Due to clerical error, some copies of the November 2, 2006 second notice order initially
distributed by the Clerk and posted on the Board’s Web site contained an error on page
91.
The main authority note to Part 225 inadvertently contained a reference to Sections 9.10
and 28.5 of the Illinois Environmental Protection Act (415 ILCS 5/9.10 and 28.5). The
main authority note correctly reads as follows: Implementing and authorized by Section
27 of the Environmental Protection Act [415 ILCS 5/27].
This correction is consistent with the source note as it appears in first notice publication
of Part 225 appearing at 30 Ill. Reg. 10193 (June 2, 2006, correcting notice at 30 Ill.
Reg. 9281 (May 19, 2006)) and 30 Ill. Reg. 2706 (July 28, 2006).
ILLINOIS POLLUTION CONTROL BOARD
November 2, 2006
IN THE MATTER OF:
PROPOSED NEW 35 ILL. ADM. CODE 225
CONTROL OF EMISSIONS FROM LARGE
COMBUSTION SOURCES (MERCURY)
)
)
)
)
)
R06-25
(Rulemaking - Air)
Proposed Rule. Second Notice.
OPINION AND ORDER OF THE BOARD (by G.T. Girard, A.S. Moore):
SUMMARY OF TODAY’S ACTION
The Board today proceeds to second notice with a proposal to reduce emissions of
mercury from coal-fired electrical generating units in the State. The Board will submit the
proposal to the Joint Committee on Administrative Rules (JCAR) pursuant to Administrative
Procedure Act (APA) (5 ILCS 100/5
et seq
. (2004)). The proposal the Board adopts today
includes a mercury emissions standard of 0.0080lb/GWh or a 90% reduction from input mercury,
a temporary technology based standard (TTBS), and a multi-pollutant control system (MPS).
The Board has accepted some changes in the proposal while rejecting others. The following will
give a brief overview of today’s opinion and order.
Guide to the Board’s Opinion
The Board’s opinion is divided into several sections beginning with the procedural
background (page 4), a summary of the proposal including the rule language (page 6), a brief
summary of the public comments and a list of some of those who commented (page 19), and a
list of persons who testified (page 21). The substantive portions of the opinion begin with a
summary of the issues (page 22), followed by a discussion of the technical feasibility of the
proposal (page 22). Under technical feasibility, the opinion is divided into four topics: (1)
general comments (page 23); (2) control technology (page 25); (3) measurement of mercury
removal (page 37); and (4) flexibility, which includes discussion of the TTBS and the MPS (page
41).
The next section of the opinion addresses the issue of economic reasonableness (page
54). The economic reasonableness section is also divided into four topics: (1) deposition and
modeling (page 54); (2) health effects (page 63); (3) fish advisories (page 69); and (4) economics
of compliance (page 72). Following economic reasonableness is a section devoted to the legal
issues raised in the comments (page 78). The legal issues raised are grouped as follows: (1)
Illinois and federal administrative law (page 78); (2) Section 27 of the Environmental Protection
Act (Act) (415 ILCS 5/27 (2004) (page 81); (3) Section 10 of the Act (415 ILCS 5/10 (2004)
(page 83); (4) Supremacy and Commerce Clauses of the United States Constitution (page 84);
and (5) Due Process Clause of the United States Constitution (page 87).
2
The final two sections of the opinion address issues surrounding: (1) Kincaid Generation,
L.L.C. (Kincaid) (page 87); and (2) whether the proposal will meet the federal requirements
(page 88). These two sections are followed by the Board’s conclusion (page 90) and the Board’s
order (page 90). At the end of the Board’s order a list of abbreviations and acronyms has been
included for the convenience of the public as an Appendix (page 145).
Summary of the Board’s Decision
The Board has received over 7,000 public comments, held 18 days of hearings, and
entered over 100 exhibits into the record in this proceeding. After carefully reviewing the
entirety of the record, the Board finds that the proposal as amended at second notice is
technically feasible and economically reasonable. Further, the Board finds that the Board’s
authority extends to including the MPS in the proposal for second notice. In making these
determinations the Board examined several issues and those will be summarized in the following
paragraphs.
Technical Feasibility
The Board considered arguments that the proposal’s preferred control technology will not
achieve the standard established in the rule. The Board disagrees and finds that the use of
halogenated activated carbon injection (HCI) has been demonstrated to achieve the established
standards. Further, the Board finds that the size of the specific collection area (SCA) does not
impact mercury reduction with the use of HCI. The Board finds that the duration of the testing
used to demonstrate the feasibility of HCI is sufficient and that an absolute emissions limit is
appropriate.
The Board considered arguments that the measurement of mercury removal cannot be
accomplished to the level required to prove compliance with the standards. The Board notes that
the measurement requirements in the proposal are substantially identical to the measurement
requirements for the Clean Air Mercury Rule (CAMR) developed by the United States
Environmental Protection Agency (USEPA). Many of the issues concerning the measurement
requirements are issues, which relate to the underlying federal requirements; therefore, the Board
defers to the USEPA’s decision to adopt the requirements. In addition, the Board finds that the
testimony offered in opposition to the measurement requirements is not persuasive. Therefore
the Board finds that the measurement of mercury removal can be accomplished to the level
required to prove compliance with the standards.
The Board next considered the issue of flexibility in the proposal, including averaging,
the TTBS, and the MPS option. The Board finds that averaging, both on a systemwide and a 12-
month rolling basis, adds flexibility to the proposal that helps establish technical feasibility of the
proposal. The Board also finds that the TTBS will add flexibility for compliance; and the
addition of the TTBS does not equate with the conclusion that the underlying standard is not
technically feasible. As to the MPS, the Board finds that the MPS offers yet another alternative
for achieving compliance and will result in additional removal of pollutants not regulated in this
proceeding.
3
Economic Reasonableness
In reviewing the economic reasonableness of the proposal, the Board includes arguments
on deposition, modeling, health effects, and fish advisories. The Board does so because the
parties attack the economics of the proposal using these areas. The first issue considered by the
Board is whether the deposition and the modeling of the deposition of mercury support the
emissions standards in the proposal. The Board finds that they do. The Board finds that relying
on studies not specific to Illinois is legitimate and something the Board has done in the past.
Further, the Board finds that the modeling method relied upon by the Illinois Environmental
Protection Agency’s witnesses is an appropriate method and supports the proposal. The Board
finds that the record indicates that lowering emissions of mercury in Illinois will impact the
amount of mercury deposited in Illinois waters. Therefore, the Board finds that the deposition
and modeling evidence in the record support the adoption of the proposed mercury emissions
standards.
The Board next considered arguments concerning whether the reduction of mercury
emissions will result in health benefits to Illinois citizens. The Board finds that the evidence in
the record indicates that health benefits can be expected. Therefore, the Board finds that the
expected health benefits support the adoption of the proposed mercury emissions standards.
The Board considered arguments that reduction of mercury emissions will not impact fish
advisories in Illinois. The Board disagrees and finds that reduction of mercury emissions may
lead to delistings from the Special Mercury Advisory. Therefore, the Board finds that the
potential delistings support the adoption of the proposed mercury emissions standards.
The Board considered arguments that the cost of compliance does not justify the adoption
of the mercury emissions standards. The Board finds that the incremental cost differences
between compliance with CAMR and with the proposal, along with the significant reduction of
mercury emissions, cause this proposal to be economically reasonable. Therefore, the Board
finds that the record supports a finding that the rule is economically reasonable.
Legal Issues
The Board considered arguments challenging the Board’s authority to add the MPS to the
rulemaking at second notice. The Board finds that the MPS is a logical outgrowth of the
proposal and as such is not contrary to either Illinois or federal administrative law. The Board
has found the MPS to be economically reasonable and technically feasible; and therefore, the
addition of the MPS does not violate Section 27 of the Act (415 ILCS 5/27 (2004)). Further the
Board finds that the MPS does not violate Section 10 of the Act (415 ILCS 5/10 (2004)) because
of the voluntary nature of the MPS. The Board also finds that adding the MPS to the rule does
not violate the Supremacy Clause or the Commerce Clause of the United States Constitution.
Finally, the Board finds that the proposal does not violate the Due Process Clause of the United
States Constitution.
Kincaid
4
The Board addressed concerns from Kincaid that due to the utility’s unique nature in
Illinois, the proposal is not technically feasible or economically reasonable for Kincaid. The
Board agrees that Kincaid is uniquely situated and suggests that Kincaid pursue other regulatory
relief.
Federal Requirements
The Board considered arguments that the proposal, with the TTBS and the MPS, will not
be able to meet the requirements established by CAMR. The Board finds that the proposal, with
the TTBS and the MPS, can meet the federal requirements.
PROCEDURAL BACKGROUND
On March 14, 2006, the Illinois Environmental Protection Agency (Agency) filed a
proposal for rulemaking to limit mercury emissions from large coal-fired electrical generating
units (EGU). The proposal was filed pursuant to Sections 9.10, 27, and 28.5 of the Act (415
ILCS 5/9.10, 27, and 28 (2004)). On March 16, 2006, the Board accepted the proposal for first
notice under the “fast-track” rulemaking provisions of Section 28.5 of the Act (415 ILCS 5/28.5
(2004)), without commenting on the merits of the proposal.
On April 20, 2006, the Board ruled, in response to various motions, that the Board has the
authority under Section 28.5 of the Act (415 ILCS 5/28.5 (2004)) to reject a proposal filed by the
Agency pursuant to Section 28.5, if the Board finds that the proposal does not meet the statutory
requirements. The Board further found that the proposal met the statutory requirements of
Section 28.5 of the Act because failure to adopt a mercury emissions standard could result in the
USEPA enforcing the federal CAMR. The Board reasoned that the USEPA enforcing CAMR
would constitute a “sanction” as that term is used in Section 28.5 of the Act (415 ILCS 5/28.5
(2004)).
While the Board was considering the motions to remove the proposal from the fast-track
procedures, Dynegy Midwest Generation, Inc. (Dynegy), Kincaid, and Midwest Generation,
L.L.C. (Midwest Generation) (collectively plaintiffs) filed a complaint in the Sangamon County
Circuit Court on April 3, 2006. That case is Dynegy Midwest Generation, Inc., Kincaid
Generation, L.L.C., and Midwest Generation, L.L.C. v. PCB and IEPA, No 2006-CH-213. In
that complaint, plaintiffs sought declaratory relief from the court that the use of the fast-track
procedures was inappropriate for this rulemaking, that the schedule set by the Board and the
hearing officer could not proceed, and that Section 28.5 was unconstitutional. The plaintiffs also
asked for injunctive relief. On April 17, 2006, the plaintiffs filed a motion seeking a preliminary
injunction against the Board and the Agency. The Sangamon County Circuit Court heard
argument on the motion on April 27, 2006, and entered an order granting a preliminary
injunction on May 1, 2006. On May 8, 2006, after Dynegy and Ameren filed joint statements
with the Board in this rulemaking docket, the Board filed a motion to dismiss the circuit court
case, which is still pending.
On May 4, 2006, the Board decided to proceed with the Agency’s March 14, 2006
proposal pursuant to Section 27 of the Act (415 ILCS 5/27 (2004)). The Board acknowledged
5
the order of the court, and stated the Board’s intent to abide by the court’s decision. The Board
canceled the hearings scheduled to begin on May 8, 2006, and rescinded the schedules set forth
by both the Board and the hearing officer in their respective March 16, 2006 orders. The Board
also re-first noticed the proposed rule under the APA (5 ILCS 100/5
et seq
. (2004)). At the same
time, the Board filed a notice of withdrawal of the original first notice that appeared in the
Illinois Register
on March 31, 2006 (30
Ill. Reg.
5957). The Board cited only Section 27 of the
Act (415 ILCS 5/27 (2004)) as authority for the proposed rule in the new first notice. The new
first notice was published in the
Illinois Register
on May 19, 2006 (30
Ill. Reg.
9281).
On May 23, 2006, the Agency filed a motion to amend the proposal. On June 15, 2006,
the Board accepted the amendment, which was published in the
Illinois Register
on July 28,
2006 (30
Ill. Reg.
12706).
The Board began hearings in this proceeding on June 12, 2006, in Springfield before
Board Hearing Officer Marie Tipsord. The Springfield hearings continued day-to-day through
and including June 23, 2006. After the close of the Springfield hearings, Dynegy and Midwest
Generation filed a motion to strike Dr. Gerald Keeler’s testimony at the Springfield hearing. On
July 20, 2006, the Board denied that motion finding that the rules of evidence in rulemakings
before the Board differ from those in a contested case before the Board. In a rulemaking, “[a]ll
information that is relevant and not repetitious or privileged will be admitted by the hearing
officer.” 35 Ill. Adm. Code 102.426. Thus, the Board found that Dr. Keeler’s testimony was
admissible in this rulemaking proceeding.
The Board began a second set of hearings on August 14, 2006, in Chicago. The Chicago
hearings continued day-to-day through and including August 23, 2006.
1
During the hearing, a
request for additional hearings was made on the record. The hearing officer directed that the
request be filed with the Board and on August 24, 2006, Midwest Generation filed a motion to
schedule additional hearings. By hearing officer order, response time was shortened to allow
responses without undue delay in the proceeding. The Board received responses from Ameren
Energy Generation Company, Amerenenergy Resources Generating Company, and Electric
Energy, Inc. (Ameren), the Agency, and Environmental Law and Policy Center, in opposition to
the motion. Kincaid responded in support of the motion. On September 7, 2006, the Board
denied the request for additional hearings.
In accordance with Section 27(b) of the Act, the Board requested, in letters dated
March 16, 2006 and May 10, 2006, that Department of Commerce and Economic Opportunity
(DCEO) conduct an economic impact study for this rulemaking. On June 26, 2006, DCEO
responded that DCEO does not have the resources to perform economic impact studies on this
rulemaking. The Board received a second response letter on June 29, 2006, which also indicated
that DCEO would not perform an economic impact study. During the Chicago hearings, the
Board specifically sought comment on the decision of DCEO (
see
CTr. at 6-7).
1
The transcript pages for the Springfield hearing are not consecutively numbered and therefore
will be cited with date and a.m. or p.m. The Chicago hearing transcripts will be cited as “CTr.
at”.
6
Pursuant to the hearing officer’s order, the deadline for filing comments to ensure that the
comments were considered by the Board before proceeding was September 20, 2006. Between
the close of hearing and September 20, 2006, the Board received 7286 comments that will be
discussed below. Also on September 20, 2006, Midwest Generation filed a motion to correct
transcript. The Board did not receive any responses to the motion. The Board grants that
motion.
On September 25, 2006, Ameren filed a motion for leave to file
instanter
supplemental
post-hearing comments. The Board did not receive any responses to the motion. The Board
grants that motion and accepts the comment.
PROPOSAL
The following section of this opinion will summarize the Agency’s reasons for
submitting this proposal. Next, the Board will summarize the proposed rule language and the
justification provided in the proposal for the suggested language. The proposal filed by the
Agency includes a statement of reasons (Reasons) that describes the Agency’s reasons for
submitting the proposal. The proposal also includes a technical support document (TSD) which
includes technical information supporting the rulemaking proposal. Both items will be referred
to as necessary to summarize the Agency’s proposed rule language.
General Reasons for Proposal
The Agency indicates that the rulemaking is intended to meet certain obligations of the
State of Illinois under the federal Clean Air Act (CAA) (42 U.S.C. § 7401
et seq
.). Reasons at 1.
The Agency states that the proposal is brought to satisfy the State’s obligation to submit a state
implementation plan (SIP) to address the requirements of USEPA’s CAMR (
see
70 Fed. Reg.
28606 (May 18, 2005)) and Section 9.10 of the Act.
Id
., citing 415 ILCS 5/9/10 (2004). The
Agency explains that while the proposed rule is consistent with CAMR, the proposal addresses
serious deficiencies present in the CAMR including:
the unnecessary delay in achieving mercury emissions reductions, the inherent
concerns associated with a cap and trade program to control a persistent,
bioaccumulative toxin, the inadequate mercury reductions contained in the
CAMR, and the legal basis upon which CAMR was adopted. Reasons at 1.
Concerns About Mercury
Mercury is a naturally occurring trace element found in the environment as well as a
pollutant released to the environment by human or anthropogenic activities. Reasons at 2.
Mercury is a persistent environmental contaminant, which cannot be degraded or destroyed.
TSD at 29. Mercury exists in two general forms in the environment: inorganic, which include
elemental mercury, and organic forms.
Id
. Mercury combines with carbon to form compounds
referred to as organic mercury. Inorganic mercury compounds are formed when mercury
combines with other non-carbon elements such as chlorine, sulfur and oxygen.
Id.
7
Natural sources of mercury include outgassing from volcanoes and evaporation from
natural bodies of water. Regarding the anthropogenic sources, mercury emissions from
combustion of fossil fuel such as coal-fired EGU represent the largest source category of
mercury emissions in the United States. Reasons at 2; TSD at 31. USEPA estimated that coal-
fired EGUs contribute about 34% of the total man-made mercury emissions. Emissions of
mercury occur in three forms: elemental (Hg
0
), gas phase divalent (Hg
2+
) (reactive gaseous
mercury) and particulate-bound divalent mercury (Hg
p
).
Id
. According to the Agency, reactive
and particulate forms of mercury compounds have the greatest impact on near-field deposition of
mercury. Reasons at 2. These forms of mercury are water-soluble and are generally more
readily deposited to the earth’s surface through wet or dry deposition. TSD at 29.
While the various forms of mercury are known to induce toxic responses in the human
body, ingestion of methylmercury through fish consumption poses the greatest exposure risk to
human beings. TSD at 37. The Agency states that the deposition of mercury on the land and
into waters is the serious health concern. Reasons at 2. The Agency maintains that nearly 50%
of the mercury entering many bodies of water comes from air deposition and once in the water
some mercury transforms to methylmercury.
Id
. Methylmercury is formed by biological process
and is a highly toxic form of mercury. Methylmercury is the form of mercury that is a concern
for potential health effects from mercury. Reasons at 3.
Methylmercury can be ingested by the lower trophic level organisms where the mercury
can bioaccumulate in fish tissue. Reasons at 3. Concentrations of methylmercury in predatory
fish then build up over the fish’s entire lifetime, accumulating in the fish tissues as the predatory
fish consume other species in the food chain.
Id
. Therefore, fish and wildlife at the top of the
food chain can have higher concentrations of mercury than the lower organisms.
Id
. Thus, the
most common exposure of mercury for humans is through consumption of mercury contained in
the food supply.
Id
.
The Agency notes that when humans consume fish containing methylmercury, the
methylmercury is absorbed into the blood and distributed throughout the tissues of the body.
Reasons at 3. Methylmercury can be passed to a fetus in pregnant women and sufficient
exposure may lead to neurological effects on the unborn child.
Id
. The effect of prenatal
exposure can occur even if the exposure does not affect the mother.
Id
. As a result of exposure
to methylmercury children may be at an increased risk of poor performance on neurobehavioral
tests such as those measuring attention, fine motor function, language skills, visual-spatial
abilities, and verbal memory.
Id
. Mercury contamination of Illinois waters has resulted in fish
consumption advisories being issued for every body of water in the State, according to the
Agency. Reasons at 3.
Clean Air Act and CAMR
Under Section 112(b) (42 U.S.C. § 7412(b)) of the CAA, mercury is listed as a hazardous
air pollutant (HAP). Reasons at 4. Section 112 of the CAA requires the establishment of
maximum achievable control technology (MACT) standards applicable to new and existing
sources.
Id
. The CAA required the USEPA to conduct a study of electric utility boilers to assess
the hazards to public health from emissions of HAPs.
Id
. Pursuant to Section 112(n)(1)(A) of
8
the CAA (42 U.S.C. § 7412(n)(1)(A)), USEPA found that regulation of coal and oil-fired utility
boilers was necessary and appropriate. Reasons at 4.
In January 2004, USEPA proposed federal rules governing the emissions of mercury
from coal-fired electric generating units. Reasons at 6-7. In response to the federal proposal, the
Agency submitted comments that took issue with the federal rules. Reasons at 7-8. The Agency
challenged USEPA’s regulation under Section 111 of the CAA rather than Section 112(d) of the
CAA. Reasons at 8. The Agency argued that the mercury limits must be more stringent than
those proposed and that the rule should be fuel neutral without favoring one type of coal.
Id
.
The Agency also opposed trading of mercury allowances and argued for reductions to occur by
2010. Reasons at 8-9. USEPA adopted CAMR on May 18, 2005, and did not make changes to
address the Agency’s concerns. Reasons at 9.
The Agency takes issue with CAMR for several reasons. Reasons at 10. The Agency
does not believe that CAMR would result in sufficient reductions of mercury in a timely manner.
Id
. The Agency also is concerned that CAMR will impede efforts to encourage clean-coal
technology that will allow use of Illinois coal.
Id
. The Agency, because of these concerns,
asked the Illinois Attorney General’s Office to appeal CAMR and that appeal was filed on
May 27, 2006. Reasons at 11. Thirteen other states have also filed one or more appeals of
CAMR. Illinois’ appeal was consolidated with other challenges. Reasons at 11, citing Illinois v.
USEPA, Nos. 05-1174 and 05-1189 (D.C.Cir.).
Under CAMR, the USEPA established a cap and trade program to reduce nationwide
coal-fired power plant emissions of mercury in two phases. Reasons at 23, citing 70 Fed. Reg.
28619. The first phase is effective in 2010 and is set at 38 tons per year.
Id
., at 70 Fed. Reg.
28606. The second phase, effective in 2018, sets the emissions rate at 15 tons per year.
Id
.
CAMR’s market based cap and trade program distributes mercury allowances that equate to
emissions of one ounce of mercury.
Id
. CAMR also allows for banking of mercury allowances.
Reasons at 23.
CAMR established an annual mercury budget for each state beginning in 2010. Reasons
at 23, citing 70 Fed. Reg. 28649-50. Each state’s plan under CAMR must include emissions
control requirements and compliance procedures to demonstrate that the state’s annual budget
will be met.
Id
. CAMR establishes Illinois’ annual budget as 1.594 tons per year for the period
2010 through 2017, and 0.629 tons per year for the period 2018 and thereafter. Reasons at 24,
citing 70 Fed. Reg. 28649-50. CAMR’s 2018 national cap of 15 tons per year equates to
approximately a 70% reduction in mercury emissions from the 1999 baseline year. Reasons at
24.
Section 9.10 of the Act
The Illinois General Assembly also saw a need for examination of mercury emissions,
and therefore, added Section 9.10 to the Act (415 ILCS 5/9.10 (2004)). Reasons at 5. Section
9.10 of the Act required the Agency to report to the General Assembly findings “that address the
potential need for the control or reduction of emissions from fossil fuel-fired electric generating
plants.” 415 ILCS 5/9.10(b) (2004); Reasons at 5. In Section 9.10 of the Act, the General
9
Assembly specified several areas for the Agency to address including the “reduction of mercury
as appropriate . . . that are sufficient to prevent unacceptable local impacts from individual
facilities” with consideration of developments in federal law that may affect action by Illinois.
Id
.
The Agency published a report entitled
Fossil Fuel-Fired Power Plants: Report to the
House and Senate Environment and Energy Committees
in September 2004 (Section 9.10
Report). Reasons at 6. The Section 9.10 Report indicated that control of mercury emissions was
necessary, but did not specify a level of control.
Id
. The Agency stated its belief that
independent, full and complete economic assessments should be performed on a mercury
reduction rule to examine the impact to Illinois jobs in the coal and power industry.
Id
.
Purpose and Effect of Agency’s Proposal
The Agency proposed this rulemaking to satisfy Illinois’ obligation to submit a SIP
addressing the requirements of CAMR and to address applicable requirements of Section 9.10 of
the Act (415 ILCS 5/9.10(2004)). Reasons at 23. The Agency seeks to achieve maximum
mercury reductions while providing flexibility. Reasons at 24. To do this, the Agency proposes
to phase in compliance, include provisions to allow compliance to be demonstrated by averaging
systemwide and plant wide, and to allow for relief for EGUs that will be shut down.
Id
.
Specifically, the proposal requires EGUs that serve a generator greater than 25 megawatts
producing electricity for sale to begin utilizing control technology by July 1, 2009. Reasons at
24. The proposal allows compliance to be demonstrated by either using a mercury emissions
standard of 0.0080lb/GWh or a 90% reduction from input mercury.
Id
. The standards apply on a
rolling 12-month average basis and compliance can be shown on a source-wide basis. Reasons
at 24-25. Companies with several sources may meet these standards by averaging between the
sources as long as each source attains at least a 75% reduction. Reasons at 25. The emissions
standards do not apply if an existing EGU plans to permanently shut down by 2010.
Id
.
CAMR requires monitoring of mercury emissions, so the proposal includes requirements
for monitoring. Reasons at 26. The monitoring requirements specify that units must comply
with the federal CAMR monitoring requirements of 40 C.F.R. 75.
Temporary Technology Based Standard
On June 15, 2006, the Board granted a motion to amend the proposal to include a TTBS.
A source may use the TTBS to demonstrate compliance with the proposed standards if the EGUs
are equipped and operated with control systems which include HCI and either a cold side
electrostatic precipitator (ESP) or a fabric filter. Proposed Section 225.234(b). The TTBS is
limited to only 25% of the total rated MW capacity for the owner or operators of more than one
EGU. Proposed Section 225.234(b)(3).
Multi-Pollutant Standards
10
Although not a part of the Agency’s proposal, the Board will discuss the MPS here for
organizational purposes. On July 28, 2006, Ameren and the Agency filed a joint statement
asking that the Board include a multi-pollutant standard in the proposed rule.
See
Exh. 75. At
hearing, Ameren testified concerning the proposed language and the Agency joined Ameren in
answering questions about the MPS language.
See
CTr. 1-442. On August 21, 2006, Dynegy
and the Agency also filed a joint statement with Dynegy joining in supporting the MPS and
suggesting changes to the MPS.
See
PC 6283, CTr. at 1341-43. A corrected copy of the
language was filed on August 23, 2006. PC 6284.
The MPS is a voluntary provision that allows Illinois units to comply with mercury
reductions using co-benefits from SO
2
and NO
x
emissions reductions. PC 6301 at 4. A source
must commit to reducing SO
2
and NO
x
emissions and, in exchange, the source has additional
time to achieve the mercury emissions standard of 0.0080 lb/GWh or 90% reduction of mercury.
Exh. 75 at 1-2, PC 6301 at 4, PC 6284 at 2-3. The MPS requires that SO
2
and NO
x
allowances
necessary to meet the requirements of the MPS be surrendered to the Agency for retirement.
Exh. 75 at 2, PC 6284 at App.A, 10. The MPS requires specific reductions of SO
2
and NO
x
emissions rates and imposes deadlines for installation of HCI controls. Exh. 75 at 1, PC 6284 at
2-3.
Ameren and the Agency anticipate that installing and operating pollution control
equipment pursuant to the MPS will achieve significant reductions of SO
2
and NO
x
emissions
beyond those required by existing regulations and beyond the federal Clean Air Interstate Rule
(CAIR). Exh. 75 at 2. Ameren and the Agency state that the MPS is both technically feasible
and economically reasonable and that the level of SO
2
and NO
x
emissions reductions will
contribute to Illinois’ efforts to achieve attainment of National Ambient Air Quality Standards
(NAAQS). Exh. 75 at 3. Ameren also testified to the technical feasibility and economic
reasonableness of the MPS.
See
,
e.g.
, CTr. at 248-50, 307.
Dynegy’s joint statement with the Agency echoes the comments concerning the reduction
of SO
2
and NO
x
emissions made by the Ameren and the Agency in their joint statement. PC
6284 at 4. Dynegy and the Agency also indicate that the revised proposal is economically
reasonable and technically feasible. PC 6284 at 5. Ameren supports the revised MPS
amendments filed by Dynegy and the Agency. PC 6301 at 6.
Rule Language
The following section summarizes the actual rule language of the proposal.
Section 225.100.
This is the standard severability clause in the rule. The Section
provides that if any section, subsection or clause of Part 225 is found to be invalid, the validity of
Part 225 as a whole will not be affected. Reasons at 29.
Section 225.120 and 225.130
.
In these sections the Agency sets forth abbreviations,
acronyms, and definitions used in Part 225. Reasons at 29
.
The Agency also incorporates
definitions found in 35 Ill. Adm. Code 211.
Id
.
11
Section 225.140.
Part 225 incorporates several sections of the
Code of Federal
Regulations
by reference. Reasons at 30. Specifically, this section incorporates 40 C.F.R. 60.17,
60.45a, 60.49a(k)(l) and (p), 60.4170 through 60.4176.
Id
. These sections of 40 C.F.R. Part 60
address Standards of Performance for New Stationary Sources.
Id
. Subsection (b) incorporates
by reference 40 C.F.R. Part 75.
Id
. Under CAMR, state plans must require that EGUs comply
with the monitoring, recordkeeping, and reporting provisions of 40 C.F.R. Part 75, which
addresses continuous emission monitoring.
Id
. Subsection (c) incorporates by reference
standard test methods that are to be utilized under Part 225.
Id
.
Section 225.200.
Subpart B of Part 225 is proposed to control mercury emissions from
coal-fired electric generating units in Illinois. Reasons at 30.
Section 225.202
.
This section sets forth the measurement methods for mercury under
Part 225. Reasons at 30.
Section 225.205.
Subsection (a) provides that Subpart B applies to all stationary coal-
fired boilers and stationary coal-fired combustion turbines serving a generator with nameplate
capacity of more than 25 MWe and producing electricity for sale. Reasons at 31.
Subsection (b) includes language that determines when Subpart B applies to a
cogeneration unit. Specifically, Subpart B applies to a cogeneration unit serving at any time a
generator with nameplate capacity of more than 25 MWe and supplying in any calendar year
more than one-third of the unit’s potential electric output capacity or 219,000 MWh, whichever
is greater, to any utility power distribution system for sale. Reasons at 31. The proposed
language provides that “if a unit qualifies as a cogeneration unit during the 12-month period
starting on the date the unit first produces electricity, but subsequently no longer qualifies as a
cogeneration unit, the unit shall be subject to subsection (a) of this Section starting on the day
which the unit first no longer qualifies as a cogeneration unit.”
