BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
IN
THE MATTER OF:
AMENDMENTS TO 35 ILL.ADM.CODE 225:
CONTROL OF EMISSIONS FROM LARGE
COMBUSIONS SOURCES (MERCURY
MONITORING)
)
)
)
)
)
)
)
)
)
NOTICE OF FILING
To:
R09-10
(Rulemaking - Air)
John Therriault, Assistant Clerk
Illinois
Pollution Control Board
James
R. Thompson Center
Suite 11-500
Persons on the Attached Service List
100 West Randolph
Chicago, Illinois 6060 I
PLEASE TAKE NOTICE that we have today electronically filed with the Office
of the
Clerk
of the Pollution Control Board Testimony of Aric D. Diericx On Behalf of Dynegy
M'
st Generation, Inc., copies of which are herewith served upon you.
U(?~
Joshua R. More
Dated: February
2,2009
Joshua R. More
SCHIFF HARDIN, LLP
6600 Sears Tower
233 South Wacker Drive
Chicago, Illinois 60606
312-258-5500
Electronic Filing - Received, Clerk's Office, February 2, 2009
CERTIFICATE OF SERVICE
I,
the undersigned, certify that on this 2nd day of February, 2009, I have served
electronically the attached
Testimony of Aric D. Diericx On Behalf of Dynegy Midwest
Generation, Inc.,
upon the following persons:
John Therriault, Assistant Clerk
Illinois Pollution Control Board
James
R. Thompson Center
Suite 11-500
100 West Randolph
Chicago, Illinois 6060 I
and electronically and by first class mail, postage affixed, upon persons on the attached Service
List.
Joshua
R. More
SCHIFF HARDIN, LLP
6600 Sears Tower
233 South Wacker Drive
Chicago, Illinois 60606
312-258-5500
~
Joshua R. More
Electronic Filing - Received, Clerk's Office, February 2, 2009
SERVICE LIST
(R09-10)
Timothy Fox
Hearing Offi cer
Illinois Pollution Control Board
100 West Randolph, Suite 11-500
Chicago, Illinois 60601
foxt@ipcb.state.il.us
S. David Farris, Manager, Environmental,
Health and Safety
City
of Springfield, City Water Light
&
Power
201 East Lake Shore Drive
Springfield, Illinois 62757
dfarris@cwlp.com
CH2\2895810.2
JolmJ. Kim
Charles
E. Matoesian
Dana Vetterhoffer
Division
of Legal Counsel
Illinois Environmental Protection Agency
1021 North Grand Avenue, East
P.O. Box 19276
Springfield, Illinois 62794-9276
jolm.j.kim@illinois.gov
charles.matoesian@illinois.gov
dana. vetterhoffer@illinois.gov
David Rieser
McGuireWoods LLP
77 W. Wacker Drive, Suite 4100
Chicago, Illinois 60601
drieser@mcguirewoods.com
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
IN THE MATTER OF:
AMENDMENTS TO 35 ILL.ADM.CODE 225:
CONTROL OF EMISSIONS FROM LARGE
COMBUSTION SOURCES (MERCURY
MONITORING)
)
)
)
)
)
)
R09-10
(Rulemaking - Air)
TESTIMONY
OF ARIC D. DIERICX
ON BEHALF
OF DYNEGY MIDWEST GENERATION, INC.
My name is Aric Diericx. I am testifying on behalf of Dynegy Midwest Generation, Inc.
While Dynegy supports the Illinois Environmental Protection Agency's ("Agency") stated
objective
of incorporating the monitoring portions of the vacated Clean Air Mercury Rule
("CAMR") into the Illinois mercury rule, Dynegy has several concerns with the Agency's
proposed amendments in this rulemaking that
go beyond the requirements of the CAMR
monitoring provisions. Dynegy is concerned with the Agency's position regarding "optimum
manner"
as that term is used in Section 225.233(c)(2) of the currently effective Illinois mercury
rule and the retrospective noncompliance exposure presented
by proposed Section 225.239(g)(2).
