B, Section 1.4(a)(4)(B) to reflect the
removal of the term “designated representative.”
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 owner or operator
designated representative
to submit the additional
information required to complete the certification (or
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recertification) application. If the owner or operator
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.
24.
The Agency proposes amending Appendix B, Section 1.4(a)(5)(B) to reflect the
removal of the term “designated representative.”
B)
The owner or operator
designated representative must
submit a notification of certification retest dates as
specified in Section 225.250(a)(3)(A) and a new
certification application according to the procedures in
Section 225.250(a)(3)(B); and
25.
The Agency proposes amending Appendix B, Section 1.4(b)(2) to reflect the
removal of the term “designated representative.”
2)
Notification of recertification test dates. The owner,
or operator, or
designated representative must submit notice of testing dates for
recertification under this paragraph as specified in 40 CFR
75.61(a)(1)(ii), incorporated by reference in Section 225.140,
unless all of the tests in paragraph (c) of this Section are required
for recertification, in which case the owner or operator must
provide notice in accordance with the notice provisions for initial
certification testing in 40 CFR 75.61(a)(1)(i), incorporated by
reference in Section 225.140.
26.
The Agency proposes correcting several errors made in the Second Errata. In
item 27, several changes were made to Appendix B, Section 1.4(b)(3)(G)(v). A
number of punctuation errors occurred during the process. First, the second
sentence was broken up into two new sentences. This involved adding a period,
which was mistakenly omitted from the Second Errata. The two sentences should
read:
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…
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Next, in the Second Errata, the fifth sentence in the lower half of the paragraph
correctly shows the strikeout of a “+-” sign before “15 ppm” but inadvertently
leaves out a second “+-” before 1.5% which was also intended to be stricken.
The passage should read:
…± 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…
Third, the same sentence was broken up to form a new sixth sentence. To reflect
this, a semicolon was stricken and a period added. In the Second Errata,
however, the period was stricken rather than underlined. In addition, the new,
capitalized “No” was not underlined as being an addition. The passage should
read:
…the average reference method value, as applicable.
; No no adjustments
to the calibration…
Accordingly, the entire paragraph (v) should read:
(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
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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).
27.
The Agency proposes amending Appendix B, Section 1.4(b)(4) to reflect the
removal of the term “designated representative.”
4) Recertification application. The owner or operator
designated
representative must apply for recertification of each continuous 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.
28.
The Agency proposes amending Appendix B, Section 1.4(b)(5) to reflect the
removal of the term “designated representative.” An extraneous space was also
removed between the words “Agency’s” and “notice” in line ten.
5)
Approval or disapproval of request for recertification. The
procedures for provisional certification in paragraph (a)(3) of this
Section apply to recertification applications. The Agency will issue
a notice of approval, disapproval, or incompleteness according to
the procedures in paragraph (a)(4) of this Section. Data from the
monitoring system remain invalid until all required recertification
tests have been passed or until a subsequent probationary
calibration error test is passed, beginning a new recertification test
period. The owner or operator must repeat all recertification tests
or other requirements, 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. The owner or operator
designated representative must submit a notification of the
recertification retest dates, as specified in 40 CFR 75.61(a)(1)(ii),
incorporated by reference in Section 225.140, and must submit a
new recertification application according to the procedures in
paragraph (b)(4) of this Section.
29.
The Agency proposes amending Appendix B, Section 1.4(f) to reflect the removal
of the term “designated representative.”
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f)
Certification/recertification procedures for alternative monitoring systems.
The designated representative representing the owner or operator of each
alternative monitoring system approved by the Agency as equivalent to or
better than a continuous emission monitoring system according to the
criteria in subpart E of 40 CFR 75, incorporated by reference in Section
225.140, must apply for certification to the Agency prior to use of the
system under Part 225, Subpart B, and must apply for recertification to the
Agency following a replacement, modification, or change according to the
procedures in paragraph (c) of this Section. The owner or operator of an
alternative monitoring system must comply with the notification and
application requirements for certification or recertification according to
the procedures specified in paragraphs (a) and (b) of this Section.
30.
The Agency proposes correcting an error made in the Second Errata. In item 40,
a change to Appendix B, Section 1.6(c) struck appendix “A-4” of 40 CFR 60.
Thus the preceding descriptive noun “appendices” needed to be changed to
“appendix,” as only a reference to one appendix remained. However, the Second
Errata inadvertently showed the term “appendix” being stricken and
“appendices” being added. Subparagraph (c) should read:
c)
Instrumental EPA Reference Method 3A in appendix
appendices 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:
31.
The Agency proposes correcting several errors made in the Second Errata. In
items 47 through 50, the Agency cited Appendix B, Section 1.10(a) when it should
have cited 1.10(c). The actual changes to the rule were correct; the citations in
the descriptions simply were not. These should read:
47.
The Agency proposes amending Appendix B Section 1.10(c)(1)(B)
to include moisture as a monitored parameter. Prior omission of
moisture as a parameter was an oversight.
48.
The Agency proposes deleting Appendix B Section
1.10(c)(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(c)(1)(E)(vi) to correct grammar.
49.
The Agency proposes amending Appendix B Section 1.10(c)(2)(B)
to correct an erroneous reference.
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50.
The Agency proposes amending Appendix B Section 1.10(c)(2)(D)
to correct an erroneous reference.
32.
The Agency proposes amending Appendix B, Section 1.11(a) to require five years
for record retention so as to be consistent with Section 225.290(a)(6).
Section 1.11 General recordkeeping provisions
The owner or operator must meet all of the applicable recordkeeping requirements of
Section 225.290 and of this Section.
a)
Recordkeeping requirements for affected sources. The owner or operator
of any affected source subject to the requirements of this Appendix must
maintain for each affected unit a file of all measurements, data, reports,
and other information required by Part 225, Subpart B at the source in a
form suitable for inspection for at least five (5)
three (3) years from the
date of each record. The file must contain the following information:
33.
The Agency proposes correcting an error made in the Second Errata. In item 52,
Appendix B, Section 1.11(b)(3) and (b)(4) were combined into one item. To
effectuate this, and to make the list uniform, the period at the end of the old (b)(4)
was changed to a semicolon. However, this was not reflected as a change in the
Second Errata. The corrected item 52 should read:
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;.
34.
The Agency proposes correcting an error made in the Second Errata. In item 53,
Appendix B, Section 1.11(e)(1)(c), the second sentence was removed. This
required the period at the end of the first sentence to be changed into a semicolon
to provide continuity to the list. This was done, but not reflected as an
amendment. Accordingly, Section 1.11(e)(1)(c) should read:
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;
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35.
The Agency proposes amending Appendix B, Section 1.14(a) to reflect the
removal of the term “designated representative.”
Section 1.14 General provisions
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)
that is subject to Part 225. The term "non-affected unit" means any unit
that is not subject to Part 225, the term "permitting authority" means the
Agency.
, and the term "designated representative" means the responsible
party under Part 225.
36.
The Agency proposes amending Appendix B, Section 1.14(c)(2) because EGUs
are not actually required to account for all
emissions (as a result of the removal
of data substitution requirements and the addition of the 75% monitor availability
requirement, for example).
c)
Prohibitions.