Id
.
Section 225.210.
This section requires that to be in compliance with Subpart B an owner
or operator of a source with one or more EGUs must apply for a Clean Air Act Permit Program
(CAAPP) permit that addresses the applicable requirements of Subpart B. Reasons at 31
.
Subsection (b) specifically requires the owner or operator to comply with the monitoring
requirements of Section 225.240 through 225.290 of Subpart B.
Id
. The Agency proposes that
emissions measurements recorded and reported in accordance with Section 225.240 through
225.290 of Subpart B will determine compliance with mercury requirements under Section
225.230 or 225.237. Reasons at 31-32. Subsection (c) requires compliance with the mercury
emissions reduction requirements set forth under Section 225.230 or 225.237. Reasons at 32.
Subsection (d) sets forth the recordkeeping and reporting requirements for owners or operators of
EGUs under Subpart B.
Id
. The owners or operators must keep the following records: emission
monitoring information, copies of all reports, compliance certifications, all documents necessary
to demonstrate compliance with Subpart B, copies of all documents from the permit application
and any other submission under Subpart B.
Id
. The owner or operator must keep the records for
five years, unless the Agency extends this period for cause in writing prior to the end of five
years.
Id
.
12
Subsection (e) governs liability and sets forth that the owner or operator of each source
must meet the requirements of Subpart B and that any provision of Subpart B that applies to a
source will also apply to the owner and operator of the source and to the owner and operator of
each EGU at the source. Reasons at 32. Subsection (f) includes language that limits the effect of
Subpart B on other authorities.
Id
. The Agency provides that no provision of Subpart B can be
construed to exempt or exclude the owner and operator of a source or EGU from compliance
with any provision of an approved State Implementation Plan, a permit, the Act or the CAA.
Id.
Section 225.220.
This section addresses CAAPP permit requirements and provides in
subsection (a) that each source submit a CAAPP permit application that addresses all applicable
requirements of this Subpart. Reasons at 33. Subsection (a) also establishes a timeline for the
submission of permit applications.
Id.
In subsections (b) and (c), the content and information
required in the permit application and permit are set forth.
Id.
The proposed language in
subsection (c) requires that each permit issued by the Agency and subject to Subpart B address
all applicable requirements of this Subpart and contain federally enforceable conditions.
Id
.
Section 225.230.
This section sets forth emissions standards for EGUs at existing
sources. Reasons at 33. Subsection (a) provides that beginning July 1, 2009, the EGU must
comply with one of the following standards on a rolling 12-month basis: “(1) an emission
standard of 0.0080 lb/GWh gross electrical output; or (2) a minimum 90% reduction of input
mercury.”
Id
. Subsection (b) provides that as an alternative to compliance with subsection (a)
an EGU may demonstrate that the actual emissions of mercury are less than the allowable
emissions from the EGU on a rolling 12-month basis.
Id
. Subsection (b) also includes the
equations necessary for compliance and provides that if an EGU does not comply with Section
225.265 of this Subpart to determine mercury input, the allowable emissions will be calculated
based on the electrical output of the EGU. Proposed Section 225.230(b).
Subsection (c) provides that for two EGUs that share a common stack, and where
mercury monitors are in the common stack, compliance with applicable emission standards must
be determined as if the two EGUs were a single EGU, as provided for by 40 C.F.R. Part 75,
Subpart I. Reasons at 34. Subsection (d) requires that a source with multiple EGUs may
alternatively comply with subsection (a) by demonstrating that the actual emissions of mercury
are less than the allowable emissions of mercury from all EGUs at the source on a rolling 12-
month basis. Proposed Section 225.230(c). Subsection (d) provides formulas for determining
the maximum allowable emissions of mercury from all the EGUs at a source.
Id
. If a source that
relies on subsection (d) fails to meet the requirements of subsection (d) in a given 12-month
period, all EGUs at the source in such reliance will be considered out of compliance with the
applicable standards of Subpart B for the entire last month of that period. Reasons at 33-34.
Section 225.232.
Subsection (a) provides that through December 31, 2014, as an
alternative to compliance with Section 225.230(a), an EGU may comply with emissions
standards through an averaging demonstration. Reasons at 34-35. The EGU must show that
actual mercury emissions from the EGU and other EGUs covered by the demonstration are less
than the allowable emissions from all such EGUs on a rolling 12-month basis.
Id
.
13
Subsection (b) proposes that each EGU covered by the demonstration must “comply with
one of the following emission standards on a source-wide basis for the period covered by the
demonstration: (1) An emission standard of 0.020 lb/GWh gross electrical output; or (2) A
minimum 75% reduction of input mercury.” Reasons at 35. Subsection (c) provides that the
equations set forth in Section 225.230(a)(2), (a)(3), or (d) (2) determine compliance with
emissions standards under this section. Reasons at 35. The owner or operator must apply the
equations that address all EGUs at the sources covered by the demonstration, rather than the
equations that address only EGUs at one source.
Id
.
Subsection (d) provides that owners or operators of multiple existing sources with EGUs
may only participate in averaging demonstrations with existing sources they own or operate.
Reasons at 35. However, the owners or operators of specifically enumerated single sources with
EGUs may participate in demonstrations with each other.
Id
. The proposed language requires
that participants that are single existing sources with EGUs be authorized through federally
enforceable permit conditions for each participating source.
Id
. Under subsection (e), “a source
may be included in only one [d]emonstration during each rolling 12-month period.”
Id
.
Subsection (f) requires that EGUs using the demonstration to comply with “Subpart B must
complete the determination of compliance for each 12-month rolling period no later than 60 days
following the end of the period.” Reasons at 36.
Subsection (g) provides that if a source applies the demonstration to comply with Subpart
B and fails, the compliance status of such source will be determined under Section 225.230, as if
the demonstration did not apply. Reasons at 36. Subsection (h) includes that if one source of
two participating in a demonstration does not maintain the required records, data, and reports for
the EGUs at the source or does not submit copies of such documents to the Agency upon request,
this will be deemed a failure to demonstrate compliance and both participating sources will be
subject to Section 225.230 to determine compliance.
Id.
Section 225.235.
Section 225.235(a) provides that the standards do not apply to an EGU
that will be permanently shut down. Reasons at 36. To comply with this section, an owner or
operator who will not be constructing a new EGU to replace the existing unit must notify the
Agency no later than June 30, 2009, that it is planning to permanently shut down by December
31, 2010.
Id
. Otherwise, if the owner or operator plans to construct a new EGU to specifically
replace the existing unit, the existing unit must shut down by December 31, 2011, for this section
to apply.
Id
. The existing EGU must be permanently shut down by the specified dates, unless
the owner or operator demonstrates to the Agency, prior to such date, that factors beyond the
owner or operator’s reasonable control have interfered with the shut down plan, in which case an
extension may be given. Proposed Section 225.235(a). In these circumstances, an operator or
owner that will not replace the existing EGU may receive an extension requiring the permanent
shut down of the unit by December 31, 2011.
Id
. If the owner or operator of an existing EGU is
constructing a new EGU, the deadline for permanent shut down of the existing EGU may be
extended to June 30, 2013, so long as after December 31, 2012, the existing EGU only operates
as a “back-up unit to address periods when the new generating units are not in service.”
Id
.
Along with the notification, the EGU must submit a description of actions that have been
taken to shut down the EGU and a description of actions that will be taken to complete the shut
14
down. Prop. Section 225.235(a). To rely on this section, an owner or operator must have
applied for a construction permit or be pursuing a federally enforceable agreement that requires
the permanent shut down of the EGU, and by June 30, 2009, must have applied for revisions to
the operating permit that terminate the authorization to operate the unit.
Id
. To rely on this
section, an owner or operator must have obtained a construction permit or have entered into a
federally enforceable agreement and obtained revised operating permits in accordance with this
section, by June 30, 2010.
Id
.
Subsection (b) provides that any EGU not required to comply with Section 225.230
pursuant to this section, “shall not be included when determining whether any other EGUs at the
source or other sources are in compliance with Section 225.230 of this Subpart.” Prop. Section
225.235(b).
Subsection (c) provides that if an owner or operator relies on this section in lieu of
compliance with Section 225.230(a) and fails to permanently shut down by the required date, the
EGU will be considered a new EGU and therefore subject to the emissions standards in Section
225.237(a) of Subpart B. Reasons at 38.
Section 225.237.
Subsection (a)(1) provides that a source that has not commenced
commercial operations before January 1, 2009, is a new source and must “comply with one of
the following emissions standards for each EGU on a rolling 12-month basis: (1) An emission
standard of 0.0080 lbs/GWh gross electrical output; or (2) A minimum 90% reduction of input
mercury.” Reasons at 38. Subsection (a)(2) allows that the equations in Section 225.230(a)(2),
(a)(3), or (b)(2) of Subpart B may be used to demonstrate compliance.
Id
.
Subsection (b) provides that the commencement date of the initial 12-month rolling
period for which a new EGU must comply with subsection (a)(1) of this Section is the same date
that the initial performance test for the mercury emissions standard under 40 C.F.R. 60.45
commences. Reasons at 38. The required continuous emissions monitoring system for mercury
emissions must be certified prior to this date.
Id
. “Thereafter, compliance shall be demonstrated
on a rolling-12-month basis in terms of calendar months.”
Id
.
Section 225.240.
This section requires that an EGU must comply with monitoring,
recordkeeping and reporting requirements in this section and those of Sections 225.250 through
225.290 of Subpart B and Subpart I of 40 C.F.R. Part 75. Reasons at 39. If an EGU shares a
common stack with units that are not EGUs and emissions are not monitored in the duct to the
common stack from each EGU then emissions monitoring must comply with 40 C.F.R.
75.82(b)(2) and this Section, “including monitoring the duct to the common stack from each unit
that is not an EGU.”
Id
. However, if the EGU counts the combined emissions measured at the
common stack as the mass emissions of mercury, for the EGU’s recordkeeping and compliance
purposes, then the aforementioned measures for EGUs that share a common stack with units that
are not EGUs are not required.
Id
.
In subsection (a), the Agency sets forth requirements for installation, certification and
data accounting. This subsection requires the owner or operator to install all required monitoring
systems and successfully complete all required certification tests, in accordance with this Section
15
and Sections 225.250 through 225.290 of Subpart B and 40 C.F.R. 75.21 and 75.82, and record,
report, and quality-assure the data from such monitoring systems. Reasons at 39.
Subsection (a)(4) provides that to qualify to use the low mass emissions excepted
monitoring methodology, the EGU must meet the requirements set forth in this subsection, and
demonstrate eligibility through initial emissions testing, which must be conducted before the
dates set forth in subsections 225.240(a)(4)(A) and (B). Proposed Section 225.240(a). For an
EGU to be eligible to use the excepted emissions monitoring methodology, the EGU may not
emit more than 464 ounces (29 pounds) of mercury per year pursuant to 40 C.F.R. 75.81(b),
must demonstrate that the EGU is eligible to use the methodology by performing emissions
testing in accordance with 40 C.F.R. 75.81(c), must comply with other applicable requirements
of 40 C.F.R. 75.81(b) through (f), and must submit to the Agency a copy of any information that
is required to be submitted to the USEPA under these provisions.
Id
.
Subsection (a)(4) requires that if an EGU commenced commercial operations before
July 1, 2008, initial emissions testing, to demonstrate eligibility of an EGU for the low mass
emissions excepted methodology, must be conducted before “January 1, 2009, or 45 days prior
to relying on the low mass emissions excepted methodology, whichever date is later.” Proposed
Section 225.240(a). If the EGU commenced commercial operation on or after July 1, 2008,
initial emissions testing shall be conducted “at least 45 days prior to the applicable date specified
under subsection (b)(2) of this Section or 45 days prior to relying on the low mass emissions
methodology, whichever date is later.”
Id
.
Subsection (b) requires EGU to 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 dates specified in subsections (b)(1) (2) and (3). Proposed Section 225.240(b). The
owner or operator must record, report, and quality-assure the emissions monitoring systems
required under subsection (a)(1) of this Section on and after the specified dates.
Id
. Under
subsection (b)(1) an EGU that commences commercial operation before July 1, 2008, is required
to comply with emissions monitoring certification on or before January 1, 2009.
Id.
Subsection
(b)(2) provides that an EGU that commences commercial operation after July 1, 2008, is required
to comply with monitoring system certification by 90 unit operating days or 180 calendar days
after commercial operations commence, whichever occurs first.
Id
.
Subsection (b)(3) proposes that an EGU that completes construction of a “new stack or
flue or installation of add-on mercury emissions controls, a flue gas desulfurization system
(FGD), a selective catalytic reduction system, a fabric filter, or a compact hybrid particulate
collector system is complete after the applicable” deadline is required to recertify the continuous
emissions monitoring system within 90 unit operating days or 180 calendar days after the date on
which emissions first exit the new system, stack, flue, device or filter, whichever is first.
Reasons at 39.
Subsection (c) requires that if an EGU does not meet the applicable deadline for
certification of any required emissions monitoring system, the owner or operator is required to
determine, record, and report maximum potential values and, where appropriate, minimum
potential values for mercury concentration, stack gas flow rate, stack gas moisture content, and
16
any other parameters required to determine mercury mass emissions in keeping with 40 C.F.R.
75.80(g) for each system. Proposed Section 225.240(c). Under subsection (c)(2) if an EGU that
is required to be recertified pursuant to subsection (b)(3) of this Section fails to meet the deadline
for recertification of any emissions monitoring system, the owner or operator is required to, “for
each such system, determine, record, and report substitute data using the applicable missing data
procedures in 40 C.F.R. 75.80(f), in lieu of the maximum potential (or, as appropriate, minimum
potential) values, for a parameter if the owner or operator demonstrates that there is a continuity
between the data streams for that parameter before and after the construction or installation under
subsection (b)(3) of this Section.”
Id
.
Subsection (d) provides that an EGU may not use “any alternative emissions monitoring
system, alternative reference method for measuring emission, or any other alternative to the
emissions monitoring and measurement requirements of this Section and Sections 225.250
through 225.290 of this Subpart,” unless the USEPA promulgates the alternative and the Agency
approves it in writing or if such alternative is approved in writing by the Agency and the
USEPA. Reasons at 41.
Subsection (d)(3) provides that an owner or operator may not disrupt “the continuous
emission monitoring system, any portion thereof, or any other approved emission monitoring
method, and thereby avoid monitoring and recording mercury mass emissions discharged into
the atmosphere, except for periods of recertification or periods when calibration, quality
assurance testing, or maintenance is performed in accordance with the applicable provisions of
this Section, Sections 225.250 through 225.290 of this Subpart, and Subpart I of 40 C.F.R. Part
75.” Proposed Section 225.240(d). Under subsection (d)(4), an EGU must not discharge
mercury emissions without accounting for all such emissions pursuant to “applicable provisions
of this Section, Section 225.250 through 225.290 and Subpart 1 of 40 C.F.R. Part 75.”
Id
. An
EGU must not retire or permanently discontinue use of the continuous emissions monitoring
system or a component thereof, other than in the limited circumstances enumerated in this
subsection.
Id
.
Subsection (e) provides that an EGU in long-term cold storage must comply with
applicable provisions of 40 C.F.R. Part 75 for monitoring, recordkeeping, and reporting for such
units. Reasons at 42.
Section 225.250.
Subsection (a) includes provisions for initial certification and
recertification procedures for a continuous emissions monitoring system or excepted monitoring
system (sorbent trap monitoring system) under 40 C.F.R. 75.15. Reasons at 42.
Subsection (b) proposes that a monitoring system will be exempt from the initial
certification requirements of this Section if the following provisions are met: the monitoring
system has been previously certified pursuant to 40 C.F.R. Part 75, and “the applicable quality
assurance and quality control requirements of 40 C.F.R. 75.21 and Appendix B to 40 C.F.R. Part
75 are fully met.” Reasons at 42. However, a monitoring system required by section 225.240
that is exempt from initial certification requirements must never-the-less comply with the
recertification provisions of this section.
Id
.
17
Subsection (c) sets forth that the applicable certification and recertification requirements
in 40 C.F.R. 75.81(c) through (f) will apply to an EGU qualified to use the mercury low mass
emissions excepted methodology under 40 C.F.R. 75.81(b). Reasons at 43.
Under subsection (d), within 45 days of completing all initial certification and
recertification tests required under this section, the owner or operator is required to submit an
application to the Agency including the information required by 40 C.F.R. 75.63.
Id
.
Section 225.260.
Subsection (a) provides that the missing data procedures in Subparts D
and I of 40 C.F.R. Part 75, where applicable, will be applied to substitute data whenever any
emissions monitoring system fails to meet quality assurance and quality control requirements or
data validation requirements of 40 C.F.R. Part 75. Reasons at 43.
Subsection (b) sets forth that the Agency will issue a notice of disapproval of the
certification status of a monitoring system if an audit and review of the initial certification or
recertification reveal that such monitoring system should not have been certified or recertified
because of the following reasons. Reasons at 43. The Agency will issue such notice of
disapproval if both at the time of initial certification or recertification application and submission
and at the time of the audit the monitoring system did not meet a particular performance
specification or failed to meet other requirements under Section 225.250 of Subpart B or failed to
meet applicable provisions of 40 C.F.R. Part 75.
Id
. Such notice of disapproval acts to revoke
prospectively the certification status of the monitoring system.
Id
. The initial certification and
recertification procedures in Section 225.250 apply to each disapproved monitoring system.
Id
.
Section 225.261.
This section provides that an EGU that uses a mercury concentration
monitoring system and a flow monitoring system to monitor and report, will also monitor and
report heat input rate at the EGU level using the procedures set forth in 40 C.F.R. Part 75.
Reasons at 44.
Section 225.263.
Under this Section, if an EGU complies with this Subpart, by means of
either Section 225.230(a)(1) or 225.230(b) or (d) or 225.232, the owner or operator “shall
monitor gross electrical output of the associated generator(s) in MWh on an hourly basis.”
Proposed Section 225.263.
Section 225.265.
If the EGU complies by means of Section 225.230(a)(2) or uses input
mercury levels and complies by means of Section 225.230(b) or (d) or Section 225.232, the
owner or operator must “[p]erform daily sampling of the coal combusted in the EGU for mercury
content.” Proposed Section 225.265. The owner or operator “shall collect a minimum of one 2-
lb. grab sample per day of operation from the belt feeders anywhere between the crusher house
or breaker building and the boiler.”
Id
. The sample should be taken in a manner so that it will
be representative of the mercury content of coal burned that day. Prop at 44. The owner or
operator is required to analyze the grab sample using the following tests: to determine heat
content, “ASTM D5865-04, Standard Test Method for Gross Calorific Value of Coal and Coke,
or equivalent approved in writing by the Agency”; to determine moisture content, “ASTM
D3173-03, Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, or
equivalent approved in writing by the Agency”; and to measure the mercury content, “ASTM
18
D6414-01, Standard Test Method for Total Mercury in Coal and Coal Combustion Residues by
Acid Extractor or Wet Oxidation/Cold Vapor Atomic Absorption, ASTM D3684-01, Standard
Test Method for Total Mercury in Coal by the Oxygen Bomb Combustion/Atomic Absorption
Method, or equivalent approved in writing by the Agency”. Reasons at 44-45.
A source with multiple EGUs may take one sample per crusher house or breaker
building, rather than one sample per EGU, if the EGUs share the crusher house or breaker
building. Reasons at 45. For such a source the owner or operator must determine the mercury
content in terms of lbs/trillion Btu using the data analyzed.
Id
.
If an EGU is required to comply with this Section, the owner or operator must conduct
sampling and analysis pursuant to this Section at least 30 days before the start of the month for
which this requirement applies if the EGU is in daily service, and “if the EGU is not in daily
service, on the day that the EGU resumes operation.” Reasons at 45.
Section 225.270.
For a source with one or more EGUs, the owner or operator must
submit written notification to the Agency pursuant to 40 C.F.R. 75.61 for each EGU or group of
EGUs monitored at a common stack and each non-EGU monitored under 40 C.F.R.
75.82(b)(2)(ii). Reasons at 45.
Section 225.290.
Under subsection (a)(1), the owner or operator of an EGU and its
designated representative must comply with applicable recordkeeping and reporting
requirements of 40 C.F.R. 75.84 and those of this section. Reasons at 45-46. In subsection
(a)(2), if the EGU is subject to emissions standards, the owner or operator must keep records for
each month identifying the emissions standard with which the EGU is complying or from which
the owner or operator is calculating allowable emissions. Proposed Section 225.290. Such an
EGU must also maintain records of the daily mercury content of coal used and the daily and
monthly input mercury in the file required under 40 C.F.R. 75.84(a), if the EGU complies with
this Subpart “by means of Section 225.230(a)(2) or 225.237(a)(1)(B) or us[es] input mercury
levels to determine the allowable emissions of the EGU.”
Id
. An EGU must maintain records of
the daily and monthly gross electrical output in the file required under 40 C.F.R. 75.84(a), if such
EGU complies “with this Subpart by means of Section 225.230(a)(1) or 225.237(a)(1)(A) or
using electrical output to determine the allowable emissions of the EGU.”
Id
.
In subsection (a)(3), the owner or operator must maintain records of monthly emissions
of mercury from each EGU. For an EGU that complies by means of section 225.230(b) or (d) of
this Subpart, the owner or operator must additionally maintain records of the monthly allowable
emissions of mercury from the EGU. Reasons at 46. In subsection (a)(4), an EGU that is
participating in an averaging demonstration pursuant to Section 225.232 must keep records of the
other sources and other EGUs covered by the demonstration and within 60 days of the end of
each month, calculate and record the actual and allowable mercury emissions for the month and
the 12-month rolling period.
Id
. Subsection (a)(5) specifies the quality assurance records that a
source must maintain. Proposed Section 225.290 In subsection (a)(6), the Agency provides that
an EGU must maintain an electronic copy of all electronic submittals to the USEPA pursuant to
40 C.F.R. 75.84(f).
Id
. In subsection (a)(7), the Agency provides that an EGU must retain all
19
records required by this Section on site, unless otherwise provided for in the CAAPP permit, and
that the EGU will provide copies of any record to the Agency upon request.
Id
.
Subsection (b) proposes that the owner or operator will submit quarterly reports and sets
forth the information that must be included in such reports. Reasons at 47. Under subsection (c)
the owner or operator will be required to submit a compliance certification in support of each
quarterly report and sets forth the contents of such certification.
Id
. Subsection (d) requires that
the owner or operator submit an Annual Certification of Compliance to the Agency no later than
May 1 of each year.
Id.
Subsection (d) also sets forth the contents of such Certification of
Compliance and provides that the Certification of Compliance shall address compliance for the
previous calendar year.
Id.
Subsection (e) requires that the owner or operator promptly notify
the Agency of deviations of requirements of Subpart B, for each EGU.
Id
. Subsection (f)
requires that within 45 days of completing a quality assurance relative accuracy test audit
(RATA) the EGU shall submit the RATA report to the Agency for affected EGUs.
Id
.
Section 225.295.
In this Section, the mercury emissions allocation to the state under
CAMR must not be allocated to any EGU or other source of mercury emissions. Reasons at 47.
The Agency must hold all allowances allocated to the state by USEPA and the Agency shall
instruct USEPA to permanently retire all such allowances at the end of each calendar year.
Id.
PUBLIC COMMENTS
The Board has received an unprecedented number of comments in this proceeding. As of
today the Board has received 7,286comments. Those comments range from lengthy post-hearing
comments from the participants to postcards and notes from citizens of the State. The
overwhelming majority of the comments support the adoption of the Agency’s proposal. Due to
the volume of comments received, the Board cannot individually summarize all of the
comments, nor can the Board list all those by name who filed a comment. The Board’s decision
not to individually summarize or identify an individual does not mean that the Board has not
reviewed the comments or did not consider the comments in reaching today’s decision. The
Board appreciates each and every comment and the time taken by the individuals to present their
thoughts and opinions to the Board. All the comments received by the Board in this proceeding
can be viewed on the Board’s web sites at www.ipcb.state.il.us., through the Clerk’s Office On
Line link.
The Board will list the organizations and public officials who filed comments below.
However, rather than summarize all the comments, the Board will include comments where
appropriate when discussing the issues remaining in this proceeding. The Board has received
comments from throughout the State and specifically from the following organizations or public
officials in support of the proposed rule:
Sinai Health System (PC 6322)
Ounce of Prevention Fund (PC 6321)
Northern Illinois Public Health Consortium, Inc. (PC 6320)
Metropolitan Chicago Healthcare Council (PC 6319)
Illinois Public Health Association (PC 6318)
20
Illinois Maternal and Child Health Coalition (PC 6317)
Illinois Environmental Council and Alliance for the Great Lakes (PC 6316)
Illinois Division of the Izaak Walton League, Illinois Council of Trout Unlimited,
National Wildlife Federation, Natural Resource Defense Council,
Prairie Rivers Network (PC 6315)
Illinois Academy of Family Physicians (PC 6314)
Citizen Action Illinois (PC 6313)
Children’s Hospital of Illinois (PC 6312)
Child Care Coalition of Lake County (PC 6311)
American Lung Association of Metropolitan Chicago (PC 6310)
American Bottom Conservancy (PC 6309)
American Academy of Pediatrics, Illinois Chapter (PC 6308)
Access Living (PC 6307)
Advocate Health Care (PC 6306)
Sierra Club, Illinois Chapter (PC 6305)
Citizens Against Ruining the Environment (PC 6304)
Kathryn Tholih of Center for Neighborhood Technology (PC 6303)
Susan Spengler, President, League of Women Voters, Palatine Area (PC 6285)
April K. Holden, Village Clerk, Village of Downers Grove (PC 6276)
Sadhu A. Johnston, Commissioner, Chicago Department of Environment (PC 6232)
Illinois Public Interest Research Group (numerous comments)
Chicago Clean Power Coalition (numerous comments)
Representative Barbara Flynn Currie (PC 44)
Michael D. Belsky, Mayor, City of Highland Park (PC 3)
Mayor Richard H. Hyde, City of Waukegan (PC 2)
Governor Rod R. Blagojevich (PC 1)
The supporters of the rule discuss the issues concerning health effects from ingestion of
methylmercury. Many note that coal-fired plants are the main stationary source of mercury in
the State. The supporters urge the Board to adopt the proposal submitted by the Agency.
Among the public comments are a substantial number of post cards, which echo the concerns
about the health effects of mercury ingestion.
The Board has also received the following comments in opposition to the proposal:
Phillip M. Gonet, President, Illinois Coal Association (PC 6295)
Eugene M. Trisko, General Counsel, Unions for Jobs and the Environment (PC 6286)
Scott Wiseman, Vice President, Center for Energy and Economic Development, Inc.
Midwest Region (PC 6286)
The opponents rely on economic reasons for their opposition to the proposal. They express
concerns about the increased costs of generating electricity in Illinois and the impact on
consumers and businesses as a result. The opponents urge the Board to adopt the federal CAMR
rule instead of the Agency’s proposal.
21
The Board received final comments from the following participants, which will be
included in the discussion of the issues below:
Prairie State Generating Company. L.L.C. (Prairie State) PC 6294
City of Springfield, City Water Light & Power (CWLP) PC 6296
Environmental Law and Policy Center (Environmental Advocates) PC 6297
2
Illinois Environmental Protection Agency (Agency) PC 6298
Kincaid Generation, L.L.C. (Kincaid) PC 6299
Midwest Generation, L.L.C. (Midwest Generation) PC 6300
Ameren Energy Generating Company, AmerenEnergy Resource Generating Company,
and Electric Energy, Inc. (Ameren) PC 6301
Illinois Environmental Regulatory Group (IERG) PC 6302
Illinois Chapter of the Sierra Club (Sierra Club) PC 6305
PERSONS WHO PROVIDED TESTIMONY
The following individuals prefiled testimony on behalf of the Agency:
Jim Ross (Exh. 1)
Dr. Deborah Rice (Exh. 3)
Jeffrey W. Sprague (Exh. 7)
Marcia Willhite (Exh. 8)
Dr. Thomas C. Hornshaw (Exh. 9)
Dr. Gerald J. Keeler (Exh. 10)
Christopher Romaine (Exh. 36)
Richard E. Ayers, Esq. (Exh. 39)
Robert J. Kaleel (Exh. 41)
Sid Nelson, Jr. (Exh. 43)
David C. Foerter (Exh. 45)
Dr. James E. Staudt (Exh. 50)
Dr. Ezra D. Hausman (Exh. 51)
Dr. Michael W. Murray testified (Exh. 74) on behalf of the Environmental Law and
Policy Center.
Dianna Tickner, Vice-President of Prairie State Generating Station, LLC., presented
testimony on behalf of Prairie State (Exh. 80).
On behalf of Midwest Generation the following individuals testified:
J. Edward Cichanowicz (Exh. 84)
2
The Board notes that the Illinois Chapter of the Sierra Club filed a comment (PC 6305) that is
virtually identical to the Environmental Advocates’ comment (PC 6297); therefore, the Board
will use PC 6297 and all citations will be to that comment. However, the Board acknowledges
that the Illinois Chapter of the Sierra Club joins in all the comments.
22
Dr. Ishwar Prasad Murarka (Exh. 114)
William DePriest (Exh. 115)
James Marchetti (Exh. 118)
Krish Vijayaraghavan (Exh. 126)
Dr. Peter M. Chapman (Exh. 129
Dr. Gail Charnley (Exh. 130)
Richard D. McRanie (Exh. 132)
Mr. Michael L. Menne (Exh. 76) and Dr. Anne E. Smith (Exh. 77) testified on behalf of
Ameren.
Mr. C. J. Saladino (Exh. 138) and Mr. Andy Yaros (Exh. 137) testified on behalf of
Kincaid.