Additionally, Dynegy requests clarity on a couple
of issues and supports an alternative mercury
emission reduction calculation methodology.
I
am the Senior Director-Operations Environmental Compliance for Dynegy's Midwest
Region. The Midwest Region has generating facilities in Illinois, Michigan, Pennsylvania, and
Kentucky. The Midwest Region also provides environmental compliance support for a new coal
plant under construction in Arkansas. I have been employed in this and similar positions
at
Dynegy for the past eight years. As part of my duties at Dynegy, I oversee permitting and
regulatory development and compliance for air, water, and waste issues. Previously, I was
-1-
employed by Illinois Power Company since 1979 in its environmental department. Illinois
Power and Dynegy merged in
1999/2000.
I received a Bachelor of Science degree in meteorology from Northern Illinois University
in DeKalb, Illinois, in 1979. I have 29 years
of experience in environmental compliance,
primarily with air quality programs, including New Source Review, the Acid Rain Program, and
Title V pennitting. I have supervised the development
of ambient air quality monitoring
programs, the development
of a site-specific dispersion model, and Illinois Power's State
Implementation Plan revision for sulfur dioxide ("S02"). I was involved in the studies
of the
Ozone Transport Assessment Group and the subsequent development
of the NOx SIP Call Rule
in Illinois (Part 217, Subpart W
of the Board's rules), as well as the state's Part 225 mercury
emissions rulemaking. I have served
as chainnan of the Midwest Ozone Group and the Air
Utility Group
of Illinois. I am knowledgeable about Dynegy's air quality compliance programs
and the efforts that would
be required to comply with the proposed changes to the Illinois
mercury rule.
Dynegy owns and operates five coal-fired power plants in Illinois that are affected
by this
proposed rulemaking. These are the Baldwin Energy Complex located in Randolph County, the
Havana Power Station located in Mason County, the Hennepin Power Station located in Putnam
County, the Vennilion Power Station located in Vennilion County, and the Wood River Power
Station located in Madison County. These five power plants account for approximately 3,375
gross megawatts of generation, accounting for around 21
%
of the total installed coal-fired
generating capacity in the state.
-2-
Electronic Filing - Received, Clerk's Office, February 2, 2009
Optimum Manner
Dynegy has reviewed Mr. Scott Miller's testimony on behalf of Midwest Generation on
this topic and adopts the same position. To ensure clarity, I note that Mr. Miller referred
to
Section 225.294 in the Combined Pollutant Standard ("CPS") regarding the requirement that
halogenated activated carbon or sorbent
be injected in an optimum manner. Similar language
appears in the Multi-Pollutant Standard ("MPS") at Section 225.233(c)(2). Dynegy opted in
to
the MPS on November 26,2007. Dynegy's decision to opt in to the MPS was based on the plain
language
of the MPS that afforded Dynegy relief until 2015 (or such earlier date that Dynegy
determined that a unit should become subject
to the percent reduction emission limit) from the
requirement
to reduce mercury emissions to any set level of reduction or even approximation of
any particular level of reduction so long as Dynegy injected one of the listed sorbents at a rate of
5 Ibs/mad using an injection system designed for effective absorption of mercury in the flue gas
considering the configuration
of the electric generating unit ("EGU") and its ductwork. In
addition, the plain language
of the mercury rule limited Dynegy's MPS units to routine
monitoring
of the feed rate of sorbent injection and the exhaust gas flow rate
The MPS requires sources to "inject [sorbent] in
an optimum manner" using "an injection
system designed for effective absorption
of mercury," including the requirements for a minimum
injection rate and sorbent products from specific manufacturers. The designs
of Dynegy's
sorbent injection systems were included in its construction permit applications that were
approved
by the Agency when it issued the construction permits for our sorbent injection
systems.