1)
No owner or operator of an affected unit or a non-affected unit
under Section 1.16(b)(2)(B) of this Appendix will use any
alternative monitoring system, alternative reference method, or any
other alternative for the required continuous emission monitoring
system without having obtained prior written approval in
accordance with paragraph (f) of this Section.
2)
No owner or operator of an affected unit or a non-affected unit
under Section 1.16(b)(2)(B) of this Appendix will operate the unit
so as to discharge, or allow to be discharged emissions of mercury
to the atmosphere without accounting for all
such emissions in
accordance with the applicable provisions of this Appendix.
37.
The Agency proposes amending Appendix B, Section 1.14(c)(4)(C) to reflect the
removal of the term “designated representative.”
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4)
No owner or operator of an affected unit or a non-affected unit
under Section 1.16(b)(2)(B) will retire or permanently discontinue
use of the continuous emission monitoring system, any component
thereof, or any other approved emission monitoring system under
this Appendix, except under any one of the following
circumstances:
***
C)
The owner or operator
designated representative submits
notification of the date of certification testing of a
replacement monitoring system in accordance with Part
225.240(d).
38.
The Agency proposes amending Appendix B, subsections 1.14(f)(1) and (f)(3) to
reflect the removal of the term “designated representative.”
f)
Petitions.
1)
The owner or operator
designated representative of an affected unit
that is also subject to the Acid Rain Program may submit a petition
to the Agency requesting an alternative to any requirement of
Sections 1.14 through 1.18 of this Appendix. Such a petition must
meet the requirements of 40 CFR 75.66, incorporated by reference
in Section 225.140, and any additional requirements established by
Part 225, Subpart B. Use of an alternative to any requirement of
Sections 1.14 through 1.18 of this Appendix is in accordance with
Sections 1.14 through 1.18 of this Appendix and with Part 225,
Subpart B only to the extent that the petition is approved in writing
by the Agency.
2)
Notwithstanding paragraph (f)(1) of this Section, petitions
requesting an alternative to a requirement concerning any
additional CEMS required solely to meet the common stack
provisions of Section 1.16 of this Appendix must be submitted to
the Agency and will be governed by paragraph (f)(3) of this
Section. Such a petition must meet the requirements of 40 CFR
75.66, incorporated by reference in Section 225.140, and any
additional requirements established by Part 225, Subpart B.
3)
The owner or operator
designated representative of an affected unit
that is not subject to the Acid Rain Program may submit a petition
to the Agency requesting an alternative to any requirement of
Sections 1.14 through 1.18 of this Appendix. Such a petition must
meet the requirements of 40 CFR 75.66, incorporated by reference
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in Section 225.140, and any additional requirements established by
Part 225, Subpart B. Use of an alternative to any requirement of
Sections 1.14 through 1.18 of this Appendix is in accordance with
Sections 1.14 through 1.18 of this Appendix only to the extent that
it is approved in writing by the Agency.
39.
The Agency proposes amending Appendix B, subsections 1.16(b)(2)(A) and (C) to
reflect the removal of the term “designated representative.”
b)
Unit utilizing common stack with nonaffected unit(s). When one or more
affected units utilizes a common stack with one or more nonaffected units,
the owner or operator must either:
1)
Install, certify, operate, and maintain the monitoring systems and
(if applicable) perform the mercury emission testing described in
Section 1.15(a) or Section 1.15(b) of this Appendix in the duct to
the common stack from each affected unit; or
2)
Install, certify, operate, and maintain the monitoring systems
described in Section 1.15(a) of this Appendix in the common
stack; and
A)
Install, certify, operate, and maintain the monitoring
systems and (if applicable) perform the mercury emission
testing described in Section 1.15(a) or Section 1.15(b) of
this Appendix in the duct to the common stack from each
non-affected unit. The owner or operator
designated
representative must submit a petition to the Agency to
allow a method of calculating and reporting the mercury
mass emissions from the affected units as the difference
between mercury mass emissions measured in the common
stack and mercury mass emissions measured in the ducts of
the non-affected units, not to be reported as an hourly value
less than zero. The Agency may approve such a method
whenever the owner or operator
designated representative
demonstrates, to the satisfaction of the Agency, that the
method ensures that the mercury mass emissions from the
affected units are not underestimated; or
B)
Count the combined emissions measured at the common
stack as the mercury mass emissions for the affected units,
for recordkeeping and compliance purposes, in accordance
with paragraph (a) of this Section; or
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C)
Submit a petition to the Agency to allow use of a method
for apportioning mercury mass emissions measured in the
common stack to each of the units using the common stack
and for reporting the mercury mass emissions. The Agency
may approve such a method whenever the owner or
operator designated representative demonstrates, to the
satisfaction of the Agency, that the method ensures that the
mercury mass emissions from the affected units are not
underestimated.
40.
The Agency proposes amending Appendix B, Section 1.18(a) to require five years
for record retention so as to be consistent with Section 225.290(a)(6).
Section 1.18 Recordkeeping and reporting
a)
General recordkeeping provisions. The owner or operator of any affected
unit must maintain for each affected unit and each non-affected unit under
Section 1.16(b)(2)(B) of this Appendix a file of all measurements, data,
reports, and other information required by this part at the source in a form
suitable for inspection for at least 5
3 years from the date of each record.
Except for the certification data required in Section 1.11(a)(4) of this
Appendix and the initial submission of the monitoring plan required in
Section 1.11(a)(5) of this Appendix, the data must be collected beginning
with the earlier of the date of provisional certification or the compliance
deadline in Section 1.14(b) of this Appendix. The certification data
required in Section 1.11(a)(4) of this Appendix must be collected
beginning with the date of the first certification test performed. The file
must contain the following information:
41.
The Agency proposes amending Appendix B, subsections 1.18(d)(1), (2), (3), (4)
and (5) and subsection (e) to reflect the removal of the term “designated
representative.”
d)
General reporting provisions.
1)
The owner or operator of
designated representative for an affected
unit must comply with all reporting requirements in this Section
and with any additional requirements set forth in 35 Ill. Adm. Code
Part 225.
2)
The owner or operator of designated representative for an affected
unit must submit the following for each affected unit or group of
units monitored at a common stack and each non-affected unit
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under Section 1.16(b)(2)(B) of this Appendix:
A)
Monitoring plans in accordance with paragraph (e) of this
Section; and
B)
Quarterly reports in accordance with paragraph (f) of this
Section.
3)
Other petitions and communications. The owner or operator of
designated representative for
an affected unit must submit
petitions, correspondence, application forms, and petition-related
test results in accordance with the provisions in Section 1.14(f) of
this Appendix.
4)
Quality assurance RATA reports. If requested by the Agency, the
owner or operator
designated representative of an affected unit
must submit the quality assurance RATA report for each affected
unit or group of units monitored at a common stack and each non-
affected unit under Section 1.16(b)(2)(B) of this Appendix by the
later of 45 days after completing a quality assurance RATA
according to Section 2.3 of Exhibit B to this Appendix or 15 days
of receiving the request. The owner or operator
designated
representative must report the hardcopy information required by
Section 1.13(a)(9) of this Appendix to the Agency.