ISSUES
Section 27 of the Act requires that the Board must determine that a rule of general
applicability is economically reasonable and technically feasible before adopting the rule. While
two utilities (Ameren and Dynegy) support adoption of this rule as amended during this
proceeding, other utilities still challenge the rule. The major challenges to the rule are that the
Agency has not demonstrated that the rule is technically feasible or economically reasonable. In
challenging technical feasibility, the opponents raise the following issues: (1) the availability of
the control technology, (2) the feasibility of measuring emissions reductions, and (3) the
compliance flexibility in the proposal. In discussing economic reasonableness the opponents
discuss issues concerning: (1) the deposition of mercury and modeling of deposition, (2) the
health effects of mercury and whether control of emissions will result in positive health effects,
(3) the fish advisories, and lastly (4) the costs of compliance.
Participants also challenge the legal basis for adding proposed amendments to the
proposal without first providing notice of the amendments pursuant to the Administrative
Procedure Act (APA) (5 ILCS 100/1-1
et. seq.
(2004)). Participants also question whether the
amendments conform to federal law. For purposes of discussion, the Board will address the
arguments concerning the technical feasibility of the proposal, with amendments recommended
during the hearings. Next, the Board will discuss the economic reasonableness of the proposal
and amendments as well as discussing the potential health benefits from mercury regulation.
Finally, the Board will discuss the legal challenges to the proceeding.
In addition to these general issues, the Board will discuss the unique circumstances
surrounding Kincaid. Kincaid is in a unique position due to the size of the facility and steps
Kincaid has already taken for compliance.
TECHNICAL FEASIBILITY
General Comments
23
The Board will summarize the general comments related to technical feasibility in this
section.
Midwest Generation’s Comment
Midwest Generation’s final comment expresses a deep concern that the rule, even with
the “flexibility” is not technically feasible. PC 6300. Midwest Generation has expressed these
concerns in four general areas. First, Midwest Generation does not believe the controls preferred
by the Agency are sufficiently developed and available for use as controls. Second, Midwest
Generation questions the efficiency of the controls, particularly the use of HCI. Third, Midwest
Generation challenges the adequacy of monitoring methods for measuring mercury emissions to
demonstrate compliance with the proposed regulations. And fourth, Midwest Generation argues
that the “flexibility” in the proposed rule does not really provide flexibility to utilities in
complying with the proposed rule.
Kincaid’s Comment
Kincaid has a 1,250-megawatt coal-fired power plant in Illinois, which is Kincaid’s only
plant in Illinois. PC 6299 at 2. Kincaid believes that mercury emissions reductions from coal-
fired utility boilers are warranted; however man-made emissions of mercury are small in
comparison to other sources around the world.
Id
. Further, Kincaid argues that the Agency’s
proposal to reduce mercury emissions from coal-fired utilities in Illinois by 90% is unreasonable.
Kincaid asserts that the proposed rule places Kincaid at a competitive disadvantage over other
electricity providers in Illinois and is unfair to Kincaid. PC 6299 at 1-2. Kincaid supports this
assertion with arguments regarding the emissions reductions required in the rule and the
flexibility of the rule.
Prairie State’s Comment
Prairie State believes that the inclusion of the TTBS, if revised as they suggested, would
alleviate many of Prairie State’s concerns. PC 6294 at 15. However, Prairie State does have
additional suggestions for changes in the proposed rule.
Id
. First, Prairie State recommends
adding ASTM D6722-01 “Standard Test Method for Total Mercury in Coal and Combustion
Residues by Direct Combustion Analysis” to Section 225.202 as an acceptable method.
Id
.
USEPA has accepted this method and Prairie State believes Illinois should as well. PC 6294 at
15-16.
Prairie State argues that Section 225.210(e) should be amended to require compliance be
judged on a unit level, not both a unit level and source level. PC 6294 at 16. Prairie State opines
that by requiring both the unit and the source be in compliance, the rule is effectively assessing
two violations if a unit fails to meet an emissions level.
Id
. Finally Prairie State urges the Board
to allow averaging for new as well as existing units.
Id
.
Environmental Advocates’ Comment
24
Environmental Advocates strongly support the proposed mercury rule, including the
MPS. PC 6297 at 1. Environmental Advocates argue that the record before the Board
demonstrates the public health and environmental benefits to Illinois that will be achieved by the
adoption of the Illinois proposal rather than CAMR.
Id
. Environmental Advocates assert that
the record is clear that the additional reductions can be achieved using available technology
without creating disproportionate costs to utilities or consumers.
Id
. Environmental Advocates
opine that the question is not whether mercury should be controlled, because CAMR does that,
but whether the proposal “will produce public health and environmental benefits through deeper,
faster reductions than those mandated under CAMR in a manner that is reasonable for regulated
entities to achieve.” PC 6297 at 2. Environmental Advocates focus their comments on evidence
in the record about Illinois-specific factors that provide justification for going beyond CAMR.
Id
.
Environmental Advocates argue that as an initial matter, the remaining opponents’
position that the rule is not technically feasible or economically reasonable is difficult given
Ameren and Dynegy now support the rule. PC 6297 at 9. Environmental Advocates point out
that CWLP has agreed to include in the PSD permit a requirement to comply with the standards
proposed in the rule.
Id
. Environmental Advocates assert that the remaining opponents have
presented no facility-specific or companywide information about the projected cost of
compliance and in fact Midwest Generation’s witness, Mr. DePriest specifically declined to
answer questions about specific companies.
Id
.
Agency’s Comment
The Agency’s final comment reiterates that this rulemaking is intended to satisfy Illinois’
obligation to submit a state plan to USEPA to address the requirements of CAMR, while
addressing the deficiencies of CAMR. PC 6298 at 1. The Agency notes that over 40% of
Illinois’ electricity is generated from coal-fired power plants, which are the largest source of
uncontrolled mercury emissions in Illinois. PC 6298 at 2. The rulemaking is designed to
achieve a high level of mercury reductions, based on the Agency’s finding that mercury control
technology is technologically feasible and economically reasonable.
Id
. The proposed rule will
allow for mercury reductions to take place in two phases beginning in 2009.
Id
. The proposal
includes flexibility by allowing for systemwide averaging during the first phase and the TTBS.
Id
. The Agency has also joined with Ameren and Dynegy for the inclusion of the MPS. PC
6298 at 2-3.
The Agency notes that in the TSD, the Agency classifies existing coal-fired units in
Illinois into five categories. PC 6298 at 5. The first category is units that can comply with
emissions requirements in the proposed rule through co-benefit removal, this includes
bituminous units equipped with FGD (scrubbers), selective catalytic reduction (SCR), and the
circulating fluidized bed boiler at Marion.
Id
. The second category includes small-capacity
bituminous coal units that are currently unscrubbed, which may or may not meet the rule
requirements but are eligible for the TTBS or MPS.
Id
. The third category is units with an ESP
that plan to install fabric filters downstream of the ESP.
Id
. The fourth category includes two
units burning Powder River Basin (PRB) coal and using hot side ESPs, which the Agency agrees
25
will have to install fabric filters to comply with the rule requirements.
Id
. The last category is
units firing PRB coal with cold side ESPs, the largest group of units in Illinois.
Id
.
The Agency argues that the principle area of disagreement remaining in this rule is the
last category of units and the methods necessary for those units to meet requirements of the
Illinois mercury rule. PC 6298 at 5-6. The Agency asserts that the evidence before the Board
demonstrates that PRB coal-fired units will be able to use sorbent injection to achieve a 90% or
better reduction in mercury emissions on the timetable proposed in the rule. PC 6298 at 5. The
Agency maintains that Mr. Cichanowicz’s opinions regarding the technical feasibility of sorbent
injections systems are based on speculation and are contradicted by the evidence in the record.
PC 6298 at 6.
Control Technology
In this section of the opinion, the Board will summarize the concerns of the participants
regarding the actual controls available for mercury emissions reductions. After summarizing the
comments, the Board will discuss the comments and the record in the proceeding and make a
finding on the technical feasibility of reducing mercury emissions.
Midwest Generation’s Comment.
Controls.
Midwest Generation notes that according to Dr. Staudt, sorbent injection is the
most developed technology for mercury removal. PC 6300 at 14. In this regard, Midwest
Generation points out that there are three types of sorbent injection mechanisms described by Dr.
Staudt in the TSD. PC 6300 at 14. Those three types are: (1) injection of sorbent upstream of
an existing ESP or fabric filter; (2) TOXECON, which consists of a fabric filter downstream of
the ESP with the sorbent injected between the ESP and fabric filter; (3) TOXECON-II, which
requires injection of the sorbent between fields in the ESP. PC 6300 at 14, citing Exh. 50 at 5.
Midwest Generation argues that the Agency’s proposed standard of 90% mercury
emissions reduction is based on the Agency’s belief that the installation of HCI will achieve 90%
reduction. PC 6300 at 9. If HCI does not reduce mercury emissions by 90%, Midwest
Generation asserts that the Agency relies on the “flexibility” in the rule to achieve compliance.
Id
. Based on the Agency’s assertions regarding the use of HCI in the TSD, Midwest Generation
maintains that the technical feasibility question is “whether sorbents [injection] can consistently
and reliably achieve mercury reductions at the levels required by the rule over long term
operation.” PC 6300 at 9, 15. In order to demonstrate technical feasibility, Midwest Generation
argues that the Agency must establish that HCI alone is technically feasible and will achieve
90% reduction over the long term. PC 6300 at 9-10.
Midwest Generation asserts that the use of HCI has many problems including the fact that
the technology is still developing (PC 6300 at 14, 16, 36, 40) and may not be commercially
available (PC 6300 at 37-38). Also injection of sorbent may cause issues with particulate matter
(PM) (PC 6300 at 17, 47) and the availability of the controls in terms of material and time to
construct may not be sufficient to meet the requirements of the rules (PC 6300 at 47).
26
Developing Technology.
More specifically in terms of the developing nature of the
technology, Midwest Generation points to Dr. Staudt’s testimony and argues that he has
described “an evolving control approach, not one for which a responsible regulatory authority or
an affected company can be assured will produce the required reductions.” PC 6300 at 14.
Midwest Generation states that the level of mercury removal achievable using HCI is what is
being questioned, not the feasibility of the installation and operation of the activated carbon
injection hardware or equipment. PC 6300 at 36.
Midwest Generation argues that the Agency has not demonstrated that the HCI sorbents
will reliably, consistently, and over the long term reduce mercury emissions by 90%. PC 6300 at
36. Midwest Generation believes that HCI is an evolving technology that requires more testing.
Id
. Midwest Generation states that the additional need for testing is why the Department of
Energy (DOE) has funded a test currently under way at the Crawford Generating Station.
Id
.
Midwest Generation notes that USEPA also found that mercury removal technology is evolving
and DOE does not believe that the technology is “there” yet. PC 6300 at 36-37, citing 70 Fed.
Reg. 28614-5 and Exh. 55.
Midwest Generation comments that the Electric Power Research Institute (EPRI)
3
does
not believe that the HCI technology is commercially available. PC 6300 at 37. EPRI, according
to Midwest Generation, distinguishes between “commercially available” and “offered for sale
commercially” and EPRI considers the mercury control technologies to be offered for sale
commercially, but not commercially available. PC 6300 at 37-38, citing Exh. 113. Midwest
Generation points to the definitions of “commercially available” given by Dr. Staudt and Mr.
Nelson to argue that their definitions are “more akin” to EPRI’s definition of “offered for sale
commercially” than EPRI’s definition of “commercially available”.
Id
. Midwest Generation
notes that EPRI’s definition of “commercially available” technology means a technology whose
performance can be predicted with confidence based on sufficient long-term testing utilizing
different configurations and coal types. PC 6300 at 38.
Midwest Generation also pointed out Mr. DePriest’s testimony supports its position
regarding the availability of control equipment. PC 6300 at 47. Midwest Generation
characterized the testimony as expressing concern in terms of material and labor, where
companies are not confident that the mercury control technology will yield reliable, consistent
results.
Id
.
Particulate Matter.
Midwest Generation’s concern about increased particulate matter
emissions was delineated by the testimony of Mr. DePriest. PC 6300 at 4, citing CTr. at 1080.
Mr. DePriest expressed a concern that the ability of an ESP to maintain particulate matter
emissions and opacity limits could be affected by increased loading of carbon.
Id
. Mr.
Cichanowicz also had concerns that additional carbon loading could negatively impact PM and
opacity compliance. PC 6300 at 47, citing CTr. at 584-87. Mr. Cichanowicz identified concerns
about the characteristics of the activated carbon because the activated carbon is significantly
3
EPRI was established in 1973 as an independent, nonprofit center for public interest energy and
environmental research. EPRI’s members represent over 90% of the electricity generated in the
United States.
See
www.epri.com
.
27
different from the carbon in the ash loading typically handled by an ESP. PC 6300 at 47, citing
CTr. at 593. Mr. DePriest feels that because of switching to low sulfur PRB coal, there is not
much margin left in the ESPs to take on additional particulate loading. PC 6300 at 47, citing
CTr. at 1159. Mr. DePriest also noted that retrofitting additional collecting areas (ESP fields) to
accommodate the sorbents will be extremely difficult considering the current configurations of
existing ESPs and other plant infrastructure. Exh. 115 at 11.
Do the Controls Work.
Midwest Generation points to evidence in the record that
Midwest Generation believes establishes that not only is the technology still evolving, but as
currently developed, the technology will not achieve compliance with the rule. Specifically,
Midwest Generation challenges the length of the tests relied upon by the Agency, as well as the
test results applicability to Illinois. Midwest Generation also notes several problems with the
technology that have not been fully explored such as the impact of the size of the ESPs specific
collection area (SCA) and the space availability for baghouses to be added at the optimum
locations.
Length of Tests.
Midwest Generation asserts that the technology has not demonstrated a
consistent, long-term removal rate of 90%. PC 6300 at 11. Midwest Generation believes that
the conclusions of Dr. Staudt that 90% reduction can occur with the installation of sorbents
injection systems are based on the results of tests at various EGUs lasting from a few days to a
year. PC 6300 at 11-12. Midwest Generation asserts that most of the tests upon which
justification for the rule is based were only 30-day tests that do not provide sufficient operational
information regarding the long-term effects of injecting activated carbon. PC 6300 at 12.
Midwest Generation notes that there is only one test discussed in this record that lasted for one
year and that test is the Gaston Plant test. PC 6300 at 12, citing TSD at 125-26, 6/21pmTr. at 24,
6/22Tr. at 121.
Midwest Generation argues that the results of the Gaston Plant test do not “totally
square” with the Agency’s assertion that HCI is tested and commercially available. PC 6300 at
12. First, Midwest Generation points out that the Gaston Plant burns low-sulfur bituminous coal,
while most Illinois plants burn PRB coal, which is a low-sulfur subbituminous coal.
Id
.
Second, Midwest Generation notes that the Gaston plant was testing mercury removal
through a TOXECON, or fabric filter arrangement and the question was the air-to-cloth ratio
necessary to achieve 90% removal. PC 6300 at 12, citing CTr. at 497-98. Midwest Generation
indicates that the results of Gaston showed a removal rate of only 85.6% and to determine
whether the TOXECON arrangement could achieve 90% removal a greater air-to-cloth ratio was
simulated.
Id
. The simulation did result in a 90% removal for periods of less than 12 months.
Id
. Midwest Generation concedes that Mr. Cichanowicz stated that he believes that 90%
removal is “highly likely” if a system were initially designed to include TOXECON; however,
the Gaston Plant was not so designed and did not achieve 90% removal on a sustained 12-month
basis. PC 6300 at 12, citing CTr. at 500.
Third, the Gaston Plant had a baghouse in place following a mal-performing hot side
ESP. PC 6300 12-13, citing CTr. at 499. However, according to Midwest Generation there are
only three hot side ESPs in Illinois and none are followed by a baghouse. PC 6300 at 13. The
28
remaining EGUs in Illinois have cold side ESPs.
Id
. Midwest Generation argues that therefore,
the Gaston Plant test is not really applicable to any EGU in Illinois with a cold side ESP and
there is no long-term information regarding the ability of HCI to consistently, reliably remove
mercury at a rate of 90%.
Id
.
As to the 30-day tests discussed by both Dr. Staudt and Mr. Nelson, Midwest Generation
is skeptical of the applicability of the short-term test results as predictor of long-term
performance of the sorbent injection systems and cautions against reliance upon them. PC 6300
at 16, 40. Midwest Generation argues that the Board and those who will be regulated by the rule,
should consider and rely on long-term data that has been fully assessed for quality, accuracy, and
meaning. PC 6300 at 16. Midwest Generation asserts that the danger of relying upon short-term
test results or unpublished test results was demonstrated by Mr. Nelson. PC 6300 at 16.
Midwest Generation points out that Mr. Nelson provided information on the Crawford Station
test, which was later corrected. PC 6300 at 16-17, citing Exh. 88 and PC 6287. Midwest
Generation maintains that HCI was not achieving 90% removal during preliminary testing at
Crawford Station and accurate monitoring could not be performed. PC 6300 at 17.
Size of SCA and Placement of Additional Controls.
An additional concern pointed out
by Midwest Generation is the effect the size of the SCA may have on the ability of an ESP to
remove mercury. PC 6300 at 39. Mr. Cichanowicz stated: “There is perhaps something about
large SCA ESPs that makes it amenable to high levels of mercury removal.” PC 6300 at 39,
citing CTr. at 554. Midwest Generation draws attention to Figure 5.2 in Mr. Cichanowicz’s
prefiled testimony that suggests there is a direct or indirect relationship between mercury
removal and ESP SCA size. PC 6300 at 39, citing Exh. 84 at 4. Mr. Cichanowicz noted that
removal of mercury in the 90 to 95% range occurred at the large ESPs and not in the smaller
ESPs. PC 6300, at 39, citing CTr. at 523-24. According to Mr. Cichanowicz, smaller ESPs are
more common in Illinois.
Id
.
Midwest Generation asserts that Dr. Staudt and Mr. Nelson claim that SCA size has no
role in mercury removal. PC 6300 at 39. Midwest Generation maintains that their position “has
not been proven” in this proceeding.
Id
. According to Midwest Generation, Mr. Cichanowicz
was making the point that no one thoroughly understands the relationship between SCA size and
mercury removal. PC 6300 at 29.
Mr. Cichanowicz provided several exhibits that were aerial photos of units in Illinois
where larger ESPs had been constructed over a smaller ESP. PC 6300 at 39, citing Exh. 89-92.
Midwest Generation argues that these exhibits also establish how much ductwork is involved in
retrofitting plant sites. PC 6300 at 39. Mr. Cichanowicz testified that with Exhibits 94 and 95 he
intended to illustrate the lack of space available for the installation of TOXECON or a larger
ESP which would be necessary to meet the required mercury reductions.
Id
. Midwest
Generation argues that Mr. Cichanowicz was making the point that there is no room for
placement of additional controls at a location that makes the most control efficiency sense. PC
6300 at 40.
Kincaid’s Comment
29
Kincaid asserts that the Illinois proposal is “generally acknowledged to be the most
stringent mercury proposal” in the country and there is uncertainty around the technology
necessary to meet a sustained 90% reduction or 0.0080 lb/GWh emissions standard. PC 6299 at
4. Kincaid maintains that the hearing record in this proceeding supports the position that the
technology to achieve 90% reduction or 0.0080 lb/GWh emissions standard is not currently
available.
Id
. Kincaid points to Mr. Ross’s statement that “some of them [EGUs] may not reach
90%.” PC 6299 at 4, citing CTr. at 211. Mr. Ross went on to state that the MPS recognizes that
there may be potential difficulties and the MPS will give more time in the “broad multi-pollutant
category.” PC 6299 at 4, citing CTr. at 212.
Kincaid states that they do not have confidence that HCI can achieve a sustained 90%
reduction or 0.0080 lb/GWh emissions standard at the current state of technology. PC 6299 at 4.
Kincaid does not believe the technology has been fully demonstrated nor does Kincaid believe
that the technology is “commercially available” at this time.
Id
. Kincaid concurs with an
opinion from Dr. Staudt in a March 2006 article that “a broad and aggressive R&D program now
under way will yield more experience and information in the next few years.” PC 6299 at 4-5,
citing Exh. 54. Kincaid argues that such expectations do not provide guaranteed performance
and absent guarantees, Kincaid cannot accept the risk of potential non-compliance. PC 6299 at
5.
Kincaid points to the testimony of Mr. Cichanowicz to support the argument that HCI has
not been proven to achieve the levels necessary to meet the Illinois proposal. Mr. Cichanowicz
stated that activated carbon injection is not sufficiently developed to consistently deliver high
mercury removal under the varied conditions in Illinois despite impressive results from selected
demonstrations. PC 6299 at 5, citing Exh. 84 at 3. Kincaid points out that Mr. Cichanowicz
concedes that 90% removal or better has been demonstrated, the results are from short-term tests
and so the extent to which those can be applied to the long term is uncertain.
Id
. Kincaid notes
that Mr. Cichanowicz also believes that to achieve 90% reduction a mercury removal target of
93%-95% should be designed for in the systems. PC 6299 at 6, citing Exh. 84 at 2.
Kincaid asserts that many researchers and other companies agree that mercury specific
controls are not advanced enough to reach 90% reduction. PC 6299 at 5-6. Kincaid points to
Ameren’s testimony that absent the MPS, Ameren will not rely on carbon injection alone to
achieve 90% reductions.
Id
. Kincaid argues that EPRI also supports this position. PC 6299 at 6.
As further evidence of Kincaid’s position, Kincaid points to Mr. Nelson and his information on
Crawford Station. PC 6299 at 7. Kincaid asserts that the presentation by Mr. Nelson at the
Chicago hearing “captures the ‘rush to judgment’ approach” the development of new air
technology can take. PC 6299 at 7-8. Kincaid argues that as the investment in pollution control
equipment will be in the millions of dollars, power companies must take a “carefully measured,
well developed or ‘proven’ approach” to control. PC 6299 at 8.
Kincaid expresses serious concerns with an absolute emissions limit because the
technology will not be able to achieve the absolute emissions limits or achieve the 90%
emissions reduction. PC 6299 at 35. Kincaid does not believe that an absolute emissions limit is
appropriate even in 2015.
Id
. Kincaid asserts that any adoption of an absolute emissions
limitation is “at best, a guess by the Board” that technologies will work as described.
Id
.
30
Kincaid argues that including language in the rule that specifically allows a request for an
adjusted standard or a site-specific rule to be filed with the Board can alleviate this legitimate
corporate concern. PC 6299 at 35-36.
Prairie State’s Comment
Prairie State is concerned that the record lacks information on the ability of existing
mercury control technologies to effectively remove mercury from high sulfur coal, such as
Illinois coal. PC 6294 at 2. Prairie State notes that Ms. Tickner expressed this concern and. the
TSD, and testimony of Dr. Staudt and Mr. DePriest support her position.
Id
. Prairie State argues
the Mr. Nelson’s testimony also suggests that the technology may not be available for high sulfur
coals. PC 6294 at 3, citing 6/22Tr. at 73. Prairie State notes that Dr. Staudt’s testimony
acknowledged that high sulfur coal is a difficult situation and the apparent reason is SO
3
interference. PC 6294 at 4, citing 6/22Tr. at 98, CTr. At 1230.
Prairie State asserts that control of mercury emissions at coal-fired plants is extremely
difficult for many reasons, including the minute amount of mercury in stack gas. PC 6294 at 3.
Prairie points out that short-term testing has occurred at only 28 coal-fired units, which comprise
about 2.3% of the coal-fired units in the United States.
Id
. Like Midwest Generation, Prairie
State points to DOE’s recent conclusion that mercury control technology is still developing and
the technologies might not be available for all coal types and all power plant configurations. PC
6264 at 3, citing Exh. 55 at 1. Prairie State indicates that the USEPA reached a similar
conclusion about mercury controls in the preamble of the CAMR rule. PC 6294 at 3-4, citing 70
Fed. Reg. 28,619. Prairie State argues that there is thus no technical basis for assuming 90%
control of mercury is achievable at all coal-fired power plants. PC 6294 at 4. Prairie State
maintains that this is especially true for mercury control of high sulfur coals like those that
Prairie State will be burning.
Id
.
Prairie State points out that Dr. Staudt offered unsupported testimony that technology on
new facilities will allow the new facilities to meet the mercury reduction standards in the rule;
however, Prairie State argues that the limited available data suggests otherwise. PC 6294 at 4.
Prairie State maintains that in the one study available to date on high sulfur coal at Conesville,
the data indicates a removal rate of less than 50% is achievable. PC 6294 at 4, citing Exh. 80.
And, according to Prairie State, the removal rate was even worse using brominated carbon.
Id
.
Prairie State concedes that the Conesville test may not be directly transferable to Prairie State
due to different control technologies, but Conesville is the only test available for insight into
injection of sorbent on high sulfur coal. PC 6294 at 4.
Prairie State’s concerns about mercury control technology extend to the unavailability of
guarantees that the technologies will provide the removal necessary to meet the rule
requirements. PC 6294 at 5. Prairie State has been working with contractors for the past three
years to determine the capabilities of mercury controls and vendors of the proposed technologies
have indicated a willingness to guarantee 84% mercury removal for Prairie State.
Id
. This
removal rate is based on the mercury content of the Illinois coal Prairie State will burn and 84%
removal rate is insufficient to meet the rule requirements.
Id
.
31
Prairie State explains that a new facility is seeking guarantees that controls will work, to
cover the cost of the entire facility, about $2 to $3 billion. PC 6294 at 6. Contractors will wrap
the various guarantees from vendors into one overall guarantee to cover the scope of the project
and this is necessary to get financing for a project.
Id
. If a guarantee cannot be obtained, Prairie
State argues that it would be because the technology is not currently available and no one wants
to build a $2 to $3 billion facility and hope the technology works.
Id
.
Trading.
Prairie State is concerned that the proposed rule creates a future regulatory
uncertainty and one way to eliminate that uncertainty is to adopt CAMR’s model trading rule and
layer the Illinois requirements on top of the model trading rule. PC 6394 at 6-7. Prairie State
believes that this is necessary because if Illinois opts out of CAMR, then the CAMR mercury
budget for Illinois will be a hard cap on annual emissions in Illinois. PC 6294 at 7. Prairie State
is troubled that in 2018, utilities could be in compliance with the Illinois rule, but the total
emissions could exceed the CAMR budget.
Id
. If that were to happen, Prairie State argues that
Illinois would need to require more reductions of mercury because utilities could not purchase
allowances from other states.
Id
. Prairie State opines that one way for Illinois emissions to
exceed the mercury budget is if mercury control technologies do not perform as advertised and
this is of particular concern with high sulfur coals. PC 6294 at 8.
Prairie State asserts that a recurring theme with a trading program is the potential for “hot
spots” to be created. PC 6294 at 8. Prairie State argues that the evidence presented to the Board
indicates that a mercury cap and trade program will not create “hot spots”.
Id
. Prairie State
points out that Dr. Keeler’s modeling is a receptor model and cannot make future predictions and
thus cannot answer the question of how mercury deposition will change at any given location.
Id
. Prairie State notes that Mr. Vijayaraghavan did present modeling which predicted future
deposition and that modeling indicates that full implementation of 2020 CAIR and CAMR will
lead to less mercury deposition in Illinois than the proposed rule, except for three grid cells
where increases in mercury deposition of less than three percent are predicted. PC 6294 at 8-9.
Prairie State opines that adding the CAMR trading rule to the proposed rule will thus not lead to
“hot spots” in Illinois. PC 6294 at 9.
Environmental Advocates’ Comment
Environmental Advocates argue that activated carbon injection units are designed to
achieve in excess of 90% mercury removal once optimized with operations at specific facilities.
PC 6297 at 11, citing Exh. 50 at 6-7. However, Environmental Advocates assert that the
technical feasibility of the rule is not based on the use ACI alone to meet the proposed standards.
Id
. Environmental Advocates maintain that the record contains several other examples of
practical, existing technologies and techniques to reduce mercury alone or in conjunction with
ACI.
Id
. Environmental Advocates point out that ultimately the rule allows the operator to
decide how to combine options to meet the standards.
Id
. Environmental Advocates list the
technologies and techniques including: (1) using a very low mercury coal or to blend with lower
mercury coals; (2) employing or enhancing existing pollution control technologies; and (3)
monitoring existing facility performance. PC 6297 at 11-12.
Agency’s Comment
32
The Agency maintains that the record demonstrates that PRB coal-fired units with cold
side ESPs can achieve 90% or better reductions using sorbent injection of halogenated powdered
activated carbon (PAC) at a treatment range of about 3lb/MMacf. PC 6298 at 6, citing TSD at
149. This position is supported by Dr. Staudt’s testimony that sorbent injection of halogenated
PAC has been shown to be very effective at several full-scale coal-fired boiler installations and
that 90% removal was achieved. PC 6298 at 6, citing Exh. 50 at 6.
The Agency concedes that Mr. Cichanowicz does not agree that sorbent injection alone
will be sufficient. PC 6298 at 7. However, the Agency argues that Mr. Cichanowicz’s opinion
rests on the premise that sorbent injection upstream of a cold side ESP is incapable of providing
high levels of mercury reduction.
Id
. The Agency notes that Mr. Cichanowicz’s opinion is
based on his position that there is insufficient data to demonstrate mercury control technology is
available at present to assure compliance.
Id
. The Agency argues that Mr. Cichanowicz posed
the wrong test and the issue is really whether the technology will be available to meet the
requirements of the regulation when the regulations become effective. PC 6298 at 7-8. The
Agency opines that the evidence supports the Board making this conclusion. PC 6298 at 8.
The Agency points to the TSD that includes a list of 28 field demonstrations that are
complete and 11 more in progress or planned. PC 6298 at 8, citing TSD at 125-26. The Agency
asserts that unlike the arguments presented by industry, the Agency’s position is supported by
actual test results sponsored by DOE and others.
Id
. The Agency maintains that on units
burning PRB coal with cold-side ESPs, 90% removal or better has been demonstrated at multiple
sites using halogenated PAC at treatment rates of about 3lb/MMacf. PC 6298 at 8. The Agency
argues that the consistency of these results at multiple sites provides a high degree of confidence
that the 90% removal will be accomplished in Illinois.