I
The injection rate of 5 Ibs/macf is required if the unit bums subbituminous coal. The
injection rate
of2.5lbs/macfapplies for cyclone-fired EGUs that will install a scrubber and
baghouse
by December 31, 2012, and already meet an emission rate of 0.020 Ib HgiGWh or at
least 75% reduction.
See
Section 225.233(c)(2)(C).
-3-
Dynegy opted in to the MPS in 2007 based on its review and assessment ofthe original
MPS requirements. Dynegy's understanding of the original rule was confirmed by the Agency's
testimony acknowledging that "optimum manner" is defined in the mercury rule and that the
definition does not specify a percent reduction in mercury emissions. Tr. 51-52, R09-1
0,
Dec. 17,2008. Dynegy has already committed to comply with the specific set ofMPS
requirements as they appeared in the originally promulgated rule and the Agency-issued
construction permits. Since Dynegy is already locked in to MPS participation, it urges the Board
to reject any attempt to expand the MPS rule to include mercury removal efficiency in a re-
definition
of "optimum manner" or as a factor in determining compliance with the MPS rule.
Retrospective Noncompliance Under Proposed Section 22S.239(g)(2)
Dynegy generally supports the Agency's proposal to include the stack testing option at
Section 225.239. However, the retrospective noncompliance established in Section
225.239(g)(2) - that is, noncompliance determined through a stack test dates back to the last
compliant stack test - is inconsistent with general practice regarding reliance on stack testing to
demonstrate compliance with a standard. While mercury stack testing will not be the compliance
method for Dynegy's MPS units complying with the sorbent injection requirement, it
is an
option for any unit that Dynegy may move in to the percent reduction portion
of the rule prior to
2015. Dynegy will move
an MPS unit in to the percent reduction portion of the rule only ifit
expects that the unit can maintain compliance with that portion of the rule. The retrospective
method
of determining compliance proposed by the Agency creates a substantial noncompliance
risk that will likely force Dynegy to rely upon other monitoring methods that are either more
labor intensive or could create monitor data unavailability problems. Thus, Dynegy requests that
-4-
Electronic Filing - Received, Clerk's Office, February 2, 2009
the Board revise this section to provide that noncompliance is prospective - from the
noncompliant stack test to the next compliant stack test.
Using stack test results to determine noncompliance prospectively is standard practice.
For example, a stack test for particulate matter ("PM") determines compliance at the time
of the
stack test and continued operation under the conditions tested are also presumed compliant.
If
the next stack test for PM does not comply, then the unit is out of compliance until a compliant
stack test is performed, not back to the first stack test. Mercury stack testing should be treated no
differently.
A prospective noncompliance policy, initiated at the time
of a failed stack test, would
provide clear and immediate notice to the company
to check for sorbent injection problems.
Since initial mercury stack test results can be provided on the same day the tests are performed,
the company could take prompt action to correct any operations problems and avoid causing
noncompliance with the l2-month rolling average mercury limit. A retrospective approach
would likely sentence a company without any prior notice
to three months or longer of
noncompliance with the mercury limit whenever it failed a stack test.
Another part
of the Agency's proposed rule, Section 225.239(i)(2), would require the
development
of parametrics during stack testing that would be monitored during the period
between stack tests to ensure compliance. The purpose
ofthe parametric monitoring, to ensure
that the unit continues to operate in a manner consistent with its operation during the compliant
stack test, is a reasonable supplement
to periodic mercury stack tests. However, the premise of
parametric monitoring is negated if the regulations then mandate that a subsequent noncompliant
stack test subjects the unit
to noncompliance back to the prior stack test despite compliance with
the parametrics. Indeed, the company would have no notice
of potential noncompliance and no
-5-
chance to change operations or to re-test at an earlier date in order to avoid or shorten the period
of noncompliance. This lack of notice and the risk of incurring substantial penalties for long-
term noncompliance are major flaws in proposed Section 225.239(g)(2) that could preclude
EGUs from ever using this section.