5)
Notifications. The owner or operator of designated representative
for an affected unit must submit written notice to the Agency
according to the provisions in 40 CFR 75.61, incorporated by
reference in Section 225.140, 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.
e)
Monitoring plan reporting.
The owner or operator
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 owner or operator
designated
representative must submit hardcopy information only if that
portion of the monitoring plan is revised. The owner or operator
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
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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.
42.
In response to comments received from USEPA, the Agency proposes amending
Exhibit A, Section 2.1.3.4 to add an option to certify additional calibration points
rather than ordering new calibration materials.
2.1.3.4 Adjustment of Span and Range
For each affected unit or common stack, the owner or operator must make a
periodic evaluation of the MPC, MEC, span, and range values for each mercury
monitor (at a minimum, an annual evaluation is required) and must make any
necessary span and range adjustments, with corresponding monitoring plan
updates. Span and range adjustments may be required, for example, as a result of
changes in the fuel supply, changes in the manner of operation of the unit, or
installation or removal of emission controls. In implementing the provisions in
paragraphs (a) and (b) of this Section, data recorded during short-term, non-
representative process operating conditions (e.g., a trial burn of a different type of
fuel) must be excluded from consideration. The owner or operator must keep the
results of the most recent span and range evaluation on-site, in a format suitable
for inspection. Make each required span or range adjustment no later than 45 days
after the end of the quarter in which the need to adjust the span or range is
identified, except that up to 90 days after the end of that quarter may be taken to
implement a span adjustment if the calibration gas concentrations currently being
used for calibration error tests, system integrity checks, and linearity checks are
unsuitable for use with the new span value and new calibration materials must be
ordered or additional Hg generator calibration points must be certified.
43.
The Agency proposes amending the title of Exhibit A, Section 3.2 to include
system integrity checks. Language was also added to this Section to change
linearity error to measurement error and add language to include system integrity
checks in the definition for measurement error. In addition, a minor error in the
capitalization of the word “low” was corrected. The changes were made in
response to USEPA comments.
3.2 Linearity and System Integrity
Checks
For CO
2
or O
2
monitors (including O
2
monitors used to measure CO
2
emissions or
percent moisture):
(a) The error in linearity for each calibration gas concentration (low-, mid-, and
high-levels) must not exceed or deviate from the reference value by more than 5.0
percent as calculated using Equation A-4 of this Exhibit; or
(b) The absolute value of the difference between the average of the monitor
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response values and the average of the reference values, R-A in Equation A-4 of
this Exhibit, must be less than or equal to 0.5 percent CO
2
or O
2
, whichever is less
restrictive.
(c) For the linearity check and the 3-level system integrity check of a mercury
monitor, which are required, respectively, under Section 1.4(c)(1)(B) and
(c)(1)(E) of this Appendix, the measurement error must not exceed 10.0 percent
of the reference value at any of the three gas levels. To calculate the measurement
error at each level, take the absolute value of the difference between the reference
value and mean CEM response, divide the result by the reference value, and then
multiply by 100. Alternatively, the results at any gas level are acceptable if the
absolute value of the difference between the average monitor response and the
average reference value, i.e.,
R
−
A
in Equation A-4 of this Exhibit, does not
exceed 0.8 ?g/m
3
. The principal and alternative performance specifications in this
Section also apply to the single-level system integrity check described in Section
2.6 of Exhibit B to this Appendix.
×
100
−
=
R
RA
ME
(Equation A-4)
where,
LME
= Percentage Linearitymeasurement error, for a linearity check or system
integrity check, based upon the reference value.
R = Reference value of Llow-, mid-, or high-level calibration gas introduced into
the monitoring system.
A = Average of the monitoring system responses.
44.
The Agency proposes amending Exhibit A, Section 4 to eliminate references to
electronic submission of data, and to require hardcopy recordkeeping. In
addition, the Agency removed references to the bias adjustment factor.
4. Data Acquisition and Handling Systems
Automated data acquisition and handling systems must read and record the full range
of pollutant concentrations and volumetric flow from zero through span and provide a
continuous, permanent record of all measurements and required information as an
ASCII flata computer data file capable of transmission both by direct computer-to-
computer electronic transfer via modem and EPA-provided software and by an IBM-
compatible personal computer diskettebeing reproduced in a readable hard copy
format. These systems also must have the capability of interpreting and converting
the individual output signals from a flow monitor, a CO
2
monitor, an O
2
monitor, a
moisture monitoring system, a mercury concentration monitoring system, and a
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sorbent trap monitoring system, to produce a continuous readout of pollutant emission
rates or pollutant mass emissions (as applicable) in the appropriate units (e.g., lb/hr,
lb/MMBtu, ounces/hr, tons/hr). These systems also must have the capability of
interpreting and converting the individual output signals from a flow monitor to
produce a continuous readout of pollutant mass emission rates in the units of the
standard. Where CO
2
emissions are measured with a continuous emission monitoring
system, the data acquisition and handling system must also produce a readout of CO
2
mass emissions in tons.
Data acquisition and handling systems must also compute and record monitor
calibration error; any bias adjustments to mercury pollutant concentration data,
flow
rate data, or mercury emission rate data.
45.
In response to comments received from USEPA, the Agency proposes amending
Exhibit A, Sections 5.2.1 – 5.2.4 to include mercury monitors in span
requirements for various concentrations.
5.2.1 Zero-level Concentration
0.0 to 20.0 percent of span, including span for high-scale or both low- and high-
scale for Hg,
CO
2
and O
2
monitors, as appropriate.
5.2.2 Low-level Concentration
20.0 to 30.0 percent of span, including span for high-scale or both low- and high-
scale for Hg,
CO
2
and O
2
monitors, as appropriate.
5.2.3 Mid-level Concentration
50.0 to 60.0 percent of span, including span for high-scale or both low- and high-
scale for Hg,
CO
2
and O
2
monitors, as appropriate.
5.2.4 High-level Concentration
80.0 to 100.0 percent of span, including span for high-scale or both low-and high-
scale for Hg,
CO
2
and O
2
monitors, as appropriate.
46.
The Agency proposes amending Exhibit A, Section 6.2(h) to include chlorine in
mercury monitor linearity checks. Also, language was deleted because it was
considered inaccurate. Both changes were in response to USEPA comments.
(h) For mercury concentration monitors, if moisture and/or chlorine
is added to
the calibration gas during the required linearity checks or system integrity checks,
the dilution effect of the moisture and/or chlorine addition oncontent of the
calibration gas concentration
must be accounted for in an appropriate manner.
Under these circumstances, the dry basis concentration of the calibration gas must
Electronic Filing - Received, Clerk's Office, February 6, 2009
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27
be used to calculate the linearity error or measurement error (as applicable).
47.
The Agency proposes amending Exhibit A, Section 6.3.1 to include chlorine in
mercury monitor calibration error tests. Also, language was deleted because it
was considered inaccurate. Both changes were in response to USEPA comments.