Id
. The Agency notes that the results
varied only if carbon other than halogenated PAC was used or carbon with lower activity was
used.
Id
.
The Agency also challenges the point made by Mr. Cichanowicz that the size of the ESP
and SCA, might effect performance of the sorbent injection. PC 6298 at 8-11. The Agency
notes that Mr. Cichanowicz in his testimony indicated that the relationship “suggested” was
“anecdotal” and not reflective of “any fundamental theorem of carbon” mercury absorption. PC
6298 at 8. The Agency asserts that Mr. Cichanowicz acknowledged the variation in the
effectiveness of sorbent injection in field demonstrations charted in Figure 5.2 of his testimony
are explained by other factors such as type of sorbent, coal type, and sulfur content of coal.
Id
.
The Agency asserts that Dr. Staudt’s testimony shows a strong relationship between the amount
of sorbent injected and the amount of mercury removal. PC 6298 at 9. This relationship is borne
out when holding constant the type of coal and sorbent when plotting test results, according to
the Agency. PC 6298 at 10-11.
The Agency does concede that injection of SO
3
, to improve ash resistivity for the ESP,
can adversely affect mercury capture by sorbent. PC 6298 at 11. Dr. Staudt has suggested the
injection of SO
3
can occur downstream of mercury sorbent injection and this would avoid the
adverse affect.
Id
. The Agency argues that alternative methods can be used to address ash
resistivity as well. The Agency points out that the only companies in Illinois injecting SO
3
are
33
Ameren, Dynegy, and Electric Energy, all of which now support the proposed rule. PC 6298 at
12.
Board Discussion of Control Technology
In the TSD, the Agency classifies coal-fired EGUs in Illinois into five categories
depending on the pollution control equipment coal type. For the EGUs utilizing coal type and
control figurations other than PRB units with cold-side ESPs, the Board agrees with the Agency
that these units will be able to comply with the proposed mercury regulation by utilizing co-
benefits, MPS. TTBS, and control devices such as fabric filters. The Agency’s agreements with
Ameren and Dynegy also support this view. However, the main concern of the utilities opposing
the Agency’s mercury proposal relates to the Agency’s preferred control technology for PRB
coal-fired units with cold-side ESPs, namely HCI (halogenated activated carbon injection). HCI
for mercury control in an EGU uses halogenated powdered activated carbon (PAC) to bind and
remove mercury.
When challenging the Agency’s position on the use of HCI, Midwest Generation,
Kincaid, and Prairie State refer to the Agency’s preferred control technology for PRB coal-fired
units with cold-side ESP as activated carbon injection (ACI). However, the Agency in its TSD
distinguishes between ACI and HCI. The TSD notes that early experience with untreated PAC
raised questions regarding mercury removal rates on units firing subbituminous coals using
untreated PAC. TSD at 123. Thus, the TSD notes that the focus of subsequent testing has been
on new sorbents such as halogenated PAC. Dr. Staudt also stated that unlike untreated PAC,
halogenated PAC sorbents were formulated specifically to address the mercury capture needs of
coal-fired boilers. Exh. 50 at 6. Based on the results of the additional testing with halogenated
sorbents described in the TSD, the Agency concluded that mercury emissions reduction of 90%
or greater is achievable on PRB coal-fired units with cold-side ESPs using sorbent injection of
halogenated PAC or HCI. PC 6298 at 6. To avoid any confusion regarding the sorbent type, the
Board will refer to the Agency’s preferred control technology as halogenated activated carbon
injection (HCI) in the following discussion.
As described in the TSD, sorbent injection technology is a well-established method to
control mercury emissions for municipal waste combustors (MWC) that is now being applied to
coal-fired power plants.
See
TSD at 118-22. The system consists of a storage silo, metering
valve, pneumatic conveyor system, and series of pipes that direct the sorbent that is blown into
the plant ductwork. TSD at 120. The commonly used sorbents include untreated PAC and
chemically treated sorbents such as the halogenated PAC. While untreated PAC has been found
to be very effective in controlling mercury emissions from MWC, halogenated PAC has been
found to be very effective in controlling mercury emissions from coal-fired power plants. TSD
at 122.
The issues raised by the utilities concerning the application of HCI to control mercury
emissions for Illinois EGUs can be grouped as follows: (1) HCI will not be able to achieve the
required mercury reductions as advertised; (2) HCI performance is affected by the size of the
SCA; (3) HCI has not been sufficiently tested; and, (4) the proposed absolute emissions limits
34
cannot be met. The Board will discuss these four issues in the subsection below before rendering
conclusion at the end of this section.
Will HCI Achieve 90% Mercury Reduction?
Midwest Generation, Kincaid, and
Prairie State all argue that HCI alone will not achieve 90% mercury reduction on a consistent
basis. However, the Board notes that the proposal does not contemplate that HCI alone will
work for all units. Also, the Agency does not argue that HCI alone will always provide
sufficient control. As noted above, the Agency’s position regarding the application of HCI
pertains to only PRB coal-fired units with cold-side ESPs. Other affected units would have to
comply with the proposed regulations through co-benefit (
e.g.
, use of FGD, SCR, etc.), MPS,
TTBS, or installation of control equipment (
e.g.
, HCI, fabric filters, etc.).
In fact, the TSD and Dr. Staudt’s testimony contains extensive information relating to
other technologies.
See
,
e.g.
, TSD at 109-18, 145-47; Exh. 50 at 2-3. Some of those
technologies include coal washing, boiler flue gases air pollution control equipment and air
pollution control equipment designed to remove particulate matter, or FGD systems.
Id
. Based
on the record, all of these technologies can provide a co-benefit for mercury removal from coal.
Thus, the Agency did anticipate that, while HCI is one technology, co-benefits from other
technologies could also be used to remove mercury from coal.
Dr. Staudt does concede that boilers that fire subbituminous coal, many of which are in
Illinois, are not likely to achieve high levels of mercury removal from co-benefits alone and
would require the installation of HCI. Exh. 50 at 4.
As to the HCI technology, arguments are made that the technology is still developing and
may not be commercially available. Kincaid and Midwest Generation rely on the testimony of
Mr. Cichanowicz concerning the probability that the injection of sorbent will result in 90%
removal of mercury. Kincaid lacks confidence that 90% reduction can be achieved consistently
with sorbent injection alone. Midwest Generation notes that even Dr. Staudt believes that the
technology is evolving and Midwest Generation believes more testing is necessary to establish
that the technology will work and is commercially available. Prairie State notes that there has
been a lack of testing of sorbent injection with high sulfur coal, which Prairie State plans to use.
Midwest Generation concedes that the technical feasibility of installing and operating the
HCI hardware is not being questioned; rather, the level of mercury reduction that can be
achieved is the issue.
See
PC 6300 at 36. Given this concession by Midwest Generation, the
Board looks to determine if the record supports the proposition that 90% reduction or an
emissions standard of 0.0080 lb/GWh can be met using HCI. The TSD devotes several pages to
field tests of HCI, both completed and in progress that demonstrate 90% removal occurs with
sorbent injection.
See
,
e.g.
, TSD at 122-30. Also, the TSD discusses the control technologies at
Illinois plants and even list the technologies the Agency anticipates will be used for each EGU at
each plant in Illinois.
See
TSD at 147-62. Thus, unlike the general concerns raised by Midwest
Generation and Kincaid, the TSD specifically addresses controls at each plant in Illinois.
See
TSD at 162-63, Table 8.9.
35
Both Dr. Staudt’s testimony and the TSD indicate that at least some of the units in Illinois
will be able to achieve 90% mercury emissions reduction with HCI.
See
Exh. 50 at 6, TSD at
162-63. The units where 90% reduction may not be achieved are those that have PM control
issues, or units that use SO
3
as flue gas conditioner. The Board agrees with the Agency that the
units whose performance is affected by SO
3
can overcome the adverse effect by injecting SO
3
downstream of mercury sorbent injection or by using alternative conditioning methods. The
units with PM issues can use TTBS or averaging to comply with the regulations during the
period of optimization of controls and operation.
The TSD also provides evidence as to the actual commercial availability of sorbents and
the continued development of sorbents.
See
TSD at 139-44. Specifically the TSD indicates that
sorbent injection systems can generally be fully installed and commissioned within six months of
placing an order. TSD at 139. The TSD refers to at least one guarantee from a vendor that
sorbent injection will result in 90% removal. TSD at 140-41. The TSD indicates that activated
carbon sorbents are available from a number of suppliers and that there is long-term experience
with sorbent injection of municipal waste incinerators. TSD at 142. The TSD also notes that
work is underway to improve sorbents. TSD at 143. Thus, the record contains detailed
information on the commercial availability and development of sorbent injection controls.
Further, the Board notes that the proposed rules allow a period of almost three years for the
affected units to achieve compliance. Based on the record, the Board finds that HCI technology
is available to meet the requirements of the proposed rules.
Prairie State’s comment concerning the lack of information on high-sulfur coals and
reliance on statements by DOE is of concern to the Board. However, Prairie State acknowledges
that with changes to the TTBS, most of Prairie State’s concerns could be addressed.
See
PC
6294 at 15. The Board will therefore address the concerns of Prairie State under the discussion
of TTBS below.
Midwest Generation expresses concerns that the injection of sorbents may cause issues
with particulate matter. The TSD acknowledges that sorbent injection has the potential to affect
particulate matter control devices. TSD at 134. However, the TSD notes that dozens of tests
programs have been run where the sorbent is injected upstream of the ESP and in only one has
there been adverse impacts observed.
Id
. Again the record contains evidence of actual test data
demonstrating that increased emissions of particulate matter will not occur. However, if PM
issue does come up at plant, the Board notes that the affected plant may utilize the flexibilities
allowed in the proposed regulations, such as TTBS and averaging, to comply with the rules
during the period of optimization of control equipment.
Size of the SCA.
Midwest Generation raises an issue, based on Mr. Cichanowicz’s
testimony concerning the effect of SCA size on mercury reductions. The Board does not find
evidence to support this concern. Mr. Cichanowicz concedes: “Figure 5-2 is not intended to
reflect any fundamental theorem of carbon HG absorption or ESP residence time, but rather
projects an anecdotal relationship.” Exh. 84 at 4. Mr. Cichanowicz offers his opinion that
achieving 90 to 93% mercury removal on larger units such as St. Clair and Meramac, with ESPs
of 720 and 400 SCA, respectively “portends the same result on small ESPs at stations such as
Will County and Hennepin.”
Id
. However, Mr. Cichanowicz’s opinion is not supported by the
36
evidence in the record. Actually, the record indicates that the variations in effectiveness of
sorbent injection shown in Figure 5-2 (Exh. 84 at 39) submitted by Mr. Cichanowicz are
explained by other factors, including choice of sorbent, coal type, and coal sulfur content.
Further, the record suggests a strong relationship between the amount of halogenated sorbent and
mercury removal. Therefore, the Board finds that the record does not demonstrate that the size
of the SCA will impact mercury reduction HCI.
Length of Tests.
Midwest Generation, Kincaid and Prairie State argue that the short-
term duration of the field testing is insufficient to establish that 90% reduction of mercury can be
consistently achieved over the long term. Midwest Generation attempts to distinguish the single
12-month test included in the record from any potential applicability in Illinois. The Board is
cognizant that the short-term testing is not a substitute for long-term testing. However, the
results of multiple field tests of HCI on PRB coal-fired units with cold side ESPs have
demonstrated 90% or better removal at sorbent rates of 3 lb/Mmacf. Further, the Board believes
that the three-year compliance period allowed by the proposed regulations provides sufficient
time for utilities to install HCI systems, and optimize sorbent rates and plant operations to
comply with the standards. Therefore, the Board finds that the short-term testing is sufficient to
demonstrate technical feasibility.
Absolute Emissions Limit.
Kincaid and Prairie State both express concerns about the
Board establishing an absolute emissions limit. Kincaid argues that setting an absolute emissions
limit is a guess by the Board that technologies will develop to achieve the required reductions,
while Prairie State believes that Board should adopt the CAMR trading provisions and layer the
Illinois rule on top of trading. As to Kincaid’s assertion that the Board will be “guessing” that
technology will develop to achieve an absolute emissions limit, the Board disagrees. As
discussed above, the Board has ample evidence to demonstrate that HCI, either alone or with
other technologies, can achieve 90% reduction of mercury. Further, the Board finds no merit in
Kincaid’s suggestion to include specific language in the proposed regulations allowing affected
plants to seek an adjusted standard or a site-specific rule; the proposed regulations do not
prohibit an owner or operator of a power plant from seeking site-specific relief pursuant to
Sections 27 or 28.1(c) of the Act. Therefore, the Board does not share Kincaid’s concerns about
absolute emissions limitations.
Because the Board believes that 90% reduction can occur, given the record before the
Board concerning the state of the technology, the Board does not see the need to consider a
trading program for mercury emissions. And, as will be discussed below, the Board also does
not believe that there will be an issue for Illinois to achieve the CAMR budgeted limits.
Therefore, trading will not be included in the rule.
Board Conclusion.
The Board finds that the record demonstrates that the mercury
emissions controls proposed in the rule are technically feasible. The Board has found evidence
that the affected utilities are afforded a number of alternative options to comply with the
proposed mercury limitations, including control technology, co-benefits, averaging, and TTBS.
Regarding mercury control technology, the Board finds that sorbent injection with halogenated
PAC or HCI is technically feasible for PRB coal-fired units with cold side ESPs to comply with
the proposed mercury limits. Field tests at multiple sites have demonstrated that 90% removal is
37
achievable over 30-day testing and although short-term testing is not always optimal, in this
instance, the testing is sufficient to demonstrate technical feasibility. The evidence in the record
does not support potential problems with particulate matter or concerns about the size of the
SCA. The technologies are commercially available from several vendors and at least one vendor
testified in the proceeding and will provide guarantees for 90% removal.
In addition, the Board finds that co-benefits achieved through the use of FGD, SCR or
selective non-catalytic reduction (SNCR), and installation control equipment including fabric
filters are technically feasible options for EGUs utilizing coal type and control configurations
other than PRB coal-fired units with cold-side ESPs. Also, the rules allow sufficient time for
plant operators to install control equipment and optimize operations to comply with the mercury
emissions limits. And finally, the record demonstrates that an absolute emissions rate is viable,
can be achieved and trading is not necessary.
Measurement of Mercury Removal
In this section of the opinion, the Board will summarize the concerns of the participants
regarding the measurement of mercury removal. After summarizing the comments, the Board
will discuss the comments and the record in the proceeding and make a finding regarding the
technical feasibility of measuring mercury levels required by this rulemaking.
Midwest Generation’s Comment
Midwest Generation argues that mercury removal cannot be precisely, consistently, and
continuously measured. PC 6300 at 41. Midwest Generation asserts that for a rule to be
technologically feasible, the affected sources must be able to know if they are in compliance.
Id
.
The rule requires removal of mercury at a rate of 90% and the rate is not based on emissions
factors, but on actual measurement.
Id
. Midwest Generation points to testimony from Mr.
McRanie that the minute levels of mercury that must be measured to demonstrate compliance
with this rule cannot be accurately measured. PC 6300 at 41-42. Midwest Generation maintains
that the mercury levels are less than the trace level of the measurement devices. PC 6300 at 42.
Midwest Generation notes that Mr. McRanie distinguished between detecting mercury
and measuring mercury and pointed out that the precision and accuracy of measuring mercury at
the levels required by the rule “are unknown because such data do not exist.” PC 6300 at 42,
citing CTr. at 1724-2715. The applicable federal monitoring rules, which are incorporated in this
rule by reference, allow ±1.0
μg/m
3
error in calibrating the measurement instruments. PC 6300
at 42, citing Exh. 133 at 6. Midwest Generation asserts that this allowable error is greater than
the emissions standard of .0080 lb/GWh or 0.80
μg/m
3
. PC 6300 at 42, citing Exh. 133 at 2.
Midwest Generation maintains that requiring that an emissions limit not exceed a level that is
lower than the measurement error is not technically feasible. PC 6300 at 42.
Mr. McRanie opined that based on field observations the precision of mercury
measurement is actually more in the range of ±0.5
μg/m
3
. Midwest Generation maintains that if
the true value of mercury emissions is 0.80
μg/m
3
the continuous emissions monitoring system
(CEMS) might read anywhere from 0.0 and 1.3
μg/m
3
with no calibration error. PC 6300 at 42.
38
Midwest Generation points to test results from Mr. McRanie comparing mercury analyzers
operated during the best months and asserts that the results confirm that measurement precision
does not support the proposed rule.
Id
.
Midwest Generation raises concerns about using a measurement method developed for a
cap and trade program, like the federal CAMR, in a rule that requires command and control, like
the proposed rule. PC 6300 at 43. Midwest Generation notes that if a measurement method is
inaccurate or biased, under a cap and trade system, the worst scenario is that a unit would need to
buy additional allowances if needed.
Id
. Midwest Generation argues that however, under
command and control, the inaccuracy could lead to civil and criminal penalties and the Agency
has presented no answer to that.
Id
.
A second problem pointed to by Midwest Generation is one arising from the
measurement method and the missing data substation provisions of the federal rules. PC 6300 at
43. According to Midwest Generation the federal regulations target 100% data capture and
impose increasingly “draconian substitute data requirements” where data is not available. PC
6300 at 43, citing 40 C.F.R. § 75.33. Midwest Generation notes that this substitution
requirement has been typical of cap and trade programs. PC 6300 at 43. Midwest Generation
notes that according to Mr. McRanie, USEPA “long ago determined that missing data
substitution is inappropriate” for command and control regulations. PC 6300 at 43, citing Exh.
132 at 3, 36-36.
Lastly, Midwest Generation states that there is a problem with percent reduction which
requires accurate measurement of mercury in the coal and mercury in the stack. PC 6300 at 43.
Midwest Generation reiterates that CEMS is inaccurate, but also asserts there are problems with
measurement of input mercury. PC 6300 at 43-44. Mr. McRanie pointed to problems in
determining the input mercury, the amount of mercury in the coal burned, and with the coal
sampling requirements in the rule. PC 6300 at 44, citing Exh. 132 at 36-37. A particular
concern of Mr. McRanie’s according to Midwest Generation is the lack of methodology in the
proposal for calculating input mercury.
Id
.
Midwest Generation asserts that the inaccuracies of CEMS and imprecision in the
approach to coal sampling will compound themselves and produce unreliable results. PC 6300 at
44. Midwest Generation maintains that even if both input and emissions could be measured
accurately, the fact that input is measured on a daily basis with one grab sample, while emissions
are determined from CEMS could distort the results.
Id
. Midwest Generation argues that if the
single grab sample yielded a lower than actual mercury content rate, then proving 90% removal
might be difficult, even though the source might actually be reaching the result.
Id
.
Midwest Generation argues that mercury monitoring technology is also evolving. PC
6300 at 44. Currently, mercury monitoring equipment can experience downtimes 50-70% of the
time, falling far short of 100% data capture.
Id
. Mr. McRanie believes that monitoring will
improve, but the obvious problems have been addressed and the remaining issues will be more
difficult absent a breakthrough in technology. PC 6300 at 44-45, citing CTr. at 1695-96.
Prairie State’s Comment
39
Prairie State asserts that currently there are many questions about USEPA’s monitoring
requirements and whether CEMS can accurately measure mercury emissions at the levels
necessary to demonstrate compliance. PC 6294 at 9. Prairie State points to Mr. McRanie’s
testimony concerning CEMS and demonstrating compliance with CAMR, much less the more
stringent Illinois proposal.
Id
. Prairie State notes that the USEPA measurement requirements
are currently being challenged in federal court and there may be changes to the measurement
requirements.
Id
. Prairie State recommends that the Board incorporate USEPA’s monitoring
requirements by reference and not include specific mercury monitoring requirements. PC 6294
at 10.
Agency’s Comment
The Agency states that while the proposed rule has many differences from CAMR, the
proposed rule is identical to CAMR concerning emissions monitoring. PC 6298 at 33. The
Agency argues that Mr. McRanie claimed that the monitoring of mercury emissions was
problematic; however, he conceded that the requirements in Illinois were the same as those
required by CAMR.
Id
. The Agency asserts that since Illinois sources would be subject to the
same mercury monitoring requirements whether or not the Board promulgates the proposed rule,
Mr. McRanie’s comments are “essentially a non-issue.”
Id
.
The Agency notes that Mr. McRanie provided similar comments to USEPA during the
CAMR rulemaking process and USEPA finalized the rules containing mercury monitoring
requirements anyway. PC 6298 at 33. The Agency asserts that Mr. McRanie’s objectivity on
this issue is in question and he was unfamiliar with parts of the Agency’s proposal designed to
address potential monitoring issues such as averaging. PC 6298 at 34. The Agency maintains
that Mr. McRanie conceded that mercury monitoring technology was improving and more
improvement is expected before the Illinois rules become effective. PC 6298 at 35.
The Agency provided as part of the final comment a document from USEPA’s Clean Air
Markets Division entitled
Mercury Emissions Monitoring Program For Coal-Fired Boilers
under the Clean Air Mercury Rule, Status Report, August 2006
. PC 6298, Attach 1. According
to the Agency, this document indicates that monitoring equipment is improving in performance
and reliability and precision in CEMS have improved dramatically. PC 6298 at 35. The Agency
notes that the document states that mercury monitoring technologies continue to advance at a
rapid rate and are on track to meet the CAMR requirements. PC 6298 at 35-36. USEPA also
does not see a problem with the number of units available for use.
Id
.
In addition to the USEPA document, the Agency points to the Thermo Electron mercury
monitoring brochure, which promises that the monitors are easy to use and maintain. PC 6298 at
36, citing Exh. 133. EPRI documents also indicate that by 2007 commercially offered CEMS for
mercury will be accurate and field ready. PC 6298 at 36-37, citing Exh. 137. Thus, the Agency
argues that the Board should discard Mr. McRanie’s entire testimony. PC 6298 at 38.
The Agency notes that none of the potentially affected sources provided prefiled
testimony concerning the use of sorbent traps technology for measurement of mercury emissions,
40
and Mr. McRanie admitted that he was asked only to address CEMS. PC 6298 at 38. The
Agency argues that the fact remains that sorbent trap technology is an acceptable alternative to
CEMS and EPRI is a supporter of sorbent traps.
Id
. EPRI is working with vendors on a 2007
deliverable that includes a commercially available, reliable sorbent trap mercury measuring
system.
Id
. The Agency asserts that the information from EPRI indicates that sources could
save up to $80,000 over CEMS. PC 6298 at 39.
The Agency argues that aspects of the proposed rule are similar to a trading rule and
therefore data substitution is acceptable. PC 6297 at 39. The Agency notes that the proposal
allows averaging, which Mr. McRanie agreed was “in conceptual thought” similar to trading.
Id
,
citing CTr. at 1749. Further, Mr. McRanie admitted being unfamiliar with certain parts of the
proposed rule including the averaging provisions. PC 6297 at 40, citing CTr. at 1747-48, 1754.
The Agency also pointed out that Mr. McRanie admitted that without the use of data substitution
companies faced with possible noncompliance could avoid accounting for excess emissions and
avoid the intent of the regulation. PC 6297 at 40, citing CTr. at 1772.
Board Discussion of Measurement of Mercury Removal
Before addressing the arguments made concerning CEMS, the Board notes that the
proposal incorporates the USEPA provisions for mercury monitoring and the provisions are
nearly identical.
See
Prop. at 42. Prairie State has suggested that the Board simply incorporate
the USEPA rules without including specific mercury monitoring requirements in the proposed
rule. The Board has reviewed the Part 75 rules and the Agency’s proposed rules. The Board is
not convinced that the minor differences warrant a change in the language. Further,
incorporation of the Part 75 rules may not alleviate the concerns of Prairie State as the APA
requires that incorporations be date-specific. Accordingly, changes to Part 75 will not be
automatically included in Board rules.
See
1 Ill. Adm. Code 100.385; 5 ILCS 100/5-75 (2004).
Since the proposed intent of monitoring requirements is to track the federal rules, the Board
expects the Agency to propose amendments to the monitoring provisions if the federal rules are
revised as a result of a court decision.
The issues raised by Midwest Generation and Prairie State concerning measurement of
mercury removal are all directed at the use of CEMS. Further, both Midwest Generation and
Prairie State rely on the testimony of Mr. McRanie. However, the Board has concerns about the
testimony of Mr. McRanie. First, Mr. McRanie’s testimony identifies problems with CEMS that
are inherent in the monitoring and are problems the USEPA considered when adopting the
monitoring requirements that are included by reference in the proposal.
See
CTr. at 1736-37.
Mr. McRanie specifically stated that USEPA “did not do a bad job in putting those Part 75
monitoring requirements together.” CTr. at 1737,
see also
CTr. 1742.
Second, Mr. McRanie did not prefile testimony concerning the sorbent trap method for
monitoring mercury removal monitoring, which is also a part of the proposal. In fact, Mr.
McRanie stated that he was asked to address CEMS, but no one told him not to discuss sorbent
trap methodology. CTr. at 1780. Mr. McRanie did then mention that he did not find there to be
a lot of interest in using the sorbent trap methodology as a CEMS process. CTr. at 1780-81. In
the preamble to CAMR, USEPA states that mercury emissions are determined either by
41
continuously collecting mercury emissions data from each affected unit by installing and
operating a CEMS or an appropriate long-term method such as sorbent trap method. See 70 FR
28610. Further, USEPA states that sorbent trap monitoring systems may be used ‘‘across the
board,’’ provided that rigorous quality assurance (QA) procedures are implemented. These QA
requirements are found in 40 C.F.R. 75.15 and in 40 C.F.R. part 75.
See
70 Fed. Reg. 28631.
The Board is also concerned that Mr. McRanie was unfamiliar with the portions of the
proposal that would allow averaging both systemwide and on a 12-month rolling basis.
See
CTr.
at 1747-48. Because of his unfamiliarity with the averaging provisions of the proposed rules,
Mr. McRanie’s testimony about the substitution of data was less helpful to the Board, as the
Board observes similarities between averaging in this proposed rule and trading rules. The
Board agrees with the Agency that aspects of the proposed rules do not require compliance with
a hard cap limit on emissions at all times, which is similar to a trading rule. Further, similar to
the proposed rules, CAMR also requires compliance with the final standard of performance for
mercury to be determined on the basis of a rolling 12-month average calculation.
Id
. Therefore,
the Board finds that data substitution provisions prescribed in the federal rules are appropriate for
addressing data handling under the proposed regulations.
In summary, the Board is presented with a rule, identical in substance to federal
requirements for mercury monitoring. USEPA examined the technology available and
determined what methods were appropriate. Also, both USEPA and EPRI, an organization for
which Mr. McRanie works, believe that problems with CEMS can be corrected and that the
equipment will be available by 2009. Further, the Agency provided evidence that at least one
supplier disputes some of Mr. McRanie’s positions.
See
Exh. 134.
Board Conclusion.
While Mr. McRanie testified about problems with CEMS,
contrasting evidence includes the USEPA’s decision to adopt the Part 75 monitoring
requirements and evidence that contradicts some of Mr. McRanie’s testimony. Based on the
evidence in the record, the Board finds that mercury monitoring technology is technologically
feasible. The Board also finds that the technology is currently available. Therefore, the Board
will proceed to second notice without substantively amending the monitoring requirements in the
proposal.
Flexibility
In this section the Board will summarize the concerns of the participants regarding the
flexibility of the proposal including the inclusion of the MPS. After summarizing the comments,
the Board will discuss the comments and the record in the proceeding and make a finding
regarding the technical feasibility of the flexibility of the proposal including the MPS and TTBS.
Midwest Generation’s Comment
Midwest Generation asserts that the “flexibilities” provided for in the proposal as
amended do not cure the problems with HCI and are not truly flexibilities. PC 6300 at 3. The
four flexibilities discussed by Midwest Generation are:
42
1.
12-Month Rolling Averaging
2.
Systemwide Averaging Demonstrations
3.
Temporary Technology Based System (TTBS)
4.
Multi-pollutant System (MPS). PC 6300 at 19-34.
Each of these presents some problems, according to Midwest Generation.
Id
.
12-Month Rolling Averaging.
Midwest Generation concedes that compliance with a
12-month rolling average might be easier than compliance with an instantaneous standard;
however, the use of the 12-month rolling average does not eliminate concerns about HCI
achieving a 90% reduction. PC 6300 at 19. First, Midwest Generation asserts that the target
control level for the EGUs must be greater than 90% to maintain compliance.
Id
. Midwest
Generation states that this is obvious mathematical logic if an average is used to show
compliance because the assumption is that at times you will be over and at times you will be
under the average.
Id
. Thus, Midwest Generation argues the actual target for emissions
reductions must be greater than 90%.
Id
. Midwest Generation argues that the 30-day test
demonstration generally did not establish an average reduction rate of 90%. PC 6300 at 20.
A second problem with the 12-month rolling average, according to Midwest Generation
is with the measurement. PC 6300 at 20. As discussed above, Midwest Generation argues that
measuring 90% removal is difficult so measuring more than 90% is even more difficult.
Id
.
Midwest Generation objects to the emissions reduction standard, not that the compliance
determination is expressed as a 12-month rolling average, because the 90% reduction is not
technically feasible.
Id
.
Systemwide Averaging Demonstrations.
Midwest Generation maintains that
systemwide averaging also does not allow real flexibility for several reasons. PC 6300 at 20.
First, Midwest Generation notes that this demonstration applies only to companies with multiple
sources although a provision is included for so called orphan sources.
Id
. Midwest Generation
argues that the orphan sources provision is “specious” because one of the companies listed is part
of Ameren and a second source has agreed to extensive controls in new permits (City Light &
Power of Springfield (CWLP)). PC 6300 at 20-21. This leaves Southern Illinois Power
Cooperative (SIPC ) and Kincaid. PC 6300 at 21. SIPC is a very small (290 MW) when
compared to Kincaid (1320 MW).
Id
. Midwest Generation notes that both plants have some
controls in place that will remove mercury, but given the disparity in sizes Midwest Generation
does not believe that Kincaid would benefit from averaging with SIPC .