Moreover, retrospective noncompliance
is inconsistent with other parts of the stack
testing provision. The proposed rule provides that stack testing must be performed if there is a
significant change
at a unit between the normal quarterly or semi-annual tests, such as a switch
from bituminous to subbituminous coal. While a noncompliant stack test with the new coal may
indicate a recent problem, there
is no indication of noncompliance back to the date of the
compliant stack test with the prior coal. Assuming noncompliance back to the prior stack test, as
required by the Agency's proposed rule, ignores all other circumstances during the interim
period.
The Agency's proposed approach would create an environment
of uncertainty concerning
the value
of a compliant stack test and how often stack testing should be performed in order for
companies to reduce their exposure to enforcement. Dynegy urges the Board to delete the
retrospective noncompliance elements
of proposed Section 225.239 from the rule.
Flue Gas Temperature Correction Required by Section 225.233(c)(2)
Dynegy understands that the Agency has agreed to amend the methodology for correction
of the
flue
gas temperature so that if there is a difference between the temperature of the stack
and the temperature at the point
of sorbent injection, it will not increase the pounds of sorbent
required
to be injected on an hourly basis. Dynegy supports changes to the Agency's proposal
that will result in a rule with the same intent as the following:
-6-
Electronic Filing - Received, Clerk's Office, February 2, 2009
Section 22S.233(c)(2):
D)
For the purposes
of subsection (c)(2)(C) of this Section, the flue
gas flow rate
IffllSt
may be determined tefat the point of sorbent
injection or; provided that this flow rate
may be assumed to be
identical to the stack flow rate if the gas temperat\H'es at the point
ofinjeetion and the stacie are normally within
IOO°I', or the fllle
gas
flov,' rate may oth_vise lle ealelliated from the staelc flow
rate, eorreeted for the differenee in gas temperatures.
Use
of "Excepted" in Sections 22S.234(a)(4), 22S.238(a)(4), and 22S.239(a)(l), (3), and (4)
Dynegy notes that the Agency has used the word
excepted
in Sections 22S.234(a)(4),
22S.238(a)(4), and 22S.239(a)(l), (3), and (4) and elsewhere in a manner inconsistent with its
dictionary definition. We believe that the intent is that the use
of sorbent traps is an approved
and acceptable means
of monitoring mercury. We request that the Board specifically clarify that
this is the intent
of the use of the word
excepted
or that the word be changed to
accepted.
Mercury Emission Reduction Calculation Procedures
Dynegy has reviewed the Agency's proposed methodology for calculating mercury
emission reductions and suggests that the Board allow for an alternative calculation
methodology, at least for sources using sorbent trap sampling systems. This alternative method
is to demonstrate compliance on a
Ib/TBtu
basis rather than the current mass basis of pounds
mercury in v. pounds mercury out. The equations reflecting this alternative approach and
justifications for these calculations are set forth in Attachment 1 to
my testimony, a
memorandum from Steve Norfleet at RMG Consulting
&
Research, Inc., to Wendell Watson at
Dynegy.
This
Ib/TBtu
approach is simpler than the calculation requirements included in the
Illinois mercury rule and avoids the problems caused
by missing data.
It
is simpler because stack
-7-
Electronic Filing - Received, Clerk's Office, February 2, 2009
flow and coal scale data are not required to perform the calculations, and eliminating those items
also eliminates the bias or error
of those systems from the calculations. Since the
Ib/TBtu
approach is similar to the IblMBtu method used to determining control device removal efficiency
in conjunction with federal New Source Performance Standards, it provides consistency with an
existing USEP A methodology. The addition
of this calculation would provide sources with a
straightforward alternative to determine their mercury removal efficiency.