6.3.1 Gas Monitor 7-day Calibration Error Test
Measure the calibration error of each mercury concentration monitor, and each
CO
2
or O
2
monitor while the unit is combusting fuel (but not necessarily
generating electricity) once each day for 7 consecutive operating days according
to the following procedures. For mercury monitors, you may perform this test
using either elemental mercury standards or a NIST-traceable source of oxidized
mercury. Also for mercury monitors, if moisture and/or chlorine is added to the
calibration gas, the dilution effect of the added moisture and/or chlorine on the
calibration gas concentration must be accounted for in an appropriate mannerand
the dry-basis concentration of the calibration gas must be used to calculate the
calibration error. (In the event that unit outages occur after the commencement of
the test, the 7 consecutive unit operating days need not be 7 consecutive calendar
days.) Units using dual span monitors must perform the calibration error test on
both high- and low-scales of the pollutant concentration monitor. The calibration
error test procedures in this Section and in Section 6.3.2 of this Exhibit must also
be used to perform the daily assessments and additional calibration error tests
required under Sections 2.1.1 and 2.1.3 of Exhibit B to this Appendix. Do not
make manual or automatic adjustments to the monitor settings until after taking
measurements at both zero and high concentration levels for that day during the 7-
day test. If automatic adjustments are made following both injections, conduct the
calibration error test such that the magnitude of the adjustments can be
determined and recorded. Record and report test results for each day using the
unadjusted concentration measured in the calibration error test prior to making
any manual or automatic adjustments (i.e., resetting the calibration). The
calibration error tests should be approximately 24 hours apart, (unless the 7- day
test is performed over non-consecutive days).
48.
In response to comments received from USEPA, the Agency proposes amending
Exhibit A, Section 6.5.2 to remove references to operating levels. These operating
levels are used strictly for non-EGUs.
6.5.2 Flow Monitor RATAs (Special Considerations)
(a) Except as otherwise provided in paragraph (b) 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 velocities may be obtained from frequently used unit/load or
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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) 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.
49.
In response to comments received from USEPA, the Agency proposes amending
Exhibit A, Sections 6.5.2.1 and 6.5.2.2 to remove numerous references to
operating levels or thermal output pertaining only to non-EGUs.
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):
(1) For affected units that produce electrical output (in megawatts) or thermal
output (in klb/hr of steam production or mmBtu/hr), tThe 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
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in units of megawatts of thousands of lb/hr of steam load or mmBtu/hr of thermal
output.;or
(b) The operating
load levels for relative accuracy test audits will, except for
peaking units, be defined as follows: the "low" operatingload level will be the
first 30.0 percent of the range of operation; the "mid" operatingload level will be
the middle portion (>30.0 percent, but <=60.0 percent) of the range of operation;
and the "high" operatingload 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
operatingload
levels would be 100 to 400 megawatts, 400 to 700 megawatts, and
700 to 1100 megawatts, respectively.
(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 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)
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.
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(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.
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 operatingload level. If a flow monitor relative accuracy
test is failed or aborted due to a problem with the monitor on any load level of a
2-levelload (or 3-levelload) relative accuracy test audit, the RATA must be
repeated at that load (or operating) level. However, the entire 2-levelload (or 3-
levelload) 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-
levelload
RATA is required.
50.
In response to comments received from USEPA, the Agency proposes amending
Exhibit A, Section 6.5.3 to remove a reference to bias adjustment.
Calculations
Using the data from the relative accuracy test audits, calculate relative accuracy
and bias
in accordance with the procedures and equations specified in Section 7
of this Exhibit.
51.
The Agency proposes amending Exhibit A, Section 6.5.5.3 by including the term
“RATA”, for clarification purposes. In addition, language was added and deleted
to reflect the proper units for some measurements and to substitute the “±”
symbol for the less preferred “+-.”
6.5.5.3 Stratification Test Results and Acceptance Criteria
(a) For each diluent gas RATA
, the short reference method measurement line
described in Section 8.1.3 of PS No. 2 may be used in lieu of the long
measurement line prescribed in Section 8.1.3 of PS No. 2 if the results of a
stratification test, conducted in accordance with Section 6.5.5.1 or 6.5.5.2 of this
Exhibit (as appropriate; see Section 6.5.5(b)(3) of this Exhibit), show that the
concentration at each individual traverse point differs by no more than +±10
.0
percent from the arithmetic average concentration for all traverse points. The
results are also acceptable if the concentration at each individual traverse point
differs by no more than +±5ppm or +-0.5 percent CO
2
(or O
2
) from the arithmetic
average concentration for all traverse points.
(b) For each diluent gas RATA
, a single reference method measurement point,
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located at least 1.0 meter from the stack wall and situated along one of the
measurement lines used for the stratification test, may be used for that diluent gas
if the results of a stratification test, conducted in accordance with Section 6.5.5.1
of this Exhibit, show that the concentration at each individual traverse point
differs by no more than ±+-5
.0 percent from the arithmetic average concentration
for all traverse points. The results are also acceptable if the concentration at each
individual traverse point differs by no more than +-3 ppm or +-±0.3 percent CO
2
(or O
2
) from the arithmetic average concentration for all traverse points.
(c) The owner or operator must keep the results of all stratification tests on-site, in
a format suitable for inspection, as part of the supplementary RATA records
required under Section 1.13(a)(7) of this Appendix.
52.
In response to comments received from USEPA, the Agency proposes amending
Exhibit A, Section 6.5.6 to refer to mercury monitoring systems more specifically
than the previously more general “pollutant concentration monitor.”
6.5.6 Sampling Strategy
(a) Conduct the reference method tests so they will yield results representative of
the pollutant concentration, emission rate, moisture, temperature, and flue gas
flow rate from the unit and can be correlated with the
pollutant
concentrationmercury monitor, CO
2
(or O
2
) monitor, moisture, flow monitoring
system, and mercury CEMS (or excepted monitoring system) measurements (as
applicable). The minimum acceptable time for a gas monitoring system RATA
run or for a moisture monitoring system RATA run is 21 minutes. For each run of
a gas monitoring system RATA, all necessary pollutant concentration
measurements, diluent concentration measurements, and moisture measurements
(if applicable) must, to the extent practicable, be made within a 60-minute period.
For flow monitor RATAs, the minimum time per run must be 5 minutes. Flow
rate reference method measurements may be made either sequentially from port to
port or simultaneously at two or more sample ports. The velocity measurement
probe may be moved from traverse point to traverse point either manually or
automatically. If, during a flow RATA, significant pulsations in the reference
method readings are observed, be sure to allow enough measurement time at each
traverse point to obtain an accurate average reading when a manual readout
method is used (e.g., a "sight-weighted" average from a manometer). Also, allow
sufficient measurement time to ensure that stable temperature readings are
obtained at each traverse point, particularly at the first measurement point at each
sample port, when a probe is moved sequentially from port-to-port. A minimum
of one set of auxiliary measurements for stack gas molecular weight
determination (i.e., diluent gas data and moisture data) is required for every clock
hour of a flow RATA or for every three test runs (whichever is less restrictive).