Id
. Midwest Generation
asserts that because of this limitation, the rule of general applicability precludes one plant from
participating because of circumstances of ownership.
Id
.
Midwest Generation asserts that the averaging demonstration assumes that there is an
ability to average and that the reductions can be measured. PC 6300 at 22. Midwest Generation
notes that the averaging demonstration requires at least a 75% reduction for each source
participating and this would suggest the averaging would be used to reach 90% reduction.
Id
.
To achieve 90% reduction systemwide, would then require other plants to achieve reductions of
well over 90%, argues Midwest Generation.
Id
. Midwest Generation gives as an example the
Powerton Plant, Midwest Generation’s largest, and notes that if that plant achieves the 75%
43
reduction necessary for averaging, Midwest Generation’s other plants in Illinois would need to
average 96% removal.
Id
. Midwest Generation maintains that those plants would need to have a
target reduction of 98% and even short-term tests have not achieved that level of reduction.
Id
.
TTBS.
Midwest Generation argues that the TTBS does not afford “appreciable”
flexibility if any at all. PC 6300 at 23. Midwest Generation notes that to be eligible for the
TTBS, the system must be equipped with HCI and either a cold side ESP or a fabric filter and
must inject halogenated or other equivalent activated carbon at a rate of 5 lb/Mmacf for
subbituminous coal and 10 lb/Mmacf for bituminous coal.
Id
., citing Proposed 225.234(b).
Midwest Generation opines that the system must be equipped with the same emissions control
hardware and operated in the same manner as the control and operation that the Agency asserts
will achieve 90% reduction.
Id
. Midwest Generation asserts that the inclusion of the TTBS
“suggests that the Agency is not as confident of the ability of the technology” as the Agency
would have the Board believe.
Id
.
Like averaging, Midwest Generation notes that Kincaid cannot use the TTBS because of
the size of Kincaid’s units (CTr. at 1847-48) and CWLP and SIPC are also unlikely to use the
TTBS. PC 6300 at 23-24. Midwest Generation has two units that could benefit from a TTBS-
type flexibility; however, both units have hot side ESPs. PC 6300 at 24. Midwest Generation
concedes that installation of fabric filters on these two units could achieve compliance, if the
measurement concerns were alleviated.
Id
.
MPS.
Midwest Generation articulates five issues that Midwest Generation believes the
addition of the MPS creates. PC 6300 at 26. Those issues are:
1.
that the companies that co-sponsored the MPS with the Agency believe
that compliance with the underlying rule is not technically feasible and/or
economically reasonable;
2.
that the companies that co-sponsored the MPS with the Agency are very
concerned with the financing and timing of installation of the equipment
that would be necessary to comply with the underlying rule;
3.
whether it is appropriate for the Agency to require NO
x
and SO
2
emissions
limitations in this mercury rulemaking, which it claims in the Joint
Statements will affect how the Agency approaches so-called “post-CAIR”
emissions reductions necessary for the state to demonstrate attainment of
the ozone and PM
2.5
NAAQS when the Agency has presented no support
or information in this regard in this rulemaking proceeding;
4.
whether the Board has the authority to regulate SO
2
in a rule of general
applicability, given the prohibitions of Section 10 of the Act; and
5.
whether it is constitutional for the Agency to prohibit participation in
national trading programs. Including NO
x
and SO
2
provisions is
inappropriate, even in a section represented to be voluntary, in a mercury
rule, and it is unconstitutional for the Board to interfere with national
emissions trading programs. PC 6300 at 26.
44
The Board will address the legal issues raised in points three, four, and five later in this opinion
(
see supra
at 78). The issues of the economic reasonableness will also be discussed below (
see
supra
at 54). In this section, the Board will summarize the argument regarding technical
feasibility.
Midwest Generation points out that Mr. Menne testified in support of the MPS, stating
that Ameren was not confident that HCI alone would ensure that Ameren could comply with the
90% reduction. PC 6300 at 26, citing CTr. at 169. Mr. Menne indicated that Ameren would
need to add baghouses or fabric filters at each unit still burning bituminous coal in order to
comply. PC 6300 at 26, citing CTr. at 159. Mr. Menne indicated that Ameren will not tolerate
or risk noncompliance. PC 6300 at 27, citing CTr. at 100. Midwest Generation shares Ameren’s
view that compliance is important and states that “companies cannot share in the Agency’s
cavalier view that a technology that works some of the time” is adequate to support a rule that
imposes compliance obligations. PC 6300 at 27.
Midwest Generation argues that “none of the companies” believe that reliance on HCI
alone will achieve compliance with the proposed rule. PC 6300 at 27. Further, Midwest
Generation states that “all of the companies” have confidence that the co-benefits of NO
x
and
SO
2
control equipment are necessary to achieve compliance with the mercury reductions
proposed in this rule.
Id
. Midwest Generation maintains that the USEPA also recognized
the co-benefits and expected companies to coordinate CAIR and CAMR controls.
Id
.
Midwest Generation asserts that the implication of the proposed MPS is that Dynegy and
Ameren, companies representing over half the generating capacity in the State, cannot
comply with the rule in the manner proposed within the timeframes proposed.
Id
. Midwest
Generation argues that, as a result of the Agency’s support, the Agency too finds that “as a
rule of general applicability, the underlying rule is not technically feasible.”
Id
.
Kincaid’s Comment
Systemwide Averaging.
Kincaid argues that the provisions for systemwide averaging
creates an “unequal, unfair playing field” for Kincaid due to the smaller pool of units eligible for
inclusion in an averaging demonstration with Kincaid. PC 6299 at 15. Further, Kincaid
maintains that Kincaid will be forced into a “sellers market” in trying to strike a deal with
another company that may have no incentive for participation.
Id
. Kincaid notes that for larger
companies as many as 19 units could be included while Kincaid is allowed to average with far
fewer units.
Id
.
TTBS.
Kincaid argues that the TTBS does not offer flexibility for Kincaid because of
the design of Kincaid’s power plant. PC 6299 at 11. Kincaid’s two units are 625 megawatt
units. PC 6299 at 15. Kincaid expects the emissions from both units to be identical and does not
expect one unit to meet a more stringent requirement. PC 6299 at 11. Because the proposed
TTBS limits availability to no more than 25% of the company’s capacity in the State, Kincaid is
specifically excluded from the provisions of the TTBS. PC 6299 at 15. Kincaid notes that the
Agency agrees with that assessment of the TTBS. PC 6299 at 16. Further, because Kincaid
expects the emissions to be identical from the two units, expansion of the TTBS to include
Kincaid would provide relief to Kincaid. PC 6299 at 11.
45
MPS.
Kincaid argues that the agreements struck by Ameren, Dynegy, and the Agency
effectively allow more than 8000 megawatts of coal-fired generation in Illinois to avoid the 90%
reduction requirement until 2015. PC 6299 at 3. Kincaid notes that this is more than 50% of the
coal-fired generation in Illinois.
Id
. Kincaid states that the MPS has been designed to
accommodate the exclusive needs of Ameren and Dynegy and makes no attempt at universal
appeal or feasibility. PC 6299 at 12.
Kincaid asserts that the MPS forces emissions reductions at the Ameren and Dynegy
plants that are well underway at other plants. PC 6299 at 12. Kincaid points out as an example
that Kincaid has had declining NO
x
and SO
2
emissions since 1998.
Id
. Kincaid maintains that
the NO
x
emissions from Kincaid are the lowest rate for a coal-fired utility in Illinois.
Id
.
Kincaid expects the NO
x
emissions in 2009, after the SCRs are operated on a year round basis, to
be comparable to or lower than the NO
x
limit of the MPS effective in 2012.
Id
.
Kincaid argues that the SO
2
emissions rate are even more impressive and are as low as
any other coal-fired utility in Illinois for 2002-2004. PC 6299 at 13. Kincaid opines that the SO
2
emissions reductions achieved by the units in the MPS will need more than ten years to achieve
the same reductions in SO
2
emissions that Kincaid has made since 1998. PC 6299 at 14.
Kincaid argues that for facilities like Kincaid that have already reduced NO
x
and SO
2
emissions,
additional percentage deductions like those proposed in the MPS, are not technically feasible or
economically reasonable.
Id
.
CWLP’s Comment
CWLP limited the final comment to issues concerning the MPS. PC 6296 at 2. CWLP
argues that the MPS is unclear as to whether EGUs scheduled for permanent shutdown are to be
considered in the calculation of the base emissions rate.
Id
. CWLP asserts that a plain reading
of Sections 225.233(a)(3)(B) and 223.235 suggest that the base emissions rate calculation does
not include EGUs scheduled for shutdown. PC 6296 at 2-3. CWLP argues that EGUs scheduled
for shutdown should be included otherwise the additional emissions reductions required by the
MPS could not be achieved. PC 6296 at 3. CWLP offers language to amend the rule to allow
for inclusion of EGUs scheduled for shutdown.
Id
.
CWLP also is concerned that the MPS could negatively impact new EGUs because of the
requirement to surrender allowances for retirement. PC 6296 at 4. CWLP argues that the
Agency should allow the transfer of allowances to new EGUs at the same existing source that are
prevented by definition from joining the MPS.
Id
.
Prairie State’s Comment
TTBS.
Prairie State argues that because of the lack of long-term data, a technology
based standard must be included in the rule. PC 6294 at 10. Prairie State believes that such a
standard is necessary to bridge the gap between what technologies are capable of in 2009 versus
2018.
Id
. Prairie State concedes that the short-term tests may be promising; however, the tests
are insufficient to conclude that the standards proposed can be sustained on a daily basis.
Id
.
46
Prairie State asserts that USEPA took into account timing in adopting CAMR, while the Agency
did not. PC 6294 at 11. Prairie State argues that a rule requiring compliance in 2009 will have
to be based on technology available today given permitting, procurement and installation issues.
Id
. Prairie State opines that if the Agency is correct and the technology will be capable of 90%
reduction, a technology based standard may never need to be used.
Id
. However, Prairie State
believes that without a technology based standard, facilities will be “required to shut down,
greatly curtail operations, or face enforcement actions” because the facilities cannot comply with
the standards.
Id
.
Prairie State believes that the TTBS needs improvement and delineates five different
areas of concern. PC 6294 at 11-15. First, Prairie State argues that eligibility should not be tied
to the use of a particular sorbent as such language is too restrictive and ignores new technologies
and reagents. PC 6294 at 12. Prairie State argues that the preliminary data on high sulfur coal
indicated that halogenated activated carbon may be less effective than other activated carbons
and the rule should not require an EGU to go through an alternative process to use other
sorbents.
Id
. Prairie State opines that the rule should allow the Agency to approve sorbents and
allow an EGU to use such approved sorbents.
Id
. Prairie State suggests language to reflect this
idea.
Id
.
Second, Prairie State asserts that the TTBS should allow an optimization study to
determine the optimum injection such as the one Prairie State performed in its construction
permit. PC 6294 at 11. An optimization study would allow for consideration of variables that
affect mercury removal and Prairie State argues that it is unclear if variables were considered in
the proposed TTBS.
Id
. Further, Prairie State asserts that the provisions of Prairie State’s
construction permit should be an acceptable alternative to the default rates in the TTBS.
Id
.
New facilities, whose construction permits already include a provision regarding mercury control
and the use of sorbent, should not be required to repeat the permitting process under a TTBS. PC
6294 at 13.
Third, Prairie State believes that the TTBS should allow for a lower injection rate if
particulate matter emissions are adversely impacted. PC 6294 at 13. Prairie State acknowledges
that new units should not have the same particulate control device size concerns as existing units;
new units may still experience problems given the lack of long-term data.
Id
. Prairie State also
recommends that “safety issues” be added as a basis for lowering injection rates, given the
testimony concerning a fire at a TOXECON baghouse. PC 6294 at 13-14.
Fourth, Prairie State has some confusion regarding the requirement to record the
activated carbon feed on an hourly average basis. PC 6294 at 14. Prairie State asserts that there
does not seem to be a rationale for requiring a facility to average the activated carbon feed on an
hourly basis.
Id
. Further, Prairie State maintains that as the mercury content of coal cannot be
feasibly monitored and recorded on an hourly basis, knowing the injection rate will provide no
useful information.
Id
.
Fifth, Prairie State is concerned about potential timing issues with the TTBS. PC 6294 at
14. Specifically, Prairie State notes that under Section 225.237 compliance with the proposed
standard commences on the date of the initial performance test.
Id
. Prairie State further notes
47
that application for the TTBS must be made at least three months prior to compliance with
Section 225.237 has to be demonstrated and must be included in a Title V permit.
Id
. Prairie
State maintains that theoretically a facility would need to submit the Title V application to
comply with the TTBS three months after initial start-up and before the compliance period is
complete.
Id
. Prairie State recommends that the rule be clarified.
Id
.
MPS.
Prairie State argues that the proposed MPS may have serious consequences for
new facilities within Illinois. PC 6294 at 15. Primarily, Prairie State is concerned about the
availability of SO
2
and NO
x
allowances for new facilities.
Id
. Prairie State asserts that if a
majority of existing units sign up for the MPS, the pool of available allowances will be
substantially reduced.
Id
. Prairie State suggests that the Agency make those relinquished
allowances available to new facilities for purchase.
Id
.
IERG’s Comment
MPS.
IERG filed a comment on behalf of IERG’s member companies, not participating
in the negotiations regarding the MPS. PC 6302 at 1. IERG notes that the Agency at hearing
testified that the protective language regarding further reductions of NO
x
and SO
2
emissions was
limited to coal-fired EGUs choosing the MPS compliance standards. PC 6302 at 2-3. IERG’s
understanding of this language and testimony is that the Agency would look to EGUs not
following the MPS and/or non-EGUs to achieve further reductions in NO
x
and SO
2
emissions.
PC 6302 at 3. IERG is seeking further clarification on this point.
Id
.
IERG has supported the CAIR/CAMR mercury emissions reductions and views the MPS
as a natural extension of the co-benefit model of CAIR/CAMR. PC 6302 at 3. IERG maintains
that the rulemaking as originally proposed did not appear to contemplate such an approach and
while IERG understands the inclusion of compliance alternatives and the co-benefits that NO
x
and SO
2
emissions reductions provide, the Agency originated separate regulatory paths for the
control of mercury. PC 6302 at 3-4. IERG is concerned that the proposed MPS could have
implications for other sources and IERG is not certain that the other sources have been made
fully aware of these implications. PC 6302 at 4. IERG asks that the Board seek clarification
from the Agency as to the implications of the MPS to other sources of NO
x
and SO
2
emissions.
PC 6302 at 4-5.
Ameren’s Comment
Ameren argues that compliance with the proposed rule with the addition of the MPS is
technically feasible and economically reasonable and the extensive record fully supports the
adoption of the rule as amended by the MPS. PC 6301 at 1, 7. Ameren asserts that the proposed
rule as amended by the MPS balances the Agency’s environmental goal of establishing effective
mercury controls while supporting industry’s goal of a more stable and certain regulatory
framework.
Id
. Ameren maintains that only Midwest Generation and SIPC have indicated
continued objection to the proposed mercury rule and unlike Ameren, Dynegy and Kincaid have
failed to prove any alternative proposals or amendments. PC 6301 at 6. Ameren argues that
Midwest Generation and SIPC did not present any witnesses from their own respective
companies to testify regarding how the proposed rule will directly impact their companies.
Id
.
48
Ameren asserts that a multi-pollutant approach for controlling emissions of mercury, NO
x
and SO
2
is advantageous over the traditional, single pollutant scheme. PC 6301 at 7. Ameren
states that since reduction of mercury emissions can be obtained as co-benefits from the control
of NO
x
and SO
2
emissions, allowing companies to synchronize the control of these emissions is
important for environmental regulations directed at EGUs.
Id
. Ameren indicates that
evaluations performed by Ameren and consultants for Ameren revealed that mercury emissions
reductions that would approach 90% using current technologies would require either a FGD/SCR
system for units burning bituminous coal, or a fabric filter plus sorbent injection for units
burning subbituminous coal.
Id
. Ameren argues that the installation of fabric filters is more
expensive than an ACI-halogenated sorbent system, and Ameren therefore decided that mercury
control would need to be coordinated with the company’s overall NO
x
and SO
2
emissions
reduction strategy. PC 6301 at 7-8.
Ameren developed the alternative MPS proposal of general applicability that would
reduce mercury emissions to satisfy the Agency’s original proposal while making substantial
reductions in NO
x
and SO
2
emissions. PC 6301 at 8. Mr. Menne testified that the MPS
provisions allow an additional level of flexibility for mercury control, if a source commits to
making specified reductions in NO
x
and SO
2
emissions within a set timeframe.
Id
. Mr. Menne
indicated that the MPS will require 90% reduction on most units on a timeframe extended by
only three years while requiring reductions in NO
x
and SO
2
emissions beyond those required by
CAIR.
Id
. Ameren asserts that Illinois EGUs electing to comply with the proposal using the
MPS will provide an additional health benefit not initially anticipated by the proposed rule.
Id
.
Ameren argues that the MPS is generally available to all EGUs in Illinois and even if all
the EGUs chose to take advantage of the MPS, the mercury emissions will be under the state
mercury caps imposed by CAMR. PC 6301 at 9. Ameren notes that both Dynegy and Ameren
testified that the MPS is technically feasible and both plan to take advantage of the MPS. PC
6301 at 9-10. Further, Ameren argues that even if other EGUs determine that the MPS is not
technically feasible for their systems, the proposed rule allows them to utilize either the TTBS,
the output based standard or the percent reduction standard to attain compliance with the
Agency’s proposed mercury rule. PC 6301 at 10.
Impact on CAIR Proceeding.
Ameren responded to questions posed at the close of the
Chicago hearing and indicated that nothing in the MPS limits in any way the Board’s authority to
adopt NO
x
and SO
2
emissions limits in the up coming CAIR rulemaking or any future
rulemaking. PC 6301 at 10. Ameren argues that if the Board adopts the MPS, nothing requires a
determination by the Board that the control of NO
x
and SO
2
emissions is sufficient to attain
CAIR or future nonattainment limits.
Id
. Ameren asserts that there is no conflict between the
MPS provisions and the pending CAIR rulemaking and the Board’s authority is in no way
prejudiced by the MPS amendments. PC 6301 at 11. Ameren maintains that the MPS is one
envisioned by both USEPA and supported by the Lake Michigan Air Director Consortium.
Id
.
Ameren points out that even Mr. Cichanowicz’s testimony supports a multi-pollutant strategy.
PC 6301 at 12.
Environmental Advocates’ Comment
49
Environmental Advocates argue that the proposal contains at least nine features which
offer flexibilities. PC 6297 at 9. Environmental Advocates note that very few of the opponent’s
experts include any of these flexibility mechanisms in their testimony. PC 6297 at 11.
Environmental Advocates list those nine features as:
1.
allowing a regulated entity to choose to comply using an output-based
standard or a percentage reduction;
2.
allowing a regulated entity to elect to comply using any combination of
techniques and technologies to meet an output-based or reduction
standard;
3.
providing regulated entities with almost three years before compliance is
required;
4.
allowing compliance to be determined on a 12-month rolling average;
5.
allowing owners of multiple EGUs to choose to comply by averaging
among units during the first phase of the regulatory phase (through 2013),
and allowing owners of single EGUs to average with other similarly
situated operators;
6.
allowing a complete op-out for units the regulated entity decides to
shutdown;
7.
allowing a regulated entity to choose to use the TTBS to set aside 25% of
its units from meeting a numeric standard until 2015, upon a showing that
these units are optimizing ACI mercury control equipment and meeting
other operational requirements;
8.
allowing a regulated entity to choose an integrated pollution control
strategy which will control mercury and other pollutants through the MPS;
and
9.
providing for the same alternative mercury monitoring requirements
contained in the federal CAMR, including the use of sorbent trap
monitoring devises as well as newer CEMS. PC 6297 at 9-10.
Environmental Advocates argue that the proposal provides practical flexibility to
regulated entities to allow the entities to decide how to achieve the mercury reductions. PC 6297
at 11. Environmental Advocates maintains that the Board has a complete record on activated
carbon injection systems which indicates that the units can be “relatively inexpensive,” quickly
installed, installed while the plant operates, and easily integrated with existing pollution control
equipment.
Id
.
MPS and Impact on CAIR.
Environmental Advocates also responded to questions
posed at the close of the Chicago hearing. Environmental Advocates assert that the MPS is a
voluntary program and one avenue of compliance with the mercury removal standards. PC 6297
at 13. Environmental Advocates maintain that the MPS contain no mandatory NO
x
and SO
2
emissions reductions.
Id
. Further, Environmental Advocates point out that the MPS does not
dictate that companies undertaking the MPS be viewed as in compliance with CAIR.
Id
.
Environmental Advocates opine that once CAIR is adopted companies who have opted into the
MPS may in fact be in compliance with CAIR.
Id
.
50
Environmental Advocates concede that a goal of the MPS is to begin addressing CAIR
requirements in addition to mercury reductions; however, the outcome of the CAIR proceeding is
not predetermined. PC 6297 at 14. The anticipated result of the MPS is that the reduction of
NO
x
and SO
2
emissions will exceed CAIR reductions, but that is only an anticipated result,
according to Environmental Advocates.
Id
. Environmental Advocates maintain that entities
opting to comply using the MPS will still be required to comply with CAIR.
Id
. Companies will
still need to comply with cap and trade requirements of CAIR and the numeric emissions limits
of the MPS.
Id
.
Agency’s Comment
MPS.
The Agency believes that a multi-pollutant strategy can have numerous
advantages over traditional, single-pollutant schemes. For example, a MPS can increase
protection of public health and the environment, reduce pollution more cost-effectively, and offer
greater certainty to industry and regulators. PC 6297 at 44. The Agency argues that because
mercury reductions can be achieved as a co-benefit to controls installed for NO
x
and SO
2
emissions reductions, allowing companies to synchronize control of these pollutants makes
sense.
Id
.
The Agency argues that as a general matter the MPS will have no impact on mercury
control for companies that do not opt in to the MPS. PC 6297 at 57. The mercury control
requirements for companies who do not choose the MPS are the same as the requirements before
the addition of the MPS.
Id
. The Agency asserts that the MPS is simply an alternative
compliance method.
Id
. As to NO
x
and SO
2
emissions rates under the MPS, the Agency
calculated the rates for Midwest Generation and found that Midwest Generation would be
required to meet the same NO
x
emissions rates as Ameren and the same SO
2
reduction rate as
Dynegy.
Id
.
The Agency does suggest several minor changes to the language proposed in the MPS.
PC 6297 at 64-65.
MPS and Impact on CAIR.
The Agency notes that the mercury rule focuses on the
control of mercury, but contains an optional MPS that allows companies to commit to voluntarily
meet numerical standards for both NO
x
and SO
2
and in return receive additional flexibility in
complying with the mercury standards. PC 6297 at 43-44. The Agency points out that two
companies comprising over half of the coal-fired electric generating capacity in Illinois have
indicated they will use the MPS. PC 6297 at 44.
The Agency notes that both the mercury rule with the MPS and the CAIR proposal target
NO
x
and SO
2
emissions and in that respect the goals are the same. PC 6297 at 44-45. CAIR is a
cap and trade program and sources are not technically restricted in the amount of emissions they
actually emit. PC 6298 at 45-46. However, a source must hold sufficient allowances to cover
their emissions during a reconciliation period.
Id
. Allowances can come from out-of-state
sources and Illinois sources; consequently, Illinois would not be the only direct beneficiary of
emissions reductions. PC 6298 at 46. Under the MPS, sources within Illinois owned by one
51
power company will be required to meet either specific NO
x
and SO
2
numeric emissions limits
or a percent reduction. PC 6298 at 46-47. In addition, a source is not allowed to sell, trade or
bank outside of the confines of the Illinois companies any allocated allowances equal to the level
of emissions reductions needed for compliance with the MPS. PC 6298 at 47. As a result, an
amount of allowances equal to the extra reductions beyond CAIR that are a result of the MPS are
removed from trading and cannot be used in Illinois or other states.
Id
. The Agency asserts that
this ensures that the reductions provide benefits in Illinois and region wide.
Id
.
The Agency maintains that a company that opts to utilize the MPS for mercury control
must still comply with the requirements of CAIR. PC 6298 at 49. The Agency states that a
company utilizing the MPS will need to maintain sufficient allowances to meet the requirements
of CAIR and emit NO
x
and SO
2
at a level that complies with the requirements of the MPS.
Id
.
The Agency argues that compliance with both rules was contemplated and accounted for in the
MPS language.
Id
.
The Agency concedes that allowances needed to meet the MPS limits must be
surrendered; however, allowances that are a result of over compliance with the MPS can be
freely traded or banked. PC 6298 at 50. The Agency also points out that since the CAIR
requirements will be effective (2009 and 2010) before the mercury removal requirements under
the MPS, a company electing to comply with mercury removal via the MPS will need to comply
with CAIR until 2012 and 2013.
Id
. The Agency believes that once the MPS limits and CAIR
limits apply initial compliance with the MPS will result in inherent compliance with the
emissions reduction requirements of the proposed CAIR with regard to SO
2
.
Id
.
Board Discussion of Flexibility
The following discussion will be grouped in three areas. First, the Board will discuss
averaging, and then the Board will address the TTBS. Finally, the Board will discuss the issue
surrounding the MPS, including the interaction between the MPS and the CAIR rulemaking. In
this section of the opinion the Board will not address the legal issues concerning the proposal of
the MPS, those are discussed later in this opinion. The Board notes that as a general proposition,
Midwest Generation and Kincaid argue that the rule does not really offer flexibility.
Averaging.
Midwest Generation does not believe that averaging eliminates concerns
about HCI achieving 90% reduction, because to average 90% reduction mathematically, at times,
even higher than 90% reduction will be required. Midwest Generation also has concerns about
measurements of mercury reductions. Midwest Generation and Kincaid maintain that
systemwide averaging will not add real flexibility because of the over compliance which will be
mathematically required and for Kincaid, they will be forced into a seller’s market. The Board
appreciates the concerns of Kincaid and, as will be discussed in more detail below, the Board
believes Kincaid is uniquely situated in Illinois.
As to Midwest Generation’s concerns, while the Board recognizes that compliance based
on an average would involve reductions higher than 90% at some EGUs, the Board notes that the
standard also allows units with lower than 90% to come into compliance. As noted above, the
record indicates that technology capable of achieving greater than 90% mercury reductions is
52
available. Further, the Board has found that 90% mercury reductions, and monitoring
requirements for measuring such reductions to determine compliance are technically feasible.
Therefore, the averaging components of the proposal add flexibility for utilities and the Board
finds that the record supports their inclusion.
TTBS.
Both Midwest Generation and Kincaid feel that the TTBS does not really offer
flexibility. Kincaid notes that the Kincaid facility is not eligible for the TTBS, and as indicated
above, the Board will discuss the unique nature of Kincaid later in this opinion. Midwest
Generation maintains that to be eligible for a TTBS, a unit must install the same control
equipment as necessary to achieve 90% reduction. Further, according to Midwest Generation the
inclusion of the TTBS demonstrates the Agency does not believe that the rule is technically
feasible.
The Board disagrees with Midwest Generation. Simply because a rule offers flexibility
and alternative ways to achieve compliance does not mean the rule is not technologically
feasible. The Board has reviewed the record and as discussed above, the Board finds the
evidence supports the proposed standard of 90% reduction or 0.0080 lb/GWh emissions
standard. As pointed out by the Environmental Advocates, the inclusion of multiple avenues for
compliance, including the TTBS, is additional evidence to support the Board’s determination that
the rule is technically feasible.
As discussed above, Prairie State lists five particular concerns with the TTBS and
suggests language to address these concerns. The Board has reviewed the language changes
suggested and examined the language proposed. The Board is convinced that the changes
suggested by Prairie State will clarify the intent of the TTBS. Therefore, the Board will make
the suggested changes.
MPS.
Midwest Generation believes that because Ameren and Dynegy proposed the
MPS, Ameren and Dynegy do not believe the underlying rule is technically feasible. Further,
Midwest Generation believes that Ameren and Dynegy are concerned with financing and timing
of installation of equipment. Kincaid believes that the MPS is imposing emissions standards for
NO
x
and SO
2
that other companies have been adhering to and that the MPS is tailored for
Ameren and Dynegy. The Board does not share these concerns. First, as indicated above, the
record in this proceeding indicates that the Agency has always understood that mercury
reduction can be achieved through co-benefits. The Board finds that the MPS is memorializing a
type of co-benefit and that any company in Illinois may take advantage of the MPS. The MPS
simply offers companies alternatives for compliance that may be more economically reasonable.
The Agency’s final comment includes calculations for Midwest Generation and the
calculations demonstrate that if Midwest Generation were to utilize the MPS, the NO
x
and SO
2
emissions would be similar to those for Dynegy and Ameren. The decision to utilize the MPS is
voluntary and the MPS, like the TTBS, is an alternative compliance option in the rule. As the
Board stated above, the inclusion of alternative compliance options does not render the rule
technically infeasible. Furthermore, Ameren and Dynegy have specifically stated that the MPS
is technically feasible for their companies, and although Kincaid may not be in a position to
53
utilize the MPS, other companies may. Therefore, the Board finds that the rule with or without
the inclusion of the MPS is technologically feasible.
Additional concerns including the MPS involve the relationship with CAIR and with
other sources. The Agency, Environmental Advocates, and Ameren all addressed the
relationship between CAIR and the inclusion of the MPS. All point out that the MPS is
voluntary and nothing in the language of the MPS can be viewed as implying that compliance
with the MPS equates with compliance with CAIR. Further, both Environmental Advocates and
the Agency agree, that if a company utilizes the MPS for mercury control, the company must still
comply with the requirements of CAIR. Based on these discussions and the Board’s review of
the MPS language and the CAIR proposal (
See
Proposed New Clean Air Interstate Rules (CAIR)
SO
2
, NO
x
Annual and NO
x
Ozone Season Trading Programs, 35 Ill. Adm. Code 225.Subparts A,
C, D and E R06-26), the Board agrees that the proposed MPS does not conflict or in any way
abridge the Board’s authority in CAIR.