Conclusion
Dynegy urges the Board to reject any attempt to change the scope of the MPS with a new
definition
of "optimum manner," implemented at least in part through the proposed requirement
in Section 22S.26S(b) that all MPS units sample coal for the express purpose
of using that data as
the sole compliance indicator for MPS units. Dynegy also urges the Board to reject the
Agency's proposed retrospective noncompliance in the new stack testing provisions, Section
22S.239(g)(2). Dynegy requests that the Board amend the provision requiring correction to the
stack flow where the temperature at that point is greater than 100°F difference from the point
of
sorbent injection. Dynegy requests that the Board clarify the meaning of the word
excepted
as
the Agency has applied it to sorbent traps. Finally, Dynegy supports an alternative mercury
emission reduction calculation methodology at least for sources using sorbent trap sampling
systems.
I would
be happy to answer any questions.
.8.
Attachment 1
Electronic Filing - Received, Clerk's Office, February 2, 2009
RMB
Consulting
&
Research, Inc. ______
----:=:--_-:::-:-::::-::-::-::-:-:-:-:-
5104 Bur Oak Circle
Phone: (919) 510-5102
Raleigh, North Carolina 27612
Fax:
(919) 510-5104
To:
From:
Date:
Re:
Technical Memorandnm
Wendell Watson, Dynegy
Steve Norfleet, RMB
January 29, 2009
Mercury Emission Reduction Calculation Procedures
The mercury control requirements within Part 225 of Illinois Administrative Code (lAC) Title 35
allow sources to demonstrate compliance by showing a 90% reduction on 12- month rolling
average basis. However, the rule specifies that the reductions should be calculated based on a
mass basis (pounds
in vs. pounds out), which unnecessarily complicates the determination.
Dynegy should petition the Illinois Pollution Control Board (lPCB)
to
allow it to demonstrate
compliance instead
by calculating the reductions on a
Ib/TBtu
basis. While providing equivalent
results, the
Ib/TBtu
approach is simpler to implement and avoids some of the potential issues
presented by the vacature
of the Part 75 mercury monitoring provisions.
Background Iuformation
Beginning on July 1,2009, Section 225.230 oflAC Title 35 states that existing affected sources
must demonstrate compliance with either an output-based standard
of 0.0080 lb mercury/GWh or
show a minimum 90% removal
of mercury emissions on a rolling 12-month basis. For sources
electing to show compliance with the 90% removal limit, the rule indicates that the emissions
should be calculated using the following formula:
Where:
CE
I,
12
12
CE=IOOx{1-(LE
i
.,.
Ll
i
)}
j=]
i==!
Actual control efficiency for mercury emissions of the EGU for the
particular 12-month rolling period,
expressed as a percent.
Actual mercury emissions
of the EGU, in Ibs, in an individual month in the
12-month rolling period, as determined in accordance with the emissions
monitoring provisions of this Subpart
B.
Amount
~f
mercury in the fuel fired in the EGU, in Ibs, in an individual
month in the 12-month rolling period, as determined in accordance with
Section 225.265 of this Subpart B.
There are, however, a number of issues with implementing this provision. First the D. C. Circuit
Court
of Appeals vacated the clean air mercury rule in its entirety, including the 40 CFR Part 75
mercury monitoring provisions referenced in the Part 225 of the lAC. Not only does the absence
of the Part 75 monitoring requirements create a regulatory void, but these provisions included
procedures that were incompatible with accepted compliance determination fundamentals.
Electronic Filing - Received, Clerk's Office, February 2, 2009
Second, while §225.265 of Subpart B does specifY sampling and analysis for detennining coal
mercury concentrations
in IbfTBtu, it does not indicate how one should convert these
concentration values mass (lb) values. Finally, the procedure
is inconsistent with other emission
removal efficiency calculations, which are generally perfonned on a Ib/mmBtu-basis.
Recommended Approach
In lieu of a mass-based removal efficiency determination, I recommend that reduction be
calculated based the average coal and flue gas
Ib/TBtu
concentrations for the applicable 12-
month rolling period. The equation in Section 225.230(a)(3) could be revised as follows:
Where:
CE
Eavg12
lavgl2
CE=IOOX(I-
~"gI2)
avgl2
Actual control efficiency for mercury emissions of the EGU for the
particular 12-month rolling period,
expressed as a percent.