Alternatively, moisture measurements for molecular weight determination may be
performed before and after a series of flow RATA runs at a particular load level
(low, mid, or high), provided that the time interval between the two moisture
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measurements does not exceed three hours. If this option is selected, the results of
the two moisture determinations must be averaged arithmetically and applied to
all RATA runs in the series. Successive flow RATA runs may be performed
without waiting in-between runs. If an O
2
-diluent monitor is used as a CO
2
continuous emission monitoring system, perform a CO
2
system RATA (i.e.,
measure CO
2
, rather than O
2
, with the reference method). For moisture
monitoring systems, an appropriate coefficient, "K" factor or other suitable
mathematical algorithm may be developed prior to the RATA, to adjust the
monitoring system readings with respect to the reference method. If such a
coefficient, K-factor or algorithm is developed, it must be applied to the CEMS
readings during the RATA and (if the RATA is passed), to the subsequent CEMS
data, by means of the automated data acquisition and handling system. The owner
or operator must keep records of the current coefficient, K factor or algorithm, as
specified in Section 1.13(a)(5)(F) of this Appendix. Whenever the coefficient, K
factor or algorithm is changed, a RATA of the moisture monitoring system is
required. For the RATA of a mercury CEMS using the Ontario Hydro Method, or
for the RATA of a sorbent trap system (irrespective of the reference method
used), the time per run must be long enough to collect a sufficient mass of
mercury to analyze. For the RATA of a sorbent trap monitoring system, the type
of sorbent material used by the traps must be the same as for daily operation of
the monitoring system; however, the size of the traps used for the RATA may be
smaller than the traps used for daily operation of the system. Spike the third
section of each sorbent trap with elemental mercury, as described in Section 7.1.2
of Exhibit D to this Appendix. Install a new pair of sorbent traps prior to each test
run. For each run, the sorbent trap data must be validated according to the quality
assurance criteria in Section 8 of Exhibit D to this Appendix.
(b) To properly correlate individualthe
mercury CEMS data (in lb/MMBtu) and,
volumetric flow rate, moisture, CO
2
(or O
2
) monitoring system data with the
reference method data, annotate the beginning and end of each reference method
test run (including the exact time of day) on the individual chart recorder(s) or
other permanent recording device(s).
53.
The Agency proposes amending Exhibit A, Section 6.5.8 to remove references to
operating levels for reasons identical to errata item 48.
6.5.8 Number of Reference Method Tests
Perform a minimum of nine sets of paired monitor (or monitoring system) and
reference method test data for every required (i.e., certification, recertification,
diagnostic, semiannual, or annual) relative accuracy test audit. For 2-levelload
and 3-levelload relative accuracy test audits of flow monitors, perform a
minimum of nine sets at each of the operatingload levels.
54.
In response to comments received from USEPA, the Agency proposes amending
Exhibit A, Section 6.5.9 to allow appropriate reference method testing and to
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correct improper citation.
6.5.9 Reference Methods
The following methods are from appendix A to 40 CFR 60, incorporated by
reference in Section 225.140, or have been published by ASTM, and are the
reference methods for performing relative accuracy test audits under this part:
Method 1 or 1A in appendix A-1 to 40 CFR 60 for siting; Method 2 or its
allowable alternatives in appendices A-1 and A-2 to 40 CFR 60 or its allowable
alternatives in appendix A to 40 CFR 60 (except for Methods 2B and 2E in
appendix A-1 to 40 CFR 60) for stack gas velocity and volumetric flow rate;
Methods 3, 3A or 3B in appendix A-2 to 40 CFR 60 for O
2
and CO
2
; Method 4 in
appendix A-3 to 40 CFR 60 for moisture; and for mercury, either ASTM D6784-
02 (the Ontario Hydro Method, ) (incorporated by reference under Section
225.140), or Method 29 in appendix A-8 to 40 CFR 60, Method 30A, or Method
30B in appendix A-8 to 40 CFR 60
.
55.
The Agency proposes amending Exhibit A, Section 7.1 to amend the title to
include system integrity checks, to change linearity error to measurement error,
and to add language to include system integrity checks in the definition for
measurement error. The changes were made in response to comments received
from USEPA.
7.1 Linearity and System Integrity
Checks
Analyze the linearity check data for pollutant concentration Hg, CO
2
, and O
2
monitors and the system integrity check data for Hg CEMS
as follows. Calculate
the percentage measurement error in linearity based upon the reference value at
the low-level, mid-level, and high-level concentrations specified in Section 6.2 of
this Exhibit. Perform this calculation once during the certification test. Use the
following equation to calculate the measurement error in linearity for each
reference value.
×
100
−
=
R
RA
ME
(Equation A-4)
where,
LME=Percentage
Linearitymeasurement error, based upon the reference value.
R=Reference value of Llow-, mid-, or high-level calibration gas introduced into
the monitoring system.
A=Average of the monitoring system responses.
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56.
In response to comments received from USEPA, the Agency proposes amending
Exhibit B, Section 2.1.3(b) to remove the word “tag,” as it is not appropriate in
this context.
(b) Routine calibration adjustments of a monitor are permitted after any
successful calibration error test. These routine adjustments must be made so as to
bring the monitor readings as close as practicable to the known tag
values of the
calibration gases or to the actual value of the flow monitor reference signals. An
additional calibration error test is required following routine calibration
adjustments where the monitor's calibration has been physically adjusted (e.g., by
turning a potentiometer) to verify that the adjustments have been made properly.
An additional calibration error test is not required, however, if the routine
calibration adjustments are made by means of a mathematical algorithm
programmed into the data acquisition and handling system. It is recommended
that routine calibration adjustments be made, at a minimum, whenever the daily
calibration error exceeds the limits of the applicable performance specification in
Exhibit A to this Appendix for the pollutant concentration monitor, CO
2
or O
2
monitor, or flow monitor.
57.
The Agency proposes amending Exhibit B, Section 2.1.4 to correct an erroneous
citation.
2.1.4 Data Validation
(a) An out-of-control period occurs when the calibration error of a CO
2
or O
2
monitor (including O
2
monitors used to measure CO
2
emissions or percent
moisture) exceeds 1.0 percent CO
2
or O
2
, or when the calibration error of a flow
monitor or a moisture sensor exceeds 6.0 percent of the span value, which is twice
the applicable specification of Exhibit A to this Appendix. Notwithstanding, a
differential pressure-type flow monitor for which the calibration error exceeds 6.0
percent of the span value will not be considered out-of-control if
R
−
A
, the
absolute value of the difference between the monitor response and the reference
value in Equation A-6 of Exhibit A to this Appendix, is < 0.02 inches of water.
For a mercury monitor, an out-of-control period occurs when the calibration error
exceeds 5.0% of the span value. Notwithstanding, the mercury monitor will not be
considered out-of-control if
R
−
A
in Equation A-6A-5 does not exceed 1.0
?g/scm. The out-of-control period begins upon failure of the calibration error test
and ends upon completion of a successful calibration error test. Note, that if a
failed calibration, corrective action, and successful calibration error test occur
within the same hour, emission data for that hour recorded by the monitor after
the successful calibration error test may be used for reporting purposes, provided
that two or more valid readings are obtained as required by Section 1.2 of this
Appendix. Emission data must not be reported from an out-of-control monitor.
58.
The Agency proposes amending Exhibit B, Section 2.2.1 to remove an exception
for linearity checks that would only apply to SO
2
and NO
x
monitors.