The remaining issues raised have to do with the surrendering of allowances and the
impact of the MPS on other sources. Both Prairie State and CWLP suggest that rather than
surrendering and then retiring allowances, the Agency use those allowances for new facilities.
IERG raises a concern about the language that any additional reductions will be sought from
other sources.
The Board is not convinced that requiring that allowances be surrendered and then retired
will have a detrimental impact on new facilities. Allowances for SO
2
and NO
x
will be available
pursuant to CAIR and the record in this proceeding does not support the change requested by
Prairie State and CWLP. As to the impact on other sources, any additional reductions will be
accomplished through rulemaking proceedings and at that time other sources can challenge the
changes. Nothing in the MPS automatically reduces emissions for sources that do not elect to
utilize the MPS.
The Board has reviewed the issues raised about the technical feasibility of the MPS and
inclusion of the MPS in the proposed rule. Based on the record, the Board finds that the MPS is
technically feasible and the Board will proceed to second notice with the rule including the MPS.
The Board will include the changes to the MPS suggested by the Agency in PC 6298 and agreed
to by Ameren.
Board Conclusion.
The Board finds that the rule offers flexibility allowing the regulated
community to choose alternative methods for compliance with the rule. Including alternative
compliance methods does not somehow render the underlying rule technically infeasible.
Rather, the inclusion of such flexibility solidifies the technical feasibility of the rule proposal.
Therefore, the Board finds that the proposed inclusion of alternative options for compliance is
appropriate.
Board Conclusion on Technical Feasibility
The Board finds that the proposal the Board adopts today is technically feasible. The
proposal sets forth requirements for the control of mercury emissions that are feasible and can be
54
achieved by utilities in the State. The proposal calls for measuring mercury emissions in a
manner, which is also technically feasible. Finally, the rule allows flexibility for compliance
with the emissions standards that further support the technical feasibility of the rule.
ECONOMIC REASONABLENESS
Because the opponents argue issues surrounding deposition and the modeling of
deposition of mercury, the health benefits which may be achieved by controlling mercury, fish
advisories and the economics of controlling emissions when challenging the economic
reasonableness of the proposal, the Board will address those issues in this section of the opinion.
The following will summarize the comments on each of those areas and then the Board will
discuss the findings of the Board.
Deposition and Modeling
In this section of the opinion, the Board will summarize the arguments of the participants
concerning deposition and modeling deposition of mercury. After summarizing the arguments,
the Board will discuss the issues and make findings on the issues.
Midwest Generation’s Comment
Because the Agency has justified the proposal on the basis of protecting the public health
in Illinois and eliminating mercury-impaired waters by reducing fish tissue methylmercury levels
in the state, Midwest Generation suggests that a threshold issue is “whether there is a local
impact on such methylmercury levels from power plant emissions of mercury.” PC 6300 at 64.
Midwest Generation states that, “[i]f there is no local deposition or if local deposition is not to
impaired waterbodies, reducing the emissions will not have the desired effect.”
Id
. Generally,
Midwest Generation argues that the Agency has failed to demonstrate that coal-fired EGUs are
the source of a mercury problem and that the proposal will actually reduce deposition of mercury
to the state’s waters.
Id
. at 64-65.
Specifically, Midwest Generation argues that “[t]he Agency presented no chemistry
transport or deterministic modeling data or any dispersion modeling to support its claim that
Illinois coal-fired power plants contribute to mercury deposition in Illinois waterbodies.” PC
6300 at 64. Midwest Generation notes that the Agency entered into a contract with Environ for
the performance of CAMx chemistry transport modeling to determine whether mercury
deposition from power plants contributes to impairment of Illinois waters.
Id
. Midwest
Generation argues that the Agency saw Environ’s preliminary results and then canceled the
contract because it “did not like those results.”
Id
.
Midwest Generation states that the Agency relied on the expertise of Dr. Gerald Keeler,
who testified with regard to two studies he performed: the Lake Michigan Mass Balance Study
from 1994-95 (Exh. 26), and a Steubenville study (PC 6292). Dr. Keeler also commented on a
Florida study from 2002 (Exh. 20) and a Detroit study from 2005 (Exh. 27). Midwest
Generation argues that the Agency cannot claim that the proposal will actually protect public
health in Illinois because none of the studies relied upon by Dr. Keeler show whether Illinois
55
EGU’s impair Illinois waters or whether the proposal will have an effect on the level of any
impairment. PC 6300 at 65.
Midwest Generation makes a number of points in an effort to discount the findings of Dr.
Keeler’s Steubenville study. First, Midwest Generation disputes Dr. Keeler’s view that the type
of coal burned in the vicinity of Steubenville does not matter. PC 6300 at 67-68, citing 6/15Tr.
at 115-16. Midwest Generation stresses that Illinois EGUs largely burn PRB coal, which emits
mostly elemental mercury that is less readily deposited and less likely to undergo methylation
than reactive gaseous mercury (RGM). PC 6300 at 66-67, citing Exh. 44, Exh. 127, 6/15Tr. at
34-35, 115-17. Second, Midwest Generation argues that the landscape near Steubenville
influenced the results of the study there. PC 6300 at 68. Specifically, Midwest Generation notes
that Steubenville is situated at the eastern end of Ohio River, which scarcely influences Illinois,
“with a mountain range to the east affecting weather patterns.”
Id
. With respect to this issue of
geography, Midwest Generation argues that “[t]here is nothing about the Steubenville study that
is transferable to Illinois’ circumstances.”
Id
. Third, Midwest Generation notes that Dr. Keeler
attributed a great deal of precipitation during his study to hurricane-related events, suggesting
that his findings may have been influenced by events that are not likely to be repeated.
Id
., citing
6/16Tr. at 9-10, Exh. 32. Fourth, Midwest Generation cites Dr. Peter Chapman’s examination of
mercury levels in sediment and fish relative to the location of Illinois power plants, which “found
no consistent relationship.” PC 6300 at 68, citing Exh. 129 at 7, 8/22Tr. at 47-48. Finally,
Midwest Generation notes that “the determinative or chemical transport modeling performed by
USEPA in the course of the CAMR and by AER Incorporated (AER), both in the course of the
development of comments on the CAMR and in the course of its modeling performed for this
rulemaking, predicted deposition within the range of that measured by Dr. Keeler.” PC 6300 at
68, citing Exh. 32, CTr. at 1404.
Midwest Generation also makes a number of arguments to discount the Florida study.
Midwest Generation notes that, while the area near the Everglades includes coal-fired power
plants, “the greatest number of sources and those whose mercury emissions were significantly
reduced were various types of incinerators.” PC 6300 at 69. Generally, these incinerators have a
number of features that distinguish them from power plants. Incinerators tend to burn fuel that is
“extremely variable.”
Id
. at 70. Incinerators also generally have a shorter stack height and emit
at a lower velocity, two factors influencing the height to which a plume will rise.
Id
., citing CTr.
at 1472. Also, incinerators tend to emit more RGM than power plants. PC 6300 at 70, citing
Exh. 126 at 15-16. Furthermore, Midwest Generation argues that, in terms of weather,
vegetation, area, and other factors, impaired waters in Illinois bear no resemblance to the
Everglades. PC 6300 at 71. Consequently, Midwest Generation argues that the Florida study is
“largely irrelevant” and that “there is no reason to expect similar results in Illinois.” PC 6300 at
69. “The Agency’s naked assumption that the results are transferable does not make it so.”
Id
.
Midwest Generation quickly dismisses the Lake Michigan Mass Balance Study, which
“showed typical urban contributions to atmospheric mercury levels over the Lake Michigan
basin.” PC 6300 at 65, citing TSD, App. B at 4. Midwest Generation emphasizes Dr. Keeler’s
statement that the Chicago-Gary “urban/source area contributed almost 20% of the total
deposition to Lake Michigan, and 14% to the wet deposition.” PC 6300 at 65, citing TSD, App.
B at 9. Midwest Generation further emphasizes that that the study found higher mercury levels
56
in urban areas than in rural areas. PC 6300 at 65, citing TSD, App. B at 4. Noting that Dr.
Keeler himself attributed some mercury to mobile sources (PC 6300 at 65, citing 6/15Tr. at 22),
and arguing that, as a matter of logic, Illinois mercury levels can in part also be attributed to
mobile sources, Midwest Generation insinuates that the study does not provide an accurate basis
for attributing mercury deposition to particular sources.
See
PC 6300 at 65.
Midwest Generation argues that “[t]he power generation companies presented the only
chemistry transport modeling of predicted mercury deposition in Illinois by Illinois power
plants.” PC 6300 at 71, citing Exh. 126, Exh. 127. Midwest Generation recommends that the
Board consider the results obtained by AER using a model called TEAM (Trace Element
Analysis Model). PC 6300 at 71-72. Midwest Generation argues that TEAM has been peer-
reviewed and published (PC 6300 at 71, citing CTr. at 1354, Exh. 127), has been improved
regarding atmospheric mercury (PC 6300 at 71, citing Exh. 126), yields results similar to those
obtained by USEPA using the Community Multi-Scale Air Quality (CMAQ) model (PC 6300 at
71, citing CTr. at 1355), and is consistent with the conclusion of the Steubenville study (PC 6300
at 71, citing CTr. at 1404, 1513, Exh. 127).
Midwest Generation stresses AER’s conclusion “that 19% of the mercury deposition in
Illinois is attributable to all power plants in the U.S.” PC 6300 at 73, citing CTr. at 1370-71,
Exh. 127 (emphasis in original). More specifically, argues Midwest Generation, “AER found
that the difference in deposition between the Illinois mercury rule and the 2020 CAIR/CAMR
reductions is less than 10%.” PC 6300 at 74, citing Exh. 127. Midwest Generation further
argues that AER located “no elevated concentrations of mercury predicted within the vicinity of
any of the power plants under any scenario.” PC 6300 at 74 n.38 (defining “hot spot”).
Midwest Generation argues that, in 2010, CAIR/CAMR will reduce mercury deposition
in Illinois by approximately five percent. PC 6300 at 73, citing CTr. at 1410, Exh. 127.
Midwest Generation further argues that, assuming no net change attributable to the MPS, the
Agency’s proposal would generate an additional reduction in deposition of approximately four
percent. PC 6300 at 73, citing CTr. at 1410, Exh. 127. Midwest Generation cites the testimony
of both Dr. Chapman and Dr. Charnley, who believe that this additional four percent reduction
would not measurably reduce methylmercury levels in Illinois fish tissues, would not cause any
waterbody to be removed from the state’s list of mercury-impaired waters, and would not affect
the health of Illinois citizens. PC 6300 at 73, citing 8/22Tr. at 12-15, 1660. Since Midwest
Generation claims that the Agency’s rules will not produce any of these effects, Midwest
Generation argues that “the Agency’s claimed benefits are illusory and the justification for the
proposal fails.” PC 6300 at 73.
Environmental Advocates’ Comment
The Environmental Advocates argue that both Dr. Keeler for the Agency and Mr.
Vijayaraghavan for Midwest Generation have provided support for the proposition “that
reducing mercury emissions from Illinois coal plants is likely to result in a reduction in mercury
deposition in Illinois itself.” PC 6297 at 8-9. Stressing that the Board may and will adopt
regulations that control only one source category, or emissions into a single medium, or
emissions posing a potential threat, the Environmental Advocates argue that, “when measured
57
next to the facts in the record, the Illinois EPA’s mercury pollution reduction proposal greatly
exceeds the threshold for regulatory activity.” PC 6297 at 5.
The Environmental Advocates argue that “Illinois’ coal-fired power plants are the largest
unregulated source of mercury emissions in the state.” PC 6297 at 5. The Environmental
Advocates cite a National Emissions Inventory showing that those power plants contribute as
much as 71% of mercury emissions in the state, more than the national average of a 44%
contribution.
Id
., citing 6/12Tr. at 47, TSD at 33-34. The Environmental Advocates further
argue that “[t]his fact alone, largely uncontested in this rulemaking, provides a powerful
justification for the development of an Illinois-specific rule mandating deeper, faster reductions
from this source category than required under CAMR.” PC 6297 at 6.
The Environmental Advocates rely in part on the testimony of Mr. Vijayaraghavan in
support of their claim that the Agency’s proposal will reduce mercury deposition in Illinois more
than CAMR. By 2010, argue the Environmental Advocates, Mr. Vijayaraghavan testified that
the Agency’s proposal will generate an additional 4.2% reduction in deposition compared with
CAMR and that that reduction will occur throughout the state. PC 6297 at 6, citing CTr. at 1422,
1433, 1462. In addition, the Environmental Advocates emphasize Mr. Vijayaraghavan’s
estimate that in 2010 the Agency’s proposal will reduce mercury deposition by 321 pounds more
than CAMR. PC 6297 at 7. The Environmental Advocates also rely on Dr. Keeler’s
Steubenville study attributing mercury deposition there to local and regional coal combustion
(
see
PC 6292) in support of their claim that “reducing mercury emissions from Illinois coal
plants is likely to result in a reduction in mercury deposition in Illinois itself.” PC 6297 at 8-9.
Agency’s Comment
The Agency’s TSD concedes that there remains some degree of uncertainty regarding the
manner in which atmospheric processes deposit mercury on the ground, and the Agency further
acknowledges that the issue requires additional research. TSD at 81. However, the Agency
stresses that “recent monitoring, modeling, and other research in recent years has led to an
increased understanding of the sources of mercury, the chemical transformations that affect it,
and the processes in the atmosphere that cause it to be deposited to the ground.” PC 6298 at 15,
citing TSD at 81 (§ 5.1). The Agency’s TSD concludes “that, by reducing mercury emissions
from coal-fired generating units in Illinois, the proposed Illinois EPA rule would significantly
reduce deposition of mercury in Illinois.” PC 6298 at 15, citing TSD at 81 (§ 5.1). The Agency
notes studies conducted in Florida and Massachusetts, which “showed rapid and steep declines in
measured concentrations of mercury in fish tissue when mercury emissions from nearby sources
such as incinerators and fossil fuel combustion were curtailed by regulations.” PC 6298 at 15,
citing TSD at 81-86 (§ 5.2). The Agency argues that the testimony of Dr. Gerald Keeler supports
these conclusions. PC 6298 at 15-16.
Specifically, Dr. Keeler testified regarding a multi-year source-receptor study of mercury
deposition in the vicinity of Steubenville, Ohio. PC 6298 at 16. That study collected daily
precipitation samples in 2003-2004 and then analyzed them to determine the presence of trace
elements.
Id
. The study then employed modeling to identify those elements as “fingerprints”
corresponding to various categories of emissions sources.
Id
. “To determine the direction and
58
distance from which samples arrived, the researchers used back trajectory analysis of available
weather systems.”
Id
. The Agency states that, on the basis of this study, Dr. Keeler concluded
that coal combustion sources accounted for approximately 70 percent of the wet deposition of
mercury.
Id
.,
see generally
PC 6292. “Other large industrial sources located in the area of
Steubenville were not significant contributors to mercury deposition.” PC 6298 at 16, citing
Exh. 10 at 4. The Agency further states that Dr. Keeler’s analysis showed that “a substantial
amount of the mercury deposition found at the Steubenville site was due to local and regional
sources.” PC 6298 at 16, citing Exh. 10 at 3. Regarding the form of mercury emitted by coal
combustion sources, the Agency notes Dr. Keeler’s statement that “the lifetime of elemental
mercury in the atmosphere is likely much shorter than previously believed. Thus mercury may
be deposited much closer to its source, even if emitted in elemental form, if oxidizing
compounds are present in the atmosphere.” PC 6298 at 16, citing TSD at 78.
The Agency stresses the scientific basis for Dr. Keeler’s conclusions. The Agency notes
that Dr. Keeler’s source-receptor study is empirical in nature, relying on “observation made at
sampling or receptor sites.” PC 6298 at 16-17, citing Exh. 10 at 4. The Agency further notes
that Dr. Keeler compared his methods to the source-oriented Eulerian models such as that used
by Midwest Generation’s witness, Mr. Vijayaraghavan. While acknowledging that those
Eulerian models can be useful, Dr. Keeler stated that they
are limited by the large uncertainties in emission inventories including the lack of
speciated mercury emission profiles, atmospheric mercury chemistry, and
accurate wet and dry deposition parameterizations. Receptor models differ from
source-oriented models in that they use statistical methods for which
implementation only relies upon observations of deposition at a location or
receptor. PC 6298, citing Exh. 10 at 4.
More specifically, the Agency emphasizes Dr. Keeler’s statement that CMAQ, a Eulerian model
endorsed by USEPA, “underestimated mercury wet deposition by varying amounts up to a factor
of two.” PC 6298 at 17.
The Agency notes Dr. Keeler’s testimony that “reduction in emissions from coal
combustion sources in the region would have a significant impact on the amount of mercury
deposited via both wet and dry deposition.” PC 6298 at 17, citing Exh. 10 at 5. The Agency
further notes that, because Illinois has 21 coal-fired EGUs emitting approximately four tons of
mercury annually, Dr. Keeler argued that reduced emissions would particularly benefit impaired
waters in Illinois. PC 6298 at 17, citing Exh. 10 at 5. Specifically, the Agency states Dr.
Keeler’s view that “reductions in emissions of mercury in Illinois will yield significant
reductions in mercury deposition in Illinois.” PC 6298 at 17, citing TSD at 81, 6/13Tr. at 98.
The Agency argues that Mr. Vijayaraghavan actually “confirmed the accuracy of Dr.
Keeler’s critique of the use of Eulerian models to predict deposition of mercury.” PC 6298 at 19.
The Agency first claims that Mr. Vijayaraghavan “admitted that there were few actual
measurements of the mercury species emitted by coal-fired power plants, even though the
deposition and biological activity of different mercury species are very different.”
Id
., citing
CTr. at 1383, 1386-87. Second, the Agency argues that Mr. Vijayaraghavan acknowledges that
59
mercury emissions can be affected by factors such as the chlorine content of coal but that these
factors have not been measured and generate some degree of uncertainty. PC 6298 at 19, citing
CTr. at 1383-84. Third, the Agency claims that Mr. Vijayaraghavan stated that his model makes
assumptions about the atmospheric chemistry of mercury because of uncertainties regarding the
transformation of mercury species. PC 6298 at 19, citing CTr. at 1388. Finally, the Agency
claims that Mr. Vijayaraghavan acknowledges that his model may not accurately predict local or
regional contribution to mercury deposition because it does not take into account the effect of
thunderstorms. PC 6298 at 19-20, citing CTr. at 1394-95, 1397-99, 1467, 1470, 1472.
The Agency suggests that Mr. Vijayaraghavan’s testimony on behalf of Midwest
Generation on the issue of deposition is not inconsistent with Dr. Keeler’s.
See
PC 6298 at 18-
20. First, the Agency notes that “Mr. Vijayaraghavan agreed that the source-receptor method
used by Dr. Keeler was a valid method of investigation of mercury deposition.” PC 6298 at 18.
Second, the Agency noted Mr. Vijayaraghavan’s comment that his own modeling analysis
yielded a result consistent with Dr. Keeler’s conclusion that coal-fired EGUs located within 1000
kilometers of Steubenville contribute approximately 70% of wet mercury deposition in the
vicinity of Steubenville.
Id
., citing CTr. at 1512. Third, the Agency argues that Mr.
Vijayaraghavan acknowledged that the Agency’s proposal would provide approximately twice
the reduction in mercury deposition of CAMR in 2010 and that most of the benefits of that
accelerated reduction would occur in Illinois. PC 6298, citing CTr. at 1422, 1425, 1428, 1434,
1436, 1462.
Board Discussion on Deposition and Modeling
As noted above, Midwest Generation disagrees with the Agency’s conclusion that
significant mercury emissions reduction in Illinois will yield significant reductions of mercury
deposition in Illinois. Midwest Generation’s concerns about modeling and mercury deposition
focuses on three main areas: (1) the Agency’s reliance on results of studies performed in other
parts of the country such as Ohio, Florida, and Massachusetts that are not specific to Illinois; (2)
appropriateness of using receptor models instead of chemical transport or deterministic model;
(3) whether the predicted local deposition of mercury is significant enough to warrant mercury
controls on Illinois coal combustion plants. The Board will address those concerns below.
Reliance on Studies Not Specific to Illinois.
Midwest Generation asserts that none of
the studies relied upon by the Agency’s expert Dr. Keeler show whether Illinois EGUs impair
Illinois waters or whether the proposal will have an effect on the level of any impairment.
Midwest Generation argues that the results of the studies relied upon by the Agency are not
applicable to Illinois because of differing weather systems, geographic settings, and coal types.
The Board notes that the Agency relies on the results of the Florida and Massachusetts studies to
support the Agency’s assertions. However, the Agency primarily relies upon Dr. Keeler’s
Steubenville study and his hearing testimony to conclude that reduction of mercury emissions
from EGUs will result in a reduction of local wet deposition of mercury.
Although the studies relied upon by the Agency were not Illinois specific, the Board
notes that it is not unusual for the Board to adopt regulations relying on such studies. The Board
routinely adopts regulations based on regional or nationwide modeling performed by the USEPA
60
that are not specific to Illinois. In light of this, the Board will consider the studies submitted by
the Agency in evaluating the merits of the Agency’s proposal. Initially, the Board recognizes
that while the sources of mercury emissions considered in the Florida and Massachusetts studies
were primarily incinerators, the Steubenville study dealt with coal combustion sources.
Although all the three studies support the Agency’s contention that reduction of mercury
emissions from coal combustion plants would significantly reduce local mercury deposition, the
Board will discuss the issues raised by Midwest Generation concerning the Steubenville Study,
since Agency’s justification is largely based on that study.
Regarding the Steubenville study, the Board considers whether the conditions in
Steubenville, Ohio make the results so unique that the results are not applicable to any area other
than Steubenville. The Board notes that Dr. Keeler provided testimony as to why the results of
Steubenville study are applicable to Illinois. He testified that “conditions [in Steubenville] are
not unique or anomalous to make them so they are not usable or transferable to conditions that
we would have in Illinois.” 6/16amTr. at 84. Dr. Keeler explained that the Great Lakes are
dominated by synoptic meteorological transport, which is the large-scale movement of the
“highest and low pressure systems” across the Great Lakes.
Id
. Therefore, as long as specific
meteorology that occurs in a location is taken into account, the controlling factors are not that
much different for Illinois than Ohio.
Id
. at 84-85
.
With respect to coal type, and the form (elemental or reactive) of mercury emissions,
Midwest Generation argues that Illinois EGUs primarily burn PRB coal, which results in the
emissions of mostly elemental mercury in contrast to mostly reactive mercury emitted by sources
in the Steubenville area. Elemental mercury is less readily deposited and less likely to undergo
methylation. Dr. Keeler testified that while municipal and medical waste incinerators emit
greater than 80% reactive mercury, coal-fired utilities emissions of reactive mercury range from
approximately 52 to 82%. The lower end of the range represents emissions from sub-bituminous
(PRB) coal-fired plants. 6/14Tr. at 244. Although the proportion of reactive mercury in
emissions from PRB coal burning plants is less than bituminous coal-fired plants, the Board
notes that the proportion of such emissions from PRB coal plants are still greater than 50%.
Further, Dr. Keeler testified that recent studies pertaining to mercury chemistry suggests that in
certain environments, such as downwind of urban areas, elemental mercury is rapidly
transformed to reactive mercury. 6/15Tr. at 192. He noted that observational evidence at
Steubenville indicates this phenomenon. 6/15Tr. at 193.
In light of the above, the Board finds that reliance on the findings of the Steubenville
study to evaluate the impact mercury emissions from Illinois utilities on Illinois waters is
appropriate.
Receptor Model v. Chemical Transport Model.
Midwest Generation argues that the
Board should consider AER’s modeling results presented by Midwest Generation’s expert, Mr.
Vijayaraghavan. Midwest Generation asserts that the receptor modeling performed by Dr.
Keeler reflects what is actually in the atmosphere and cannot predict future deposition. PC 6300
at 72. Midwest Generation maintains that the chemical transport or deterministic model called
TEAM used by AER predicts the impact of mercury emissions from Illinois power plants on
Illinois water bodies. PC 6300 at 64. Midwest Generation maintains that the Agency did not
61
present any chemical transport or deterministic modeling to demonstrate that the target of the
rule is the source of the perceived problem; or that the proposed rule will have the desired effect
of reducing deposition from Illinois power plants to Illinois waters. PC 6300 at 64-65.
The Board notes that regulating agencies routinely use models for evaluating impacts of
various emissions reduction levels on air quality, or apportioning the sources of a specific
contaminant. However, the type of model relied upon depends on the purpose of the evaluation.
In this proceeding, as noted by Midwest Generation, the first question that needs to be answered
is whether the Illinois coal-fired utilities (the target of the rules) are the significant source of
mercury impairment of Illinois water bodies. In order to answer this question, the Board must
determine that the mercury emissions from Illinois coal-fired plants are a significant source of
mercury deposition in the state. The record indicates that while receptor models have been used
successfully to apportion sources of mercury deposition, the chemical transport or deterministic
models are limited by large uncertainties in emissions inventory, and lack of speciated mercury
emissions profiles, atmospheric mercury chemistry and accurate deposition parameterization.
Mr. Vijayaraghavan, who performed AER’s modeling exercise, recognized shortcomings
in the deterministic models. He acknowledged that there are few actual measurements of
mercury emissions from EGUs and that “there is some level of scientific estimation that goes
into this emissions modeling.” CTr. at 1383. He further agreed that a number of factors
influence mercury emissions from EGUs, leading to “some level of uncertainty in emissions.”
Id
. at 1384. Also, he states that the chemical transformation of mercury in the atmosphere is not
understood with complete certainty and that the TEAM model must make some assumptions
regarding that phenomenon.
Id
., at 1387-88. Mr. Vijayaraghavan also acknowledged that the
TEAM model fails to account fully for thunderstorms, resulting in underestimation of mercury
deposition.
Id
., at 1394-95.
To the contrary, the record indicates a multivariate statistical receptor models have been
used successfully in Ohio, and Florida to apportion sources of mercury deposition. These
models use statistical methods that are implemented by relying on observations of deposition at a
site or receptor. Further, receptor models are not dependent on source profiles or emissions
inventories. In this regard, the Board notes that Dr. Keeler provided extensive testimony
regarding the Steubenville Study, which involved the use of receptor models to determine
sources contributing to mercury in wet deposition. This study found that coal-fired utilities
contributed approximately 70% of the mercury wet deposition at the Steubenville site. Although
this study was not Illinois specific, as noted above, the Board found that the study results are
applicable to Illinois. Therefore, the Board finds that the Agency correctly relied on the receptor
modeling to demonstrate that Illinois utilities are a significant source of mercury deposition
within the state.
Whether the Predicted Local Deposition of Mercury Warrant Mercury Controls.
As noted above, the Steubenville study results indicate that coal combustion sources accounted
for approximately 70 percent of the wet deposition of mercury at the Steubenville site. Further,
Dr. Keeler’s analysis showed that “a substantial amount of the mercury deposition found at the
Steubenville site was due to local and regional sources.” PC 6298 at 16, citing Exh. 10 at 3.
Although the Steubenville study addressed wet deposition, Dr. Keeler noted that “[e]levated
62
ambient mercury levels near large sources suggest that dry deposition would also be elevated and
likely to be similar in magnitude to the wet deposition.” Exh. 10 at 5. Accordingly, he
concludes that “reductions in emissions from coal combustion sources in the region would have a
significant impact on the amount of mercury deposited via both wet and dry deposition.”
Id.
Testifying on the issue of deposition on behalf of Midwest Generation, Mr.
Vijayaraghavan did not persuasively undermine Dr. Keeler’s conclusions on that issue.
Although Mr. Vijayaraghavan performed deposition estimates based on a Eulerian model known
as TEAM (CTr. at 1355-56), he did not dispute the validity of the source-receptor model used by
Dr. Keeler.
See
CTr. at 1512-13. In fact, he agreed that Dr. Keeler’s source-receptor method
produced results comparable to and within the range of his own estimate of mercury deposition
contributed by coal-fired EGUs.
Id
.
Addressing the effects of the proposed regulation in 2010, Mr. Vijayaraghavan agreed
that the Agency’s proposal would result in an additional decrease in mercury deposition in
comparison with the federal CAMR rule. CTr. at 1422-23, 1457. Stated another way, Mr.
Vijayaraghavan agreed that, in 2010, the federal CAMR rule would result in higher levels of
mercury deposition for virtually the entire State of Illinois.
Id
. at 1436-37. He also stated that
the Agency’s proposal would by 2010 reduce mercury deposition by approximately the same
amount that CAMR would reduce it by 2020.
Id
. at 1430. Mr. Vijayaraghavan also agreed that
Illinois would receive most of the benefits of the rule.
Id
. at 1425. Applying the TEAM model
to the single year of 2010, Mr. Vijayaraghavan acknowledged that the Agency’s proposal would
reduce mercury deposition in Illinois by 321 pounds more than the federal CAMR proposal.
Id
.
at 1496-97.
In addition to the above modeling studies, the Board notes that mercury deposition study
in the Florida Everglades showed that within a few years after state and federal requirements
reduced mercury emissions, mercury measured in the tissues of largemouth bass “showed
substantial declines.” TSD at 81-82. The Agency further states that the relation between
atmospheric mercury load to the Everglades and the body burden of largemouth bass has been
modeled to be nearly one-to-one. TSD at 84-85; 6/14Tr. at 205-08 (Keeler testimony); Exh. 20
at 68. Similarly, significant reductions in mercury emissions resulted in a steep decline in fish
tissue levels from the waters of northeastern Massachusetts within five years. TSD at 86; Exh.
20 at 14; TSD at 86 (Figure 5.8: Representative Fish Tissue Mercury and Incinerator Emissions
Changes Versus Time in NE MA). The Board recognizes that the Florida and Massachusetts
study dealt with reduction of mercury emissions mostly from incinerators. However, both the
studies lend support to the Agency’s contention that significant reduction in mercury deposition
results in reduction of mercury levels in fish tissue.