Average mercury emissions of the EGU, expressed in Ib/TBtu,
fOTthe
12-month rolling period, as determined in accordance with
the
emissions monitoring provisions of this Subpart
B.
Amount of mercury in the fuel fired in the EGU, expressed in
Ib/TBtu,
fOTthe 12-month rolling period, as determined in accordance with
Section 225.265
of this Subpart B.
The preceding equation takes the same fonn as the Equation 19-23 (and Equation 19-12) in
Method 19 of Appendix A in 40 CFR Part 60, which is used to determine control device removal
efficiency based on
Ib/mmBtu
concentrations
I
in conjunction with the federal New Source
Performance Standards (e.g., S02 removal efficiency for utility units under Subpart Da
of Part
60).
The approach
is also mathematically equivalent to the mass-based approach as demonstrated by
the exercise below:
Hg Mass em,,,,o",,)
= 100x (1-
lbl TBtuEm"",om
x
Heat
Input)
= 100 x
(I_
lb
ITBtU
em",,,,,,,)
Hg Mass
coal
lblTBtu
Caal
x
Heat Input
lblTBtu
coal
The total mass of the mercury in the coal and the total flue gas mass emissions are simply a
function
of the concentration (in IbfTBtu) times the heat input (in TBtu). In this expanded fonn,
the heat input in the numerator and the denominator cancel out, leaving only the ratio
of the
IbfTBtu concentrations. The ratio expresses the same underlying relationship but
in a more
direct, basic fonn.
While equivalent, the Ib/TBtuapproach provides significant benefit. Foremost,
it is simpler.
Stack flow and/or coal scale data would be needed to calculate mass values but are not necessary
under the IbfTBtu the approach. Thus, any bias or error (and potential monitor downtime) that
I
While emission rates such as SO::! or NOx are often expressed in
Ib/mmBtu
(or 1 b/l 0
6
Btu), mercury emissions are
often expressed in terms of Ib/TBtu (or Ib/l0
12
Btu) because of the ultralow concentration levels.
2
might have been associated with the introduction in the stack flow or coal scale measurements
has been circumnavigated.
The approach also affords a resolution to the potentially messy issue
of missing data. Every
monitoring system will experience downtime due to periodic maintenance, quality assurance
activities, and unforeseen events/failure.
If one detennines efficiency from mass values, then the
question
of how to fill in the missing periods can be important. The proposed Part 75 mercury
rule included schemes for replacing missing data with conservative values. However, while one
might argue the merits
of this technique for the proposed national mass emission trading
program, missing data substitution has no place in compliance determination under a command
and control requirement.
It
is arbitrary to assess compliance
in
the absence of data based on
made up values. For example, echoing this point, Subpart Da allows the use of Part 75
monitoring data but specifically prohibits the use of Part 75 missing data or bias adjustment
factors.
In contrast, missing data need not be an issue if the IblTBtu approach is used. The average
mercury emissions
(E"g12) can be calculated based on all the available valid hourly emissions data
for the rolling 12-month period. Likewise, the average coal concentration
(l"gI2) can be
calculated based on all the available valid coal data for the rolling 12-month period. Having
some monitor downtime is a fact of life but it does not diminish the use of the remaining data.
For example,
for most existing units under Subpart Da, a 30-day S02 average is deemed
acceptable
as long as there are a minimum of 18 hours in at least 22 of 30 successive boiler
operating days and, for new units, a monthly mercury average
is considered viable as long as the
monitor availability
is 75% or greater. While there may be a fraction of monitor downtime, the
vast majority of hours will be valid. Over a 12-month period, the average concentrations will be
representative and should provide reasonable percent mercury reduction values.
3
Electronic Filing - Received, Clerk's Office, February 2, 2009