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2.2.1 Linearity Check
Unless a particular monitor (or monitoring range) is exempted under this
paragraph or under Section 6.2 of Exhibit A to this Appendix, pPerform a
linearity check, in accordance with the procedures in Section 6.2 of Exhibit A to
this Appendix, for each primary and redundant backup, mercury, pollutant
concentration monitor and each primary and redundant backup CO
2
or O
2
monitor
(including O
2
monitors used to measure CO
2
emissions or to continuously
monitor moisture) at least once during each QA operating quarter, as defined in
40 CFR 72.2, incorporated by reference in Section 225.140. For mercury
monitors, perform the linearity checks using elemental mercury standards.
Alternatively, you may perform 3-level system integrity checks at the same three
calibration gas levels (i.e., low, mid, and high), using a NIST-traceable source of
oxidized mercury. If you choose this option, the performance specification in
Section 3.2(c) of Exhibit A to this part must be met at each gas level. For units
using both a low and high span value, a linearity check is required only on the
range(s) used to record and report emission data during the QA operating quarter.
Conduct the linearity checks no less than 30 days apart, to the extent practicable.
The data validation procedures in Section 2.2.3(e) of this Exhibit must be
followed.
59.
The Agency proposes amending Exhibit B, Section 2.2.5 to correct several cross-
referencing errors.
2.2.5 Flow-to-Load Ratio or Gross Heat Rate Evaluation
(a) Applicability and methodology. Unless exempted from the flow-to-load ratio
test under Section 7.8 to Appendix A to 40 CFR Part 75
7.6 of Exhibit A to this
Appendix, the owner or operator must, for each flow rate monitoring system
installed on each unit, common stack or multiple stack, evaluate the flow-to-load
ratio quarterly, i.e., for each QA operating quarter (as defined in 40 CFR 72.2,
incorporated by reference in Section 225.140). At the end of each QA operating
quarter, the owner or operator must use Equation B-1 to calculate the flow-to-load
ratio for every hour during the quarter in which: the unit (or combination of units,
for a common stack) operated within +-10.0 percent of
L
avg
, the average load
during the most recent normal-load flow RATA; and a quality assured hourly
average flow rate was obtained with a certified flow rate monitor. Alternatively,
for the reasons stated in paragraphs (c)(1) through (c)(6) of this Section, the
owner or operator may exclude from the data analysis certain hours within +-10.0
percent of
L
avg
and may calculate
R
h
values for only the remaining hours.
=
×
10
−
5
h
h
h
L
Q
R
(Equation B-1)
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where,
R
h
= Hourly value of the flow-to-load ratio, scfh/megawatts, scfh/1000 lb/hr of
steam, or scfh/(mmBtu/hr thermal output).
Q
h
= Hourly stack gas volumetric flow rate, as measured by the flow rate
monitor, scfh.
L
h
= Hourly unit load, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal
output; must be within + 10.0 percent of
L
avg
during the most recent normal-load
flow RATA.
(1) In Equation B-1, the owner or operator may use either bias-adjusted flow rates
or unadjusted flow rates, provided that all of the ratios are calculated the same
way. For a common stack,
L
h
will be the sum of the hourly operating loads of all
units that discharge through the stack. For a unit that discharges its emissions
through multiple stacks or that monitors its emissions in multiple breechings,
Q
h
will be either the combined hourly volumetric flow rate for all of the stacks or
ducts (if the test is done on a unit basis) or the hourly flow rate through each stack
individually (if the test is performed separately for each stack). For a unit with a
multiple stack discharge configuration consisting of a main stack and a bypass
stack, each of which has a certified flow monitor (e.g., a unit with a wet SO
2
scrubber), calculate the hourly flow-to-load ratios separately for each stack.
Round off each value of
R
h
to two decimal places.
(2) Alternatively, the owner or operator may calculate the hourly gross heat rates
(GHR) in lieu of the hourly flow-to-load ratios. The hourly GHR must be
determined only for those hours in which quality assured flow rate data and
diluent gas (CO
2
or O
2
) concentration data are both available from a certified
monitor or monitoring system or reference method. If this option is selected,
calculate each hourly GHR value as follows:
(
)
=
(
)
×
1000
h
h
h
L
HeatInput
GHR
(Equation B-1a)
where,
(
GHR
)
h
= Hourly value of the gross heat rate, Btu/kwh, Btu/lb steam load, or
1000 mmBtu heat input/mmBtu thermal output.
(
HeatInput
)
h
= Hourly heat input, as determined from the quality assured flow
rate and diluent data, using the applicable equation in Exhibit C to this Appendix,
mmBtu/hr.
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L
h
= Hourly unit load, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal
output; must be within + 10.0 percent of
L
avg
during the most recent normal-load
flow RATA.
(3) In Equation B-1a, the owner or operator may either use bias-adjusted flow
rates or unadjusted flow rates in the calculation of
(
HeatInput
)
h
, provided that all
of the heat input values are determined in the same manner.
(4) The owner or operator must evaluate the calculated hourly flow-to-load ratios
(or gross heat rates) as follows. A separate data analysis must be performed for
each primary and each redundant backup flow rate monitor used to record and
report data during the quarter. Each analysis must be based on a minimum of 168
acceptable recorded hourly average flow rates (i.e., at loads within +- 10 percent
of
L
avg
). When two RATA load levels are designated as normal, the analysis must
be performed at the higher load level, unless there are fewer than 168 acceptable
data points available at that load level, in which case the analysis must be
performed at the lower load level. If, for a particular flow monitor, fewer than 168
acceptable hourly flow-to-load ratios (or GHR values) are available at any of the
load levels designated as normal, a flow-to-load (or GHR) evaluation is not
required for that monitor for that calendar quarter.
(5) For each flow monitor, use Equation B-2 in this Exhibit to calculate
E
h
, the
absolute percentage difference between each hourly
R
h
value and
R
ref
, the
reference value of the flow-to-load ratio, as determined in accordance with
Section 7.7 to Appendix A to 40 CFR Part 757.5 of Exhibit A to this Appendix.
Note that
R
ref
must always be based upon the most recent normal-load RATA,
even if that RATA was performed in the calendar quarter being evaluated.
×
100
−
=
ref
ref
h
h
R
RR
E
(Equation B-2)
where:
E
h
= Absolute percentage difference between the hourly average flow-to-load
ratio and the reference value of the flow-to-load ratio at normal load.
R
h
= The hourly average flow-to-load ratio, for each flow rate recorded at a load
level within +-10.0 percent of
L
avg
.
R
ref
= The reference value of the flow-to-load ratio from the most recent normal-
load
flow RATA, determined in accordance with Section 7.7 to Appendix A
to 40
Electronic Filing - Received, Clerk's Office, February 6, 2009
* * * * * PC #2 * * * * *
38
CFR Part 757.5 of Exhibit A to this Appendix.
(6) Equation B-2 must be used in a consistent manner. That is, use
R
ref
and
R
h
if
the flow-to-load ratio is being evaluated, and use (GHR)ref and (GHR) h if the
gross heat rate is being evaluated. Finally, calculate
E
f
, the arithmetic average of
all of the hourly
E
h
values. The owner or operator must report the results of each
quarterly flow-to-load (or gross heat rate) evaluation, as determined from
Equation B-2, in the electronic quarterly report required under 40 CFR 75.64,
incorporated by reference in Section 225.140.