Based on the above evidence, the Board finds that the record strongly supports the
Agency’s contention that mercury emissions from Illinois utilities contribute significantly to
mercury deposition on Illinois waters. Further, the Board finds that a reduction of mercury
emissions from Illinois utilities would have significant impact on the amount of mercury
deposited on Illinois waters.
63
Board Conclusions on Modeling and Deposition.
The Board finds that the record in
this proceeding, including the testimony of Dr. Gerald Keeler, demonstrates that a reduction in
mercury emissions in Illinois will result in reduction of mercury deposition in the State.
Although the Agency relies heavily upon Dr. Keeler’s Steubenville study (PC 6292), the Board
believes that that study persuasively demonstrates that local and regional coal combustion
sources contribute significantly to the wet deposition of mercury. The Board finds that the
results of the Steubenville study are valid for evaluating the impact of mercury emissions from
Illinois utilities on Illinois waters. Further, the use of receptor models is appropriate for
apportioning the sources of mercury deposition. Finally, while the Florida and Massachusetts
studies may be based upon factors such as geography and sources that are different from Illinois,
the Board finds those studies support the Agency’s contention that a reduction of mercury
deposition will result in a reduction of mercury levels in fish tissue.
On the basis of the record, the Board concludes that that a reduction in mercury emissions
in Illinois will result in reduction of mercury deposition in the state. The Board notes that,
compared with CAMR, the Agency’s proposal reduces those mercury emissions more quickly
and more deeply. Accordingly, the Board finds that the Agency’s proposal can be expected to
result in reduced mercury deposition in the state and the expected result supports adoption of the
proposal.
Health Effects
In this section of the opinion, the Board will address the participants’ arguments
concerning the health effects from the ingestion of mercury. All parties agree that ingestion of
methylmercury by sensitive populations, such as pregnant women and young children, can cause
negative health effects. However, the opponents mainly argue that reducing mercury emissions
in Illinois will have little impact on potential health effects in Illinois. The Board will conclude
by analyzing the arguments and making the Board’s findings on this issue.
Midwest Generation’s Comment
Midwest Generation acknowledges that “[t]here is no dispute that mercury, consumed in
fish or seafood in the form of methylmercury at high enough levels can be a health risk for
certain sensitive portions of the population.” PC 6300 at 51. Nonetheless, Midwest Generation
argues that reducing mercury emissions will generate health benefits only if several steps follow
one another:
the reduced emissions would have reached an Illinois waterbody; that waterway
would have the right chemistry to convert this small, incremental amount of
mercury to an incremental amount of methylmercury; that waterbody has the
necessary biota for the incremental methylmercury to move up the biological
chain to predator, sport fish; that fish has to be caught by a fisherman; [and] that
fish has to be consumed by a member of the sensitive population and has to
contain alone, or in combination with other fish consumed by that person,
sufficient methylmercury to actually pose a health risk. (characterizing
relationship as “very attenuated”).
Id
.,
see
PC 6300 at 63.
64
Suggesting that the Agency did not adequately analyze the effects of the Agency’s own proposal,
Midwest Generation states that any health benefit produced by that proposal “would be so small,
so improbable, as to be equivalent to zero compared to CAMR in the relatively short time there
is even any difference between CAMR and the proposal.” PC 6300 at 51-52.
At hearing, Midwest Generation presented the testimony of Dr. Charnley in support of its
assertions regarding health effects. Dr. Charnley noted that other regulatory entities and
scientific organizations have developed a range of exposure limits for methylmercury. Exh. 130
at 14-15; Exh. 130, Exh. 6. Dr. Charnley attributes this range to “different decisions about which
study was the most representative or valid, the approach taken to evaluate the relationship
between dose and response, and the choice of uncertainty factor.” Exh. 130 at 15. Although she
states that the various limits may not reflect the scientific evidence equally well, “[n]one of those
choices are necessarily ‘right’ or ‘wrong’ scientifically.”
Id
. Dr. Charnley further states that the
difference between these limits “illustrates the widespread differences of opinion that are
possible in terms of scientific interpretation and policy choices.” Exh. 130 at 20. Midwest
Generation asserts that Dr. Charnley testified that any risk from the consumption of fish was
overstated by the Agency’s expert, Dr. Rice. PC 6300 at 80. Midwest Generation argues that
valid regulatory choices concerning methylmercury should be considered and based on objective
analysis and relevant evidence. PC 6300 at 81.
Expanding Midwest Generation’s perspective beyond Illinois, Midwest Generation
argues that “the already immeasurably small [benefit] becomes even more infinitesimal.” PC
6300 at 52. Midwest Generation states that the record demonstrates that only approximately one
percent of global atmospheric loading of mercury is attributable to U.S. power plants.
Id
., citing
Exh. 126 at 3, CTr. at 1488. Considering that small proportion and taking into account the steps
described above that Midwest Generation believes must follow one another in order to alleviate
the health risk of methylmercury exposure, Midwest Generation argues that the Agency’s
proposal would effectively produce results “too tiny to measure” and provide no health benefit at
all.
See
PC 6300 at 52. Accordingly, Midwest Generation argues that there is no justification for
reducing mercury emissions beyond levels required by CAMR. PC 6300 at 62.
Environmental Advocates’ Comment
The Environmental Advocates note that “[u]p to three-quarters of tested water bodies
have fish with mercury levels that justify a fish consumption advisory.” PC 6297 at 3, citing
6/12Tr. at 67. While the Environmental Advocates note that an advisory recommends eating no
more than one fish meal per week (PC 6297 at 3, citing 6/13Tr. at 31), the advisory is not self-
enforcing. “[T]here is no legal mechanism actually preventing people from eating any amount
of mercury-containing fish from Illinois waters.” PC 6297 at 3. The Environmental Advocates
note that the Illinois Department of Natural Resources every year issues approximately 700,000
fishing licenses (PC 6297 at 3, citing 6/12Tr. at 61) and that children, who are susceptible to
mercury exposure, may fish in Illinois without obtaining a license (PC 6297 at 3, citing 6/16Tr.
at 63). Assessing the health risks these persons may face, the Environmental Advocates cite “a
study of Illinois anglers conducted between 1987 and 1993, which demonstrates anglers will
65
consume unhealthy quantities of fish even though advisories exist.” PC 6297 at 3, citing Exh. 9
at 4-5.
Agency’s Comment
The Agency describes mercury as a “persistent, bioaccumulative neurotoxin” (TSD at
18), and no participant in this proceeding has squarely challenged that characterization. The
Agency acknowledges that there is some uncertainty in determining the precise extent to which
reduced mercury emissions will reduce adverse human health effects. PC 6298 at 22. Further,
the Agency has characterized the adverse health effects from methylmercury contamination as
“the major reason for developing this proposal.” TSD at 26. Yet, the Agency acknowledges that
“[t]here is scientific uncertainty in attempting to assess the extent to which mercury emission
reductions from power plants translate to reduced atmospheric deposition, reduced
methylmercury generation, reduced methylmercury accumulation in fish, and ultimately reduced
adverse human health effects.” PC 6298 at 22. Indeed, the Agency states that it neither intended
nor expected that a reduction in mercury emissions from EGUs would correspond exactly to a
reduction in fish tissue mercury concentrations.
Id
. Nonetheless, the Agency claims it is “clear”
that any reduction or elimination of fish consumption advisories is unlikely without deeply
reduced mercury emissions.
Id
. The Agency stresses that, compared to CAMR, the proposal
provides “deeper and quicker emission reductions.”
Id
.
In her testimony before the Board, Dr. Deborah Rice described more than six cross-
sectional studies exploring “the effects of environmental methylmercury intake on the
development of the child.” Exh. 3 at 3. Dr. Rice testified that each of these studies showed
adverse effects including “auditory and visual effects, memory deficits, deficits in visuospatial
ability, and changes in motor function” related to the level of methylmercury in the children’s
bodies.
Id
.
In addition, Dr. Rice testified regarding longitudinal prospective studies from the Faroe
Islands (TSD, Exh. A at 4-5), the Seychelles Islands (TSD, Exh. A at 3-4), and New Zealand
(TSD, Exh. A at 2-3) on the effects of mothers’ methylmercury exposure on the
neuropsychological function of their children. Exh. 3 at 3. Specifically, the studies analyzed the
concentration of methylmercury in the mother’s hair or umbilical cord blood as “a measure of
prenatal exposure of the child to methylmercury.” Exh. 3 at 3. The studies from the Faroe
Islands and New Zealand showed methylmercury exposure associated with adverse effects
including decreased IQ, and deficits in memory, language processing, attention, and fine motor
coordination.
Id
. Furthermore, Dr. Rice testified on the basis of those two studies that these
adverse effects may be greater at lower maternal methylmercury levels than at higher levels.
Exh. 3 at 4; Exh. 5; 6/13Tr. at 51-52 (describing shape of relationship as non-linear, logarithmic,
and supralinear). The Seychelles Islands study was not prospective in that the mother-infant
pairs were recruited after the births of the children. 6/13Tr. at 10-11. Accordingly, Dr. Rice
noted that “it can be argued that the measure of exposure might not have been quite as precise in
the Seychelles as it was in the other two studies.” 6/13Tr. at 11. Furthermore, Dr. Rice testified
that, although the Seychelles Islands investigators found that their data did not support the claim
that prenatal methylmercury exposure solely from consumption of ocean fish poses a
developmental risk, those investigators have conducted benchmark dose analysis presumably in
66
order to determine an adverse effect level. 6/13Tr. at 28-29; 8/22Tr. at 84 (noting in Charnley
testimony that analysis generated a statistically lower confidence limit on dose associated with
adverse effect).
The Agency states that USEPA defines a “reference dose” (RfD) as “an estimate (with
uncertainty spanning perhaps an order of magnitude) of a daily exposure to the human
population (including sensitive subgroups) that is likely to be without appreciable risk of
deleterious effects during a lifetime.” PC 6298 at 22 (citing USEPA Integrated Risk Information
System). The Agency further states that the National Research Council (NRC) has determined
that USEPA’s RfD for methylmercury of 0.1 micrograms per kilogram of body weight per day
(ug/kg/day) is scientifically justifiable.
Id
., citing TSD, App. A at 10. While the Agency states
that an RfD helps to define an acceptable level of exposure to methylmercury, the RfD “is not a
‘bright line’ and does not represent a true threshold in a toxicological sense.”
Id
. at 22-23, citing
6/13Tr. at 88.
The National Research Council (NRC), when reviewing the USEPA’s methylmercury
RfD, relied upon a Faroe Islands study, but also reviewed studies from the Seychelles Islands
and New Zealand. PC 6298 at 22-24. The Agency states that “[t]he Faroe Islands study was
truly prospective in that maternal participants were recruited before the children were born”
(noting the Seychelles study recruited cohort approximately six months after birth of children).
Id
. The Agency notes that a cohort of more than 900 children made the Faroe Island study the
largest of the three.
Id
. The Agency further notes that the Faroe Island study used biological
markers including umbilical cord blood and maternal hair.
Id
. Faroe Islands investigators found
that “cord blood was a better predictor of the performance of the child than was maternal hair,”
although the Seychelles Islands and New Zealand studies measured only maternal hair mercury
concentrations.
Id
.
The Agency states that average maternal hair methylmercury concentrations in the Faroe
Island, Seychelles Islands, and New Zealand cohorts exceeded USEPA’s RfD. PC 6298 at 23.
The Agency further states that the range of those maternal hair concentrations “has significant
overlap” with that of women in the United States.
Id
. More specifically, the Agency refers to a
study finding that approximately ten percent of women had hair mercury levels exceeding the
RfD and that “an equivalent or slightly greater percentage of women would exceed the reference
dose based upon recent National Health and Nutrition Examination Survey (NHANES) data.”
Id
., citing 6/13Tr. at 58 (Oken study). The Agency also notes the testimony of Dr. Rice that the
Oken study “suggests effects from methylmercury exposures that are below the USEPA
reference dose.”
Id
., citing 6/13Tr. at 55.
In addition to the three longitudinal studies from the Faroe Island, Seychelles Islands, and
New Zealand, the Agency also relies upon three prospective studies from Massachusetts, Poland,
and the Philippines, each of which evaluated “mercury body-burdens and the human health
effects of methylmercury exposure.” PC 6298 at 25, citing TSD, App. A at 5. The Agency also
argues that “[c]ross-sectional studies evaluating mercury exposure and neuropsychological
deficits have indicated adverse effects.” PC 6298 at 25. The Agency notes a study involving
Portuguese women who ate an average of 2.5 fish meals each week and in whose children
“[n]eurological function deficits were noted.”
Id
. at 25-26, citing 8/22Tr. at 97.
67
The Agency discounts “[s]tudies showing a relationship between increased prenatal fish
consumption and better performance by children on neurodevelopmental tests.” PC 6298 at 26.
Specifically, the Agency claims that those studies have not generally controlled for maternal IQ
and the child’s environment, “covariants known to be the strongest performance determinants.”
Id
., citing 6/13Tr. at 35. The Agency further claims that it may be difficult to interpret or
compare these studies because they may measure different markers or may include inadequate or
inappropriate statistical assessments. PC 6298 at 26. In addition, the Agency suggests that there
may be a low threshold between fish consumption and improved cognitive development, citing a
study noting no incremental improvement with fish consumption more frequent than once every
two weeks.
Id
., citing 8/22Tr. at 89 (Daniels study).
The Agency further argues that study results do not clearly show that polychlorinated
biphenyls (PCBs) contribute to the neurotoxic responses attributed to methylmercury. PC 6298
at 26. Specifically, the Agency claims that, while methylmercury and PCB testing may measure
the same cognitive functions, the evidence in the Faroe Islands study does not clearly support a
combined methylmercury and PCB neurotoxic effect.
Id
. The Agency stresses Dr. Charnley’s
testimony stating that “[t]he possible neurotoxic influence of PCB exposure did not explain the
methylmercury associated neurobehavioral deficits.” PC 6298 at 27, citing 8/22Tr. at 103. The
Agency dismisses “Dr. Charnley’s contention that reducing methylmercury in Illinois waters will
not lead to the elimination of the fish consumption advisories because PCBs will still be
present.” PC 6298 at 27. The Agency describes this contention as “meaningless”: “[i]f the
Board adopted this point of view no pollution control regulation would be justified because there
are always going to be other pollutants contaminating the air.”
Id
.
Addressing what it perceives to be inadequacies in CAMR, the Agency notes that CAMR
allows trading of emissions allowances and seeks to reduce mercury emissions within the United
States as a whole. The Agency suggests that CAMR may not actually reduce mercury emissions
in Illinois and states that “Illinois cannot depend upon CAMR from a public health perspective.”
PC 6298 at 27. The Agency cites USEPA’s own projections for reduction of mercury deposition
under CAMR by 2020. Noting that those projections show significant reductions in deposition
in only a few areas of the State, the Agency concludes “that CAMR will have a modest impact
on existing mercury deposition in Illinois.”
Id
., citing Exh. 130, Exh. 2. The Agency concludes
that modest reductions within Illinois may be sufficient from a national perspective but that
“Illinois clearly needs something more.” PC 6298 at 28.
The Agency plainly discounts the testimony of Dr. Gail Charnley, who questioned the
impact of the Agency’s proposal on public health and who described the benefits of the proposal
as “political only.” Exh. 130 at 20;
see
PC 6298 at 21-22. The Agency argues that Dr.
Charnley’s expressed preference for an emissions trading program such as CAMR constitutes a
bias diminishing the weight of her testimony. PC 6298 at 21, citing 8/22Tr. at 1678. The
Agency further argues that “Dr. Charnley has no record of independent research evaluating these
types of programs.” PC 6298 at 21. The Agency claims that this lack of experience casts doubt
on her ability to compare the respective health benefits of CAMR and the Agency’s proposal.
PC 6298 at 21-22, citing 8/22Tr. at 1679, 1682. Generally, the Agency states that “Dr. Charnley
attempts to create a long chain of uncertainty” designed to convince the Board to take no action
68
on the Agency’s proposal. PC 6298 at 28, citing 8/22Tr. at 1659-60. Arguing that fish
advisories are now in effect for Illinois waters and that CAMR will not significantly reduce
mercury deposition, the Agency states that the case for the proposal overcomes even Dr.
Charnley’s high burden of justification.
See
PC 6298 at 29.
Board Discussion on Health Effects
With regard to the health effects of methylmercury, the Board must determine if the
reduction of mercury emissions, leading to less deposition of mercury, will result in health
benefits to the citizens of the State. Midwest Generation agrees that there is no dispute that
methylmercury, consumed in fish or seafood at high enough levels can be a health risk for
certain sensitive portions of the population. The Board agrees and clearly the record in this
proceeding, including the testimony of Dr. Rice, demonstrates that mothers’ intake of
methylmercury has detrimental effects upon the development of their children. Both cross-
sectional and longitudinal prospective studies have shown an association of methylmercury
exposure with decreased IQ and with deficits in areas including memory, attention, and fine
motor coordination. Although the Seychelles Islands study did not confirm this association, that
study as described above may have measured methylmercury exposure less precisely than similar
studies.
The Board notes that Dr. Rice’s testimony also indicates that methylmercury is associated
with cardiovascular or coronary heart disease, including heart attack and death. Exh. 3 at 6. She
noted that studies in Finnish men found an association between hair mercury levels and
myocardial infarction, cardiovascular disease, and death.
The Board notes that Dr. Charnley stated that various entities have developed a range of
exposure limits for methylmercury. The Board accepts her view that this range is not attributable
to fundamental scientific error but instead results from differences in opinion, interpretation, and
policy choices. Accordingly, the Board cannot conclude that the results of the studies cited in
the record are based upon an invalid and unreasonably low exposure limit. However, the Board
places significant weight on USEPA’s reference dose. The Board has adopted a number of
regulations setting standards based upon USEPA’s reference doses for various chemical
contaminants, including water quality standards, groundwater standards, and soil remediation
levels.
Even as the proponent in this proceeding, the Agency acknowledges that there is not
likely to be an exact correspondence between reducing mercury emissions and reducing human
health effects. As noted previously under discussion of mercury deposition, the record indicates
that coal-fired utilities are a significant source of local mercury deposition. Further, the studies
presented by the Agency suggest a strong correlation between reduction of mercury emissions
from local and regional sources and lower mercury levels in fish tissue. Therefore, on the basis
of the record, the Board concludes that improving public health and reducing or eliminating fish
consumption advisories are not likely to occur without reducing mercury emissions from Illinois
utilities. The Board notes that, compared with CAMR, the Agency’s proposal reduces mercury
emissions from Illinois utilities more quickly and more deeply. There is no guarantee under
CAMR that mercury emissions would occur in Illinois since the rule establishes a nation-wide
69
cap and trade program. Accordingly, the Board finds that the Agency’s proposal can be
expected to result in additional health benefits and that those benefits support adoption of the
proposal.
Fish Advisories
This section of the opinion will summarize arguments concerning whether or not the
reduction of mercury emissions will impact fish advisories in the State. The Board will conclude
by analyzing the arguments and making the Board’s findings on this issue.
Midwest Generation’s Comment
Midwest Generation notes the Agency’s justification for the proposal that reducing
mercury emissions by 90% “will reduce fish tissue mercury concentrations to levels that will
eliminate mercury-impaired waters from Illinois.” PC 6300 at 74. Midwest Generation argues,
however, that
[t]he Agency has provided no evidence that any reductions in the level of
deposition that may result from the rule would in turn be reflected in reduced fish
tissue methylmercury levels in Illinois, the basis for the Agency’s assumption that
the proposal would eliminate or at least substantially reduce mercury-impaired
waters in Illinois and provide a significant, discernable health benefit to Illinois
residents. PC 6300 at 5-6.
Midwest Generation concludes that “[t]he proposed rule will not accomplish these goals.” PC
6300 at 74.
Stating that there exists a “vast amount of analysis” mustered in support of CAMR by
USEPA, Midwest Generation argues that the Agency has performed none of the analysis that
ought to provide the basis for its proposal on this issue. PC 6300 at 75. Specifically, Midwest
Generation argues that “[t]he Agency has not determined the amount of any mercury deposition
or fish tissue concentration reduction that would result from the proposed rule, if adopted.”
Id
.,
citing 6/14Tr. at 122, 166, 302-04. Midwest Generation further argues that “[t]he Agency did
not assess the extent to which Illinois residents eat Illinois freshwater fish or even the extent to
which Illinois fisherman eat the fish they catch.” PC 6300 at 75, citing 6/16Tr. at 71-73.
Midwest Generation further argues that the Agency did not assess the impact of out-of-state
sources of mercury, non-point sources of mercury, or factors affecting the methylation process.
PC 6300 at 75-76, citing 6/14Tr. at 41-44, 45-46, 127, 134, 248, 268, 302. Midwest Generation
further claims that Agency overlooked its own data relevant to the issue of fish tissue mercury
levels.
See
PC 6300 at 76. As an example, Midwest Generation stresses Dr. Hornshaw’s
testimony for the Agency, in which he stated “that mercury fish tissue concentrations in Illinois
have remained essentially flat since 1988” despite regulation reducing mercury emissions from
other sources.
Id
., citing 6/14Tr. at 183-87.
On the issue of reducing fish tissue mercury concentration, Midwest Generation
strenuously disputes the Agency’s reliance on two particular studies, one from Massachusetts
70
and one from Florida.
See
PC 6300 at 76-77. Generally, Midwest Generation argues that the
Agency has failed to show that waters in either of those states are similar enough to Illinois
waters to expect similar results here. PC 6300 at 77. More specifically, Midwest Generation
argues that “the Agency totally ignored the data in those studies that showed no reduction or
even an increase in fish tissue mercury levels following reductions in mercury emissions.”
Id
.
Midwest Generation further argues that, despite significant reductions in mercury deposition,
these studies simply did not show consistent reductions in fish tissue mercury levels and did not
eliminate mercury-impaired waters. PC 6300 at 78.
Midwest Generation also criticizes the Agency’s water quality and fish flesh data,
characterizing it as falling “far short of what is necessary to support a rulemaking.” PC 6300 at
78. Midwest Generation notes that “[t]he Agency has fish tissue mercury information for only
about 1,000 miles of the about 71,000 miles of streams in Illinois and for only eight of the more
than 3,000 lakes in Illinois larger than six acres.”
Id
., citing 6/14Tr. at 106-08. Midwest
Generation argues that, although mercury was not detected in many samples, the Agency has
assumed in practice that mercury is present at the detection limit. PC 6300 at 78, citing 6/14Tr.
at 158-59, TSD at 63.
Midwest Generation places some emphasis on claims that the Agency has inconsistently
described the effect of the proposal. PC 6300 at 79. Specifically, Midwest Generation notes that
Ms. Willhite foresees a one-to-one relationship between reduction in mercury deposition and in
fish tissue mercury concentrations.
Id
., citing 6/14Tr. at 166-67, 194-95. Midwest Generation
further notes that, in his testimony, Mr. Ross foresees only that those reductions would
correspond with one another. PC 6300 at 79, citing 6/19Tr. at 126-28.
Midwest Generation argues that the Agency’s conclusions rest on “unsupported
assumptions” rather than valid assessments and studies, and Midwest Generation stresses Dr.
Chapman’s characterization of the Agency’s data collection as “sparse.” PC 6300 at 78-79,
citing 8/22Tr. at 17-18. Midwest Generation also stresses Dr. Chapman’s testimony that, with
all of the complexities associated with regulating mercury and with the absence of critically
important data, “he would not expect to see a measurable reduction in fish tissue mercury
concentrations based on the small predicted additional mercury deposition reduction resulting
from the proposed rule, as compared to CAMR.” PC 6300 at 80, citing Exh. 129 at 11. Midwest
Generation further stresses that, “[b]ased on a complete set of relevant data, USEPA determined
that CAMR provided adequate protection.” PC 6300 at 82.
Environmental Advocates’ Comment
The Environmental Advocates note that “[t]he Illinois Department of Public Health has
established mercury advisories for all water bodies in Illinois due to levels of methylmercury in
predator fish.” PC 6297 at 3, citing Exh. 1 at 5, 6/12Tr. at 57, 6/14Tr. at 97. The Environmental
Advocates further note that 62 river segments comprising 1,034 miles in length and eight lakes
comprising 6,624 acres in area are impaired on the basis of mercury. PC 6297 at 3, citing Exh. 1
at 5-6. The Environmental Advocates also note that “[u]p to three-quarters of tested water
bodies have fish with mercury levels that justify a fish consumption advisory. PC 6297 at 3,
citing 6/12Tr. at 67. Finally, the Environmental Advocates stress that “[i]n fish tissue sampling
71
conducted between 1988 and 2001, two-thirds to three-quarters of all bass and walleye from
Illinois waters have mercury levels that would justify a consumption advisory” (PC 6297 at 3,
citing 6/13Tr. at 71), which “cautions against eating more than one fish meal per week” (PC
6297 at 3, citing 6/13Tr. at 31).
The Environmental Advocates stress that, because this caution is merely advisory in
nature, “there is no legal mechanism preventing people from eating any amount of mercury-
containing fish from Illinois waters.” PC 6297 at 3. The Environmental Advocates cite the
testimony of Dr. Hornshaw, who referred to a 1987-93 study of Illinois anglers. The
Environmental Advocates claim that the study determined that “anglers will consume unhealthy
quantities of fish even though advisories exist.” PC 6297 at 3-4, citing Exh. 9 at 4-5. The
Environmental Advocates stress Dr. Hornshaw’s conclusion based on his review of the literature
that “sport anglers may consume amounts of sport-caught fish that could allow them and their
families to exceed health-based limits for chemical contaminants in their catch.” PC 6297 at 4,
citing Exh. 9 at 5. Ultimately, the Environmental Advocates state that, “[b]ecause of well-
documented conditions in Illinois waterbodies and fish, and the associated risks to Illinois
anglers, fish consumers and wildlife, there is a strong justification to develop an Illinois-specific
regulatory approach to control mercury.” PC 6297 at 4.
Agency’s Comment
The Agency states that “[t]he Illinois Fish Contaminant Monitoring Program (FCMP) is a
cooperative effort of five Illinois agencies, the Departments of Agriculture, Emergency
Management, Natural Resources, and Public Health, and the Illinois EPA.” PC 6298 at 30. The
Agency further states that “[t]he primary goal of the FCMP is to identify for Illinois anglers
through sport fish consumption advisories those species of fish and bodies of water that may
pose the greatest potential risks to the anglers and their families, and allow them to avoid these
risks by making informed judgments about the types and amounts of fish they eat.”
Id
., citing
TSD at 54-55, Exh. 9 at 2. Specifically, the FCMP has issued a statewide mercury advisory and
has placed fifteen bodies of water on a Special Mercury Advisory. PC 6298 at 30-31;
see also
Exh. 11 (
Illinois Fishing Information 2006
). As FCMP generates more data on levels of
methylmercury in fish, the original list of four bodies of water on the first Special Mercury
Advisory in 2002 has been expanded to 15 bodies of water in 2006, including for the first time
an entire river system (the Little Wabash River and its tributaries).” PC 6298 at 32.
The Agency characterizes as “extremely misleading” Dr. Peter Chapman’s claim that
74% of the waters listed as impaired due to mercury would still be impaired due to PCBs even if
the Agency’s proposal “resulted in all fish in the listed waters achieving compliance with the
mercury criteria”. PC 6298 at 31;
see generally
Exh. 129. The Agency responds that there are
“numerous waters that could have been listed as impaired due to mercury but have not because
of FCMP policy decisions.” PC 6298 at 31. For example, the FCMP requires two or more
recent samples exceeding a criterion for a contaminant in order to issue an advisory.
Id
. Also,
FCMP has “decided that initial samples of predator species having mercury levels in the one
meal/week range (0.06-0.22 mg/kg) will not be followed up, since the statewide advisory already
covers those samples.”
Id
. The Agency argues that, if it had followed up those initial samples,
many more waters may have been listed as impaired for mercury.
Id
. In support of this claim,
72
the Agency notes that “two-thirds to three-quarters of all waters sampled between 1988-2001 had
predator species that would require advisories for mercury.”
Id
., citing TSD at 53.
The Agency argues that the Agency “has presented testimony in support of the
proposition that reductions in mercury emissions ultimately result in reduction in mercury in fish
tissue.” PC 6298 at 32;
see
Exh. 20 (study published by Florida Department of Environmental
Protection), Exh. 21 (study published by Massachusetts Department of Environmental
Protection). By requiring a 90% reduction in mercury emissions by 2009, the Agency reflects its
position that “larger and faster reductions in mercury emissions are the most appropriate way to
address sport fish advisories for methylmercury.” PC 6298 at 32. The Agency states its
expectation that adoption of its proposal will slow the growth of the Special Mercury Advisory,
possibly result in delistings from that advisory, and reduce the waters listed as impaired due to
mercury. PC 6398 at 32-33.
Board Discussion on Fish Advisories
The Board notes that the record in this proceeding, including the testimony of Dr.
Hornshaw and Ms. Willhite, indicates that the Agency’s proposal can be expected to result in
reductions in fish tissue mercury concentrations in Illinois. In this regard, the Board has
previously found that the evidence in the record supports the Agency’s contention that Illinois
coal-fired EGUs represent a significant source of mercury deposition on Illinois waters.
See
supra
59
.
Further, the record supports Agency’s position that reduction of mercury emissions
result in lower mercury levels in fish tissue. Consequently, the Board believes that adoption of
the proposal can be expected to result in delistings from the Special Mercury Advisory, and
reduce the number of waters listed as impaired due to mercury.
The Board notes Midwest Generation’s argument that the Agency’s witnesses may not
have described the expected results of this proposal with perfect consistency. However, those
descriptions do not irreconcilably conflict with one another and do not undercut the Agency’s
general rationale for the proposal. The Board notes that even if reduction of mercury emissions
from Illinois utilities does not result in the reduction of mercury levels in fish tissue on a one-to-
one basis, the record supports the Agency’s position that the proposal will result in a significant
reduction in fish tissue mercury levels.
The Board concludes that reducing fish tissue mercury concentrations and reducing or
eliminating fish consumption advisories are not likely to occur without reducing mercury
emissions. Compared to CAMR, the Agency’s proposal reduces mercury emissions from Illinois
utilities more quickly and more deeply. Accordingly, the Board finds that the Agency’s proposal
can be expected to result in reducing fish tissue mercury concentrations and reducing or
eliminating fish consumption advisories and that those benefits support adoption of the proposal.
Economics of Compliance
In this section of the opinion, the Board will address the arguments made by the
participants concerning the economics of complying with the proposal. The Board concludes
this section with a discussion and the Board’s findings.
73
Midwest Generation’s Comment
Midwest Generation argues that the realistic and necessary cost of complying with the
Agency’s proposal is so great that adoption of the proposal is economically unreasonable. PC
6300 at 50, 54. As a preliminary matter, Midwest Generation states that “[t]here is only a limited
dispute as to the costs of various mercury control equipment.” PC 6300 at 54. Midwest
Generation argues that there are significant differences between the Agency’s and the opponents’
cost estimates based on differing “assumptions as to what control equipment will need to be
installed.”
Id
. at 55. Specifically, Midwest Generation states that the Agency has concluded that
use of HCI alone will achieve compliance with the Agency proposal. PC 6300 at 54. Midwest
Generation also states the opponents’ position that, while HCI will provide some level of control,
it has not yet been persuasively shown to be able to satisfy the requirements of that proposal.
Id
.
Midwest Generation argues that, because compliance with the Agency’s proposal will require
more than HCI alone, the proposed rule is “impossible financially.” PC 6300 at 3.
Midwest Generation accounts for industry’s caution with regard to the sufficiency of HCI
by arguing that the Agency and the utilities face very different risks from reaching the wrong
conclusion about that sufficiency.
See
PC 6300 at 54-55. Midwest Generation states that the
Agency risks nothing if the conclusion that HCI is sufficient to comply with the proposal proves
to be incorrect.
Id
. at 55. On the other hand, Midwest Generation states that, if companies rely
upon an incorrect conclusion regarding the sufficiency of HCI, then companies that rely on the
Agency’s conclusion will risk “criminal and civil enforcement actions by the Agency and
USEPA, citizens’ suits, possible penalties, and even shut-down orders.”
Id
. Accordingly,
Midwest Generation states that the Agency and the utilities reach very different conclusions
about the cost of complying with the proposal because they differ with regard to the technology
required to comply.
Id
.
Midwest Generation notes that the analysis of the Agency’s proposal conducted by ICF
Resources, Inc. (TSD at 167-84) and the testimony of Dr. Ezra Hausman (6/22Tr. at 274-91,
6/23Tr. at 292-447) are “somewhat inconsistent” but that the two agree “that the proposal will
cost $32 million per year more than CAMR in 2010 through 2017.” PC 6300 at 56, citing TSD
at 159. Midwest Generation further notes that trading emissions under CAMR and co-benefits
obtained through CAIR distribute costs more evenly than the Agency’s proposal. PC 6300 at 56.
Ultimately, Midwest Generation characterizes the Agency’s cost estimate as a “grotesque
underestimate” and states that capital costs alone “will be over
$1 billion more than
CAIR/CAMR” (emphasis in original).
Id
.
In support of this conclusion, Midwest Generation refers to the testimony of Mr.
Marchetti.
See
Exh. 118. Stressing the technology and the schedule for installation that would
provide some assurance that EGUs could comply with the Agency’s proposal, Mr. Marchetti
states that the capital costs alone would be $1.77 billion. PC 6300 at 56, citing Exh. 118 at 7,
8/18Tr. at 1298. Tallying non-capital expenses, Mr. Marchetti concluded that the Agency’s
proposal would cost EGUs approximately $200 million per year for ten years in addition to costs
imposed by CAIR/CAMR. PC 6300 at 57, citing Exh. 118 at 11, 8/18Tr. at 1301.
74
Midwest Generation further argues that, although she testified in support of the proposal
including an MPS, Dr. Anne Smith reached a conclusion with regard to costs that is comparable
to Mr. Marchetti’s. PC 6300 at 57. Specifically, Dr. Smith testified that Ameren must raise
“nearly $650 million in 2006 present value” by 2009 in order to comply with the Agency’s
proposal.
Id
., citing Exh. 77 at 11. According to Midwest Generation, “the proposal would
impose on Ameren alone some $450 million more than CAIR/CAMR in capital costs and just by
2009” (emphasis in original). PC 6300 at 57. Midwest Generation notes Dr. Smith’s estimate
that, without the MPS provisions, the Agency proposal would cost all EGUs approximately
$1.13 billion more than CAIR/CAMR.
Id
., citing 8/15Tr at 398-99.
Midwest Generation further argues that “the so-called flexibility provisions,”
i.e.
, the
TTBS and the MPS, do not effectively mitigate these costs. PC 6300 at 58. With regard to the
TTBS, Midwest Generation claims that the Agency presented no evidence about the effect of the
TTBS on costs.
Id
. Midwest Generation also argues that the TTBS is explicitly limited by its
own terms to no more than 25% of generators.
Id
. Furthermore, Midwest Generation argues
that, to the extent that any generator avails itself of the TTBS, it will merely postpone and not
reduce its costs. PC 6300 at 58. With regard to the MPS, Midwest Generation notes that
Ameren’s own witness testified that, if only Ameren elected to use it, then the present value of
Ameren’s costs would actually increase to $1.35 billion.
Id
., citing Exh. 77 at 12, 8/15Tr. at 400.
Midwest Generation accounts for Ameren’s willingness to support a more costly option by citing
Dr. Smith’s testimony that “[t]here are substantial benefits to companies if they can spread the
capital costs over a longer period of time.” PC 6300 at 58, citing Exh. 77 at 10.
In addition, Midwest Generation suggests that the Agency is oblivious “to the fact that
the [proposed] rule places Illinois’ power generators at a competitive disadvantage with power
producers in other states.” PC 6300 at 4, citing Exh. 77 at 10, Exh. 118 at 6-7, 8/15Tr. at 430-32.
Midwest Generation stresses the testimony of Mr. Marchetti, who testified that compliance costs
are even more onerous because the generation of electricity will decline, reducing revenues for
Illinois EGUs. PC 6300 at 4, citing Exh. 118 at 6. Ultimately, argues Midwest Generation,
Illinois consumers will bear the weight of higher costs. PC 6300 at 5.
Ameren’s Comment
Ameren states that it offered an MPS amendment to the Agency’s proposal in order to
obtain mercury emissions reductions as a co-benefit of control devices used to reduce emissions
of SO
2
and NO
x
. PC 6301 at 7. Ameren argues that the MPS “synchronizes the control of these
emissions” in an economically reasonable manner.
Id
. Ameren refers to the testimony of Mr.
Menne, who stated that “the MPS will meet the goal of 90 percent mercury emissions on most
units, on a time frame extended by only three years, as well as making significant reduction in
NO
x
and SO
2
, above those required by CAIR.” PC 6301 at 8, citing Exh. 75, Exh. 76. Ameren
also cites the testimony of Dr. Smith. PC 6301 at 9;
see
Exh. 77. She stated that, although the
MPS requires larger expenditures than the Agency’s original proposal because of the added NO
x
and SO
2
controls, “these expenditures are greatly smoothed out, in a manner that should be far
more feasible to finance, and with a far more manageable rate of increase in demands on cash
flow.” PC 6301 at 9, citing 8/15Tr. at 388-442. Dr. Smith characterized these higher capital
expenditures as “a prudent trade-off for Illinois EGUs to make ‘from the perspective of corporate
75
financial stability, corporate management of construction projects (with associated operational
stability), and the creation of opportunities to achieve these environmental benefits at a lower
ultimate total cost.’” PC 6301 at 9, citing Exh. 77.
Kincaid’s Comment
Kincaid argues that the Agency has throughout this proceeding relied on ACI in support
of a 90% reduction in mercury emissions. PC 629 at 8-11. Kincaid believes that this reliance is
misguided on two bases. First, Kincaid believes that actual costs for constructing and operating
ACI systems are substantially higher than the estimated costs provided by Dr. Staudt in his
testimony for the Agency. PC 6299 at 8-9, citing 6/21Tr. at 5, 7. Second, Kincaid claims it has
demonstrated “that ACI is not capable of reliably achieving the required emissions level all of
the time.” PC 6299 at 9. Accordingly, Kincaid believes it “must rely on fully demonstrated
technologies” such as the TOXECON system including an ACI system in addition to a fabric
filter. PC 6299 at 9-10, citing TSD at 130. While the Agency suggests that capital costs for a
TOXECON system would be in the range of $40-60/KW, Kincaid notes that the U.S.
Department of Energy estimated those costs at $126/KW. PC 6299 at 10. For Kincaid, that
higher estimate represents capital costs of $157 million to install the TOXECON system.
Id
.
Kincaid concludes by stating that “[t]his cost is not economically reasonable and no portion of
the testimony in the record supports such excessive costs as being economically reasonable.”
Id
.
Environmental Advocates’ Comments
The Environmental Advocates first stress that it is difficult for any opponent of the
proposal to argue that it is not economically feasible when both Ameren and Dynegy support the
proposal as amended by the MPS. PC 6297 at 9. The Environmental Advocates also stress that
“the remaining opponents have presented no facility-specific or companywide information about
the projected costs of compliance.” PC 6297 at 9. The Environmental Advocates emphasize that
Mr. DePriest, a Midwest Generation witness, testified that “he had prepared cost estimates, but
was not at liberty to share this analysis.” PC 6297 at 9, citing 8/17Tr. at 1058, 1065, 1069.
The Environmental Advocates state that, in addition to providing no projected
compliance costs, the opponents also failed to evaluate any of the elements of the Agency’s
proposal that “provide substantial flexibility to regulated entities.” PC 6297 at 9. The
Environmental Advocates argue, for example, that Mr. Marchetti’s testimony “on economic
modeling did not account for either the TTBS or the MPS.” PC 6297 at 11, citing 8/18Tr. at
1308-09. The Environmental Advocates listed the elements of the Agency’s proposal that they
view as adding flexibility for EGUs. First, the Environmental Advocates note that the proposal
allows “a regulated entity to choose to comply using an output-based standard, .008 lbs/gwh, or a
percentage reduction, 90%.” PC 6297 at 9;
see
Proposed Section 225.230(a)(1). Second, the
Environmental Advocates state that the proposal allows “a regulated entity to elect to comply
using any combination of techniques and technologies.” PC 6297 at 10, citing Proposed Section
225.233. Third, the Environmental Advocates stress that the language of the proposal delays
compliance for nearly three years to July 1, 2009. PC 6297 at 10;
see
Proposed Section
225.230(a)(1).
76
Fourth, the Environmental Advocates emphasize that the Agency’s proposal allows
“compliance to be determined on a 12-month rolling average.” PC 6297 at 10;
see
Proposed
Section 225.230(a). Fifth, the Environmental Advocates note, the proposal includes provisions
“allowing owners of multiple EGUs to choose to comply by averaging among units during the
first phase of the regulatory program (through 2013), and allowing owners of single EGUs to
average with other similarly situated operators.” PC 6297 at 10;
see
Proposed Section 225.232.
Sixth, the Environmental Advocates stress that the Agency’s proposal allows “a complete opt-
out for units the regulated entity decides to shutdown.” PC 6297 at 10;
see
Proposed Section
225.235.
Seventh, the Environmental Advocates note that the TTBS allows a regulated entity “to
set aside 25% of its units from meeting a numeric standard until 2015, upon a showing that these
units are optimizing ACI mercury control equipment and meeting other operational
requirements.” PC 6297 at 10;
see
Proposed Section 225.234. Eighth, emphasize the
Environmental Advocates, the proposal allows a regulated entity to elect to follow a multi-
pollutant control strategy. PC 6297 at 10;
see
Proposed Section 225.233. Finally, the
Environmental Advocates also note that the proposal provides “for the same alternative mercury
monitoring requirements contained in the federal CAMR,” including newer CEM systems. PC
6297 at 10;
see
Proposed Section 225.240.
Emphasizing the cost of ACI systems and elements of the proposal that are intended to
provide flexibility to regulated entities, the Environmental Advocates claim that “it is not
surprising that Dr. Ezra Hausman characterized the cost to owners of Illinois coal plants as
almost negligible.” PC 6297 at 12. Specifically, Dr. Hausman stated the total annual cost of the
Agency’s proposal as $33 million. PC 6297, citing Exh. 51 at 8. The Environmental Advocates
argue that “[t]here is reason to believe the impact on consumers would be close to zero.” PC
6297 at 11-12. Dr. Hausman argued that there exists no mechanism through which Illinois
consumers could be directly charged those minimal costs of adopting the Agency’s proposal. PC
6297 at 12. “Consequently, Dr. Hausman estimates the total additional cost to consumers to be
between $0 and $11 million.” PC 6297 at 12, citing Exh. 51 at 8.
Agency’s Comment
The Agency argues that it has provided a detailed and accurate estimate of the cost for
each Illinois EGU to comply with the proposed rule. PC 6298 at 13, citing TSD at 161-66. The
Agency disputes Mr. Marchetti’s suggestion that only industry’s estimates weighed site-specific
data. PC 6298 at 14. The Agency claims that the “economic analysis considered site-specific
factors when evaluating the suitability, cost and performance of mercury control technology.”
PC 6298 at 13-14. Specifically, the Agency states that it took into account factors including
“fuel characteristics, duct sizes, ESP sizes, use of flue gas conditioning, and other plant-specific
matters that may affect the sorbent injection system design.” PC 6298 at 13. The Agency also
reports that Agency personnel visited every plant to verify the information on which it relied in
calculating its estimates.
Id
. Ultimately, the Agency concludes that the cost estimates are well
supported because test results show that the use of sorbent injection will allow plants burning
PRB coal to meet the requirements of the Agency proposal. PC 6298 at 14 (referring to TSD and
Staudt testimony).
77
The Agency argues that actual compliance costs have some likelihood of being lower
than the Agency’s current estimates. PC 6298 at 15. First, the Agency acknowledges that some
sorbents can interfere with beneficial reuse of fly ash. PC 6298 at 15. Because of that expected
adverse effect, the Agency suggests that it has included the cost of disposing of that fly ash into
the economic analysis.
See id
. The Agency notes, however, that new sorbents are undergoing
testing in order to determine whether those effects on fly ash can be reduced or eliminated.
Id
.
(referring to TSD § 8.4.4.3). Second, the Agency argues that “[s]orbent costs are also expected
to drop from the estimate in the TSD.” PC 6298 at 15. The Agency stresses Mr. Cichanowicz’s
testimony that expanded use of SCRs generated competition to supply the catalyst, which
substantially reduced prices for it.
Id
. The Agency expects that “a market for mercury sorbent
will attract competitors that will likely drive down prices.”
Id
.
The Agency argues that industry’s “exceedingly large” estimate of the cost of complying
with the proposal stems from Mr. Cichanowicz’s belief that sorbent injection would not produce
a 90% reduction in mercury emissions and that fabric filters would therefore be necessary at
plants burning PRB coal. PC 6298 at 14. The Agency discounts the basis of Mr. Cichanowicz’s
testimony on this issue by arguing that his view about any relationship between ESP size and
mercury removal efficiency “does not withstand analysis.” PC 6298 at 14. The Agency further
argues that Mr. Cichanowicz has misinterpreted the work of Dr. Clack (8/16Tr. at 740-64) and
has misunderstood testing at the Yates Unit 1 plant in Georgia (8/16Tr. at 640-42).
Id
.
Board Discussion of Economic Compliance
With regard to the economic reasonableness of the Agency’s proposal, Midwest
Generation has acknowledged that “[t]here is only a limited dispute as to the costs of various
mercury control equipment.” PC 6300 at 54. Instead, the Agency and the opponents of the
proposal strenuously disagree about the control equipment that must necessarily be installed in
order to comply with the proposal. The Agency states that “the evidence from actual test
programs supports the conclusion of Illinois EPA that sorbent injection will allow PRB coal-
fired units to meet the requirements of the proposed Illinois rule, supporting Illinois EPA’s cost
estimate.” PC 6298 at 14. The Agency estimates that “[t]he yearly additional control costs
associated with the Illinois rule are $33 million.” Exh. 51 at 8. In his testimony on behalf of the
Agency, Dr. Hausman translated that amount “into an average cost increase for the Illinois coal
plants of $0.375/MWh.”
Id
. Dr. Hausman further noted that “current retail prices in Illinois are
about $70.00/MWh and are likely to increase if price caps are removed as proposed.”
Id
.
Midwest Generation argues that testing to date has not shown that sorbent injection alone
is sufficient to comply with the Agency’s proposal. Accordingly, Midwest Generation believes
that EGUs cannot rely on sorbent injection alone and will have to install additional mercury
control equipment in order to avoid facing an enforcement action. Midwest Generation argues
that the Agency’s proposal will result in capital costs of more than $1 billion more than those
required by CAIR/CAMR. PC 6300 at 56. Including non-capital costs, Midwest Generation
claims that the Agency proposal would cost EGUs approximately $200 million each year for ten
years in addition to the costs required by CAIR/CAMR.
Id
. at 57, citing 8/18Tr. at 1301, Exh.
118 at 11.
78
In the preceding section of this opinion and order, the Board extensively addressed the
technological feasibility of the Agency’s proposal.
See supra
22. The Board found the
Agency’s proposal technically feasible by considering sorbent injection as the means to achieve
required reductions in mercury emissions for PRB coal-fired units along with the flexibility
offered by TTBS, MPS and averaging.
See supra
51. Based on this finding, the Board believes
that the annual incremental cost of compliance with the proposed rules instead of CAMR will be
consistent with the Agency’s estimate of $33 million rather than the compliance costs presented
by Midwest Generation and Kincaid. The Board recognizes that the cost for some units such as
those opting into MPS may be higher, but those costs also represent the cost of controlling SO
2
and NOx. In view of the significant reductions in mercury emissions expected by the
implementation of the proposed rules, the Board finds that the Agency’s proposal as amended is
economically reasonable.
Board Conclusion on Economic Reasonableness
The Board fully recognizes that the Agency proposal will result in costs for Illinois EGUs
and that those costs will exceed those required by implementation of CAMR. Nonetheless, the
Board noted above that, compared with CAMR, the Agency’s proposal reduces mercury
emissions more quickly and more deeply than CAMR. The Board concluded above on the basis
of the record in this proceeding that the proposed rule can be expected to result in reduction of
mercury deposition and to benefit the public health in the state. Therefore, the Board finds that
when the Agency’s estimated compliance costs are weighed against the expected benefits, the
proposed rule that the Board adopts today is economically reasonable.
LEGAL ISSUES
The participants have raised several legal issues concerning portions of the proposal.
Both Kincaid and Midwest Generation challenge the Board’s authority to adopt the language of
the MPS before proceeding to second notice. Specifically, Kincaid argues that the Board cannot
adopt the NO
x
and SO
2
provisions under Illinois and federal administrative law. PC 6299 at 19.
Kincaid also argues that adoption of NO
x
and SO
2
is prohibited by Section 27 of the Act (415
ILCS 5/27 (2004)) and SO
2
rules are prohibited by Section 10 of the Act (415 ILCS 5/10
(2004)). PC 6299 at 30. Midwest Generation joins Kincaid in challenging the inclusion of SO
2
limits as being a violation of Section 10 of the Act (415 ILCS 5/10 (2004)). PC 6300 at 29.
Kincaid and Midwest Generation argue that the U.S. Constitution precludes adoption of the
MPS. PC 6299 at 31; PC 6300 at 32.
In addition to the legal challenges concerning the MPS, Midwest Generation also argues
that the inability to measure mercury removal violates the Due Process Clause of the
Constitution. PC 6300 at 46. The Board will address each of the challenges in turn.
Illinois and Federal Administrative Law
Kincaid’s Comment
79
Kincaid argues that adoption of the MPS would violate both federal and State
administrative law because of the inclusion of NO
x
and SO
2
limits. PC 6299 at 19. Kincaid cites
numerous federal cases which establish that if the amendment is not a “logical outgrowth” of the
rulemaking, the amendment is improper. PC 6299 at 19-25. Kincaid argues that other states
have also confronted this issue and referenced and followed the federal holdings. PC 6299 at 26.
However, Kincaid has found no Illinois case law on point, but relies on Senn Park Nursing
Center v. Miller, 104 Ill. 2d 169, 470 N.E.2d 1029 (Ill. 1984) for support. In Senn Park, the
Illinois Supreme Court indicated that actual knowledge of a change by an appealing party was
not sufficient to satisfy the agency’s legal requirements for notice and comment as to the change.
PC 6299 at 27, citing Senn Park, 470 N.E.2d at 1035.
Kincaid asserts that the Board’s adoption of the MPS would violate the “fundamental and
long-established tenet of administrative law” that only amendments, which are a logical
outgrowth of the original proposal, may be adopted. PC 6299 at 27. The proposed rule did not
contain any reference to regulation of NO
x
and SO
2
so no potentially interested party would have
“any inkling” that NO
x
and SO
2
might be addressed in the final rule, argues Kincaid.
Id
.
Further, Kincaid asserts that the fact that the MPS is only one method of achieving compliance
does not relieve the Board from the requirements of the APA.
Id
.
Kincaid maintains that the failure to identify the MPS in the Board’s first notice has
specifically prejudiced Kincaid. PC 6299 at 28. Kincaid notes that no formal notice for the
concept of regulating SO
2
and NO
x
was ever provided and that, given the brief time between the
filing of the joint statement and the Board’s hearing, there was not adequate opportunity to
respond to the MPS in any meaningful manner. PC 6299 at 28. Kincaid argues that these are not
minor concerns as controls on SO
2
and NO
x
are highly technical and can cost tens or hundreds of
millions of dollars. PC 6299 at 28-29. Kincaid opines that for the Board to believe that Kincaid
could intelligently respond to such a significant departure from the original proposal in only ten
business days is arbitrary and capricious. PC 6299 at 29. Kincaid maintains that not only would
the adoption of the MPS violate fundamental and long established tenants of administrative law,
Kincaid would be directly harmed by any such adoption. PC 6299 at 29.
Midwest Generation’s Comment
Midwest Generation also questions whether regulation of SO
2
and NO
x
under mercury
regulation is appropriate. PC 6300 at 26. Midwest Generation argues that NO
x
and SO
2
have
nothing to do with the requirements to control mercury emissions and the inherent problems with
inclusion of NO
x
and SO
2
were “apparent” at the Chicago hearing. PC 6300 at 27-28. Midwest
Generation asserts that participants found themselves repeatedly asking questions concerning the
implications of the inclusion of NO
x
and SO
2
. PC 6300 at 28.
Agency’s Comment
The Agency comments that the proposed rule focuses on the control of mercury
emissions, but contains the optional MPS provisions so that companies can comply using an
alternative method. PC 6298 at 43. The Agency states that under the MPS, companies can
80
commit to voluntarily meet numerical emissions standards for NO
x
and SO
2
in return for
flexibility in complying with the mercury emissions standards. PC 6298 at 43-44.
Board Discussion of Illinois and Federal Administrative Law
The legal challenge to adopting the MPS presented here is simply that regulation of NO
x
and SO
2
is not a logical outgrowth of the regulation of mercury. If the MPS required every EGU
in the State to comply with NO
x
and SO
2
emissions standards, the Board might agree with the
arguments presented by Kincaid and Midwest Generation. However, the MPS does not require
every EGU in the State to comply with emissions standards for NO
x
and SO
2
. Rather, the MPS
establishes mercury emissions limits and to achieve those emissions limits, EGUs may elect to
utilize co-benefits realized from emissions reductions of NO
x
and SO
2
. An EGU that does not
choose to comply with the mercury rule using the MPS is not subject to NO
x
and SO
2
reductions
as a result of this rulemaking.
Control of mercury emissions and limits on those emissions is the subject of this
rulemaking. During the public rulemaking process, Ameren, Dynegy and the Agency put forth
an alternative method for compliance with the mercury emissions limits proposed in this
rulemaking. The proposal of this alternative, from the public and the proponent, is exactly the
type of change the Board anticipates when developing a rulemaking through the Board’s public
process. After reviewing a proposal, members of the regulated community may raise an
alternative with which the proponent can agree. The alternative is then suggested to the Board.
Ultimately, the Board’s acceptance of the MPS is a result of the public participating in this
proceeding and suggesting an alternative that better serves the individual companies proposing
the change, while meeting the goals of the proposal. Ameren, Dynegy, and the Agency have
suggested an alternative mercury emissions control plan, which happens to include limits on
other pollutants; but in the end, the alternative is a plan for the control of mercury emissions.
This rulemaking was proposed to and includes limits on mercury emissions. Therefore, the
Board finds that the suggested addition of the MPS from Ameren, Dynegy and the Agency is a
logical outgrowth of the process.
The record contains extensive comment from participants indicating that there are co-
benefits from controlling SO
2
and NO
x
emissions that reduce mercury emissions.
See
TSD at
199; 6/21pmTr. at 45-46, 51. Thus, the proposal of an alternative, designed to take advantage of
those co-benefits, is logical and an appropriate amendment to the rule.
The next challenge involves the timing of the proposed amendment. Kincaid argues that
by proposing such a significant departure from the original proposal, Kincaid did not have
sufficient time to prepare a response. PC 6299 at 29. Kincaid asserts that for the Board to
believe that Kincaid could respond is arbitrary and capricious.
Id
. The Board believes that
Kincaid has overstated the nature of the MPS proposal. The MPS is an alternative method for
compliance with the underlying standard, not a replacement of that standard. The inclusion of
the MPS will not change the underlying requirements that Kincaid must meet; the MPS is merely
an alternative for companies to consider. Nothing in the MPS would require any company to
utilize the MPS, each company must determine that on their own.
81
Thus, the proposal of the MPS by Ameren and the Agency at the time that prefiled
testimony was due for the second Board hearing was appropriate. The participants had time to
examine the language change and prepare questions for Ameren before the prefiling deadline of
August 7, 2006, for questions and hearing began on August 14, 2006. Many questions were
prefiled and Ameren and the Agency answered several follow-up questions.
See
CTr. at 1-442.
The participants then had until September 20, 2006, the deadline for public comment, to file
written post-hearing comments and further address the issue of the MPS. Both Kincaid and
Midwest Generation have filed extensive comments, which the Board today considers.
For the reasons discussed, the Board finds that adding the MPS language to the proposed
rule is consistent with federal and state administrative law. Further, the Board finds that the
submission of the joint statement at the time that prefiled testimony was due for the second
Board hearing did allow meaningful time for other participants to review the language and
develop questions.
Section 27 of the Act
Kincaid’s Comment
Kincaid notes that Section 27 of the Act (415 ILCS 5/27 (2004)) requires the Board to
consider the technical feasibility and economic reasonableness of “reducing the particular type of
pollution for which controls are sought.” PC 6299 at 30. Kincaid argues that there is no factual
basis in the record that the MPS is technically feasible and economically reasonable for Ameren
and Dynegy except for their acquiescence to the language.
Id
. Kincaid further asserts that there
is no basis in the record that the controls of the MPS are technically feasible and economically
reasonable for any facility other than Ameren and Dynegy. PC 6299 at 30-31. Kincaid
presented testimony that the MPS would not be technically feasible and economically reasonable
for Kincaid. PC 6299 at 31. Kincaid maintains that the Board cannot avoid Section 27
requirements for rulemaking simply by stating that the MPS requirement is only one option in a
broad array of options.
Id
.
Midwest Generation’s Comment
Midwest Generation argues that the Agency has a statutory burden in this rulemaking to
provide support for the proposal. PC 6300 at 6. Midwest Generation asserts that promulgation
of a rule where there is a lack of support would be arbitrary and capricious.
Id
. Further,
Midwest Generation asserts that Section 27 of the Act (415 ILCS 5/27 (2004)) requires the
Agency to demonstrate that the rule is technically feasible and economically reasonable. PC
6300 at 8, 50. Midwest Generation cites
Commonwealth Edison Co. v. PCB, 25 Ill. App. 3d
271, 323 N.E.2d 84 (1st Dist. 1974) to support the argument. Midwest Generation points to
language in Commonwealth Edison that defines “technically feasible” and “economically
reasonable” as a determination that the rule “is reasonable and capable of compliance by a
substantial number of individual units in the state” by a specified deadline. PC 6300 at 8, 50
citing Commonwealth Edison, 25 Ill. App. 3d at 281-82. Midwest Generation maintains that the
Agency has not demonstrated that the rule is technically feasible and economically reasonable.
PC 6300 at 8, 50.
82
Ameren’s Comment
Ameren disagrees with Kincaid and argues that adoption of the MPS will not violate
Section 27 of the Act (415 ILCS 5/27 (2004)); however, Ameren’s argument does not relate to
the issue of technical feasibility and economical reasonableness. PC 6301 at 12-14. Rather,
Ameren argues that Section 27 of the Act (415 ILCS 5/27 (2004)) allows the Board to include in
a rule of general applicability provisions that set different requirements for different sources,
areas, and companies. PC 6301 at 12-13.
Ameren asserts that Midwest Generation’s argument made in Midwest Generation’s oral
motion (
see
CTr. at 75-89) that the MPS cannot be included because this is a rule of general
applicability is erroneous. PC 6301 at 12-14. Ameren argues that Midwest Generation’s
reliance on
Commonwealth Edison, in the oral motion (
see
CTr. at 77), was misplaced. PC
6301 at 13. Ameren maintains that the court in
Commonwealth Edison held only that the Board
could choose not to make exceptions in rules of general applicability for individual companies
and not that the Board was prohibited from adopting different rules for different situations.
Id
.
Further, Ameren notes that none of the proposed rule revisions are directed at specific Illinois
EGUs, but rather allow flexibility for compliance with the mercury rule. PC 6301 at 13-14.
Different EGUs can choose how the company will ultimately comply from the options available
including the output based standard, a percent reduction standard, the TTBS, or the MPS. PC
6301 at 14. In Ameren’s opinion the fact that a company may not choose an option for
compliance has no bearing on the Board’s authority to adopt the option.
Id