60.
In response to comments received from USEPA, the Agency proposes amending
Exhibit B, Section 2.3.1.1 to specify that each moisture monitor must undergo a
RATA.
2.3.1.1 Standard RATA Frequencies
(a) Except for mercury monitoring systems, and as otherwise specified in Section
2.3.1.2 of this Exhibit, perform relative accuracy test audits semiannually, i.e.,
once every two successive QA operating quarters (as defined in 40 CFR 72.2,
incorporated by reference in Section 225.140) for each primary and redundant
backup flow monitor, CO
2
or O
2
diluent monitor used to determine heat input, and
each moisture monitoring system. For each primary and redundant backup
mercury concentration monitoring system and each sorbent trap monitoring
system, RATAs must be performed annually, i.e., once every four successive QA
operating quarters (as defined in 40 CFR 72.2). A calendar quarter that does not
qualify as a QA operating quarter must be excluded in determining the deadline
for the next RATA. No more than eight successive calendar quarters must elapse
after the quarter in which a RATA was last performed without a subsequent
RATA having been conducted. If a RATA has not been completed by the end of
the eighth calendar quarter since the quarter of the last RATA, then the RATA
must be completed within a 720 unit (or stack) operating hour grace period (as
provided in Section 2.3.3 of this Exhibit) following the end of the eighth
successive elapsed calendar quarter, or data from the CEMS will become invalid.
61.
The Agency proposes amending Exhibit B, Section 2.3.1.3 to remove numerous
references to operating levels for reasons identical to those in errata item 48.
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
Electronic Filing - Received, Clerk's Office, February 6, 2009
* * * * * PC #2 * * * * *
39
operating level).
(b) For flow monitors installed and bypass stacks 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
6.5.2.1(d) 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-
linearizedre-characterized, 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.
(6) For all multi-level flow audits, the audit points at adjacent load levels or at
Electronic Filing - Received, Clerk's Office, February 6, 2009
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40
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.
62.
The Agency proposes amending Exhibit B, Section 2.3.2(b)(2) to include the full
citation to the appropriate Section of Appendix B, which was previously omitted.
(2) The RATA may be done after performing only the routine or non-routine
calibration adjustments described in Section 2.1.3 of this Exhibit at the zero
and/or upscale calibration gas levels, but no other corrective maintenance, repair,
re-linearization or reprogramming of the monitoring system. Trial RATA runs
may be performed after the calibration adjustments and additional adjustments
within the allowable limits in Section 2.1.3 of this Exhibit may be made prior to
the RATA, as necessary, to optimize the performance of the CEMS. The trial
RATA runs need not be reported, provided that they meet the specification for
trial RATA runs in Section 1.4(b)(3)(G)(v) of this Appendix. However, if, for any
trial run, the specification in Section 1.4(b)(3)(G)(v)
of this Appendix is not met,
the trial run must be counted as an aborted RATA attempt.
63.
The Agency proposes amending Exhibit B, subsection 2.3.2(d) and (f) to remove
references to operating levels for reasons identical to errata item 48.
Additionally, the Agency proposes replacing the word “re-linearize” with the
more appropriate “re-characterize.” Changes were made in response to USEPA
comments.
(d) For single-load (or single-level)
RATAs, if a daily calibration error test is
failed during a RATA test period, prior to completing the test, the RATA must be
repeated. Data from the monitor are invalidated prospectively from the hour of the
failed calibration error test until the hour of completion of a subsequent successful
calibration error test. The subsequent RATA must not be commenced until the
monitor has successfully passed a calibration error test in accordance with Section
2.1.3 of this Exhibit. Notwithstanding these requirements, when 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 as the
reference method for the RATA of a mercury CEMS, if a calibration error test of
the CEMS is failed during a RATA test period, any test run(s) completed prior to
the failed calibration error test need not be repeated; however, the RATA may not
continue until a subsequent calibration error test of the mercury CEMS has been
passed. For multiple-load (or multiple-level)
flow RATAs, each load level (or
operating level) is treated as a separate RATA (i.e., when a calibration error test is
failed prior to completing the RATA at a particular load level (or operating level)
,
only the RATA at that load level (or operating
level) must be repeated; the results
Electronic Filing - Received, Clerk's Office, February 6, 2009
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41
of any previously-passed RATA(s) at the other load level(s) (or operating
level(s)) are unaffected, unless re-characterizationre-linearization of the monitor
is required to correct the problem that caused the calibration failure, in which case
a subsequent 3-load (or 3-level)
RATA is required), except as otherwise provided
in Section 2.3.1.3(c)(5) of this Exhibit.
(f) For a 2-levelload or 3-levelload flow RATA, if, at any load level (or operating
level), a RATA is failed or aborted due to a problem with the flow monitor, the
RATA at that load level (or operating level) must be repeated. The flow monitor
is considered out-of-control and data from the monitor are invalidated from the
hour in which the test is failed or aborted and remain invalid until the passing of a
RATA at the failed load level (or operating level)
, unless the option in paragraph
(b)(3) of this Section to use the data validation procedures and associated
timelines in Section 1.4(b)(3)(B) through (b)(3)(I) of this Appendix has been
selected, in which case the beginning and end of the out-of-control period must be
determined in accordance with Section 1.4(b)(3)(G)(i) and (ii) of this Appendix.
Flow RATA(s) that were previously passed at the other load level(s) (or operating
levels(s)) do not have to be repeated unless the flow monitor must be re-
linearizedre-characterized following the failed or aborted test. If the flow monitor
is re-linearizedre-characterized, a subsequent 3-load (or 3-level) RATA is
required, except as otherwise provided in Section 2.3.1.3(c)(5) of this Exhibit.
64.
The Agency proposes amending Exhibit B, Section 2.4(b) to provide a minor
clarification of RATA frequency requirements. Also, language was deleted to
remove references to operating levels, consistent with errata item 48.
(b) Except for Hg monitoring systemsas
provided in Section 2.3.3 of this Exhibit
(which always have an annual RATA frequency), whenever a passing RATA of a
gas monitor is performed, or a passing 2-load (or 2-level) RATA or a passing 3-
load (or 3-level) RATA of a flow monitor is performed (irrespective of whether
the RATA is done to satisfy a recertification requirement or to meet the quality
assurance requirements of this Exhibit, or both), the RATA frequency (semi-
annual or annual) must be established based upon the date and time of completion
of the RATA and the relative accuracy percentage obtained. For 2-load (or 2-
level) and 3-load (or 3-level) flow RATAs, use the highest percentage relative
accuracy at any of the loads (or levels) to determine the RATA frequency. The
results of a single-load (or single-level) flow RATA may be used to establish the
RATA frequency when the single-load (or single-level) flow RATA is
specifically required under Section 2.3.1.3(b) of this Exhibit or when the single-
load (or single-level)
RATA is allowed under Section 2.3.1.3(c) of this Exhibit for
a unit that has operated at one load level (or operating level) for >=≥85.0 percent
of the time since the last annual flow RATA. No other single-load (or single-
level) flow RATA may be used to establish an annual RATA frequency; however,
a 2-load or 3-load or a 2-level or 3-level) flow RATA may be performed at any
time or in place of any required single-load (or single-level)
RATA, in order to
establish an annual RATA frequency.
Electronic Filing - Received, Clerk's Office, February 6, 2009
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42
65.
In response to comments received from USEPA, the Agency proposes amending
Exhibit B, Section 2.5 to include an alternative to an additional audit test that is
successful.
2.5 Other Audits
Affected units may be subject to relative accuracy test audits at any time. If a
monitor or continuous emission monitoring system fails the relative accuracy test
during the audit, the monitor or continuous emission monitoring system will be
considered to be out-of-control beginning with the date and time of completion of
the audit, and continuing until a successful audit test is completed following
corrective action. Alternatively, the conditional data validation procedures and
associated timelines in Sections 1.4(b)(3)(B) through (I) of this Appendix may be
used following the corrective actions.
66.
The Agency proposes amending Exhibit C, Sections 2.3.1 and 2.3.2 to clarify
Equations F-18a and F-18b. The changes are inconsequential to the
calculations, and were made in response to USEPA comments.
2.3.1
Calculate total quarterly heat input for a unit or common stack using a flow
monitor and diluent monitor to calculate heat input, using the following equation:
∑
=
=
n
hour
HI
q
HI
i
t
i
1
(Equation F-18a)
Where:
HI
q
= Total heat input for the quarter “q”, mmBtu.
HI
i
= Hourly hHeat input rate for hour “i” during unit operation, using Equation
F-15, F-16, F-17, or F-18, mmBtu/hr.
t
i
= Hourly operating time for the unit or common stack, hour or fraction of an
hour (in equal increments that can range from one hundredth to one quarter of an
hour, at the option of the owner or operator).
n = Number of unit operating hours in the quarter.
2.3.2
Calculate total cumulative (year-to-date)
heat input for a unit or common stack
using a flow monitor and diluent monitor to calculate heat input, using the
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43
following equation:
∑
=
=
the current quarter
q
HI
c
HI
q
__
1
(Equation F-18b)
Where:
HI
c
= Total heat input for the year to date, mmBtu.
HI
q
= Total heat input for the quarter “q”, mmBtu.
67.
The Agency proposes amending Exhibit C, Sections 4.1.1 and 4.1.2 by replacing a
“?” symbol, correcting a capitalization error, moving the “(hr)” unit indicator in
two instances, and specifying two instances where an incorporation by reference
was not previously specified.
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 (?g/wscm).
Q
h
= Hourly stack gas volumetric flow rate (scfh)
t
h
= Unit or stack operating time (hr), as defined in 40 CFR 72.2,
(hr)incorporated by reference in Section 225.140.
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:
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44
M
h
=
KC
h
Q
h
t
h
(
1
−
B
ws
)
(Equation F-29)
Where:
M
h
= mMercury 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 (?g/dscm). For sorbent trap
systems, a single value of
C
h
(i.e., a flow-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 (scfh).
B
ws
= Moisture fraction of the stack gas, expressed as a decimal (equal to %H
2
O/
100)
t
h
= Unit or stack operating time (hr), as defined in 40 CFR 72.2,
(hr)incorporated by reference in Section 225.140.
68.
In response to comments received from USEPA, the Agency proposes amending
Exhibit D, Section 2.0 to remove language that has subsequently been removed
from 40 CFR Part 75.
2.0 Principle.
Known volumes of flue gas are extracted from a stack or duct through paired, in-
stack, pre-spiked sorbent media traps at an appropriate nominal flow rate.
Collection of mercury on the sorbent media in the stack mitigates potential loss of
mercury during transport through a probe/sample line. Paired train sampling is
required to determine measurement precision and verify acceptability of the
measured emissions data.
The sorbent traps are recovered from the sampling system, prepared for analysis,
as needed, and analyzed by any suitable determinative technique that can meet the
performance criteria. A section of each sorbent trap is spiked with Hg
0
prior to
sampling. This section is analyzed separately and the recovery value is used to
correct the individual mercury sample for measurement bias.
69.
The Agency proposes amending Exhibit D, Section 8.0 Table K-1 Footnote FN**
to remove language involving multiplying factor of 1.11 for single trap data.
When one trap fails to meet QA requirements the valid trap may be used. The
change was made in response to industry comments.
Electronic Filing - Received, Clerk's Office, February 6, 2009
* * * * * PC #2 * * * * *
45
[FN**] Note: If both traps fail to meet the acceptance criteria, the data from the
pair of traps are invalidated. However, if only one of the paired traps fails to meet
this particular acceptance criterion and the other sample meets all of the
applicable QA criteria, the results of the valid trap may be used for reporting
under this part, provided that the measured Hg concentration is multiplied by a
factor of 1.111. When the data from both traps are invalidated and quality-assured
data from a certified backup monitoring system, reference method, or approved
alternative monitoring system are unavailable, missing data substitution must be
used.
70.
In response to comments received from USEPA, the Agency proposes amending
Exhibit D, Section 11.7 to correct two erroneous references.
11.7 Calculation of Mercury Mass Emissions.
To calculate mercury mass emissions, follow the procedures in Section 4.1.2 of
Exhibit C to this Appendix. Use the average of the two mercury concentrations
from the paired traps in the calculations, except as provided in Section
2.2.3(h)1
.3(h) of Exhibit BA to this Appendix or in Table K-1.
71.
The Agency proposes amending Section 225.250(a)(3)(D)(iv) to correct an
erroneous citation.
iv)
Audit Decertification. The Agency may issue a
notice of disapproval of the certification status of a
monitor in accordance with Section 225.260(cb)
.
Electronic Filing - Received, Clerk's Office, February 6, 2009
* * * * * PC #2 * * * * *
46
Respectfully submitted,
ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY
/s Charles Matoesian
__________
Charles E. Matoesian
Assistant Counsel
/s Dana Vetterhoffer__________________
Dana Vetterhoffer
Assistant Counsel
DATED: February 6, 2009
1021 North Grand Avenue East
P.O. Box 19276
Springfield, Illinois 62794-9276
(217) 782-5544
Electronic Filing - Received, Clerk's Office, February 6, 2009
* * * * * PC #2 * * * * *
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 THIRD ERRATA
SHEET TO ITS PROPOSAL TO AMEND 35 ILL. ADM. CODE 225, 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,
By:
Charles E. Matoesian
/s_ Charles E. Matoesian_____
Assistant Counsel
Division of Legal Counsel
Dated: February 6, 2009
1021 North Grand Avenue East
P.O. Box 19276
Springfield, Illinois 62794-9276
217.782.5544
217.782.9143 (TDD)
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
Renee Cipriano
Stephen J. Bonebrake
Kathleen C. Bassi
Joshua R. More
David M. Loring
Schiff Hardin, LLP
233 S. Wacker Dr
6600 Sears Tower
Chicago, IL 60606
David Rieser
Bradley R. Daniels
McGuire Woods, LLP
77 W. Wacker
Suite 4100
Chicago, IL 60601
S. David Farris
City of Springfield, Office of Public Works
201 East Lake Shore Dr.
Springfield, IL 62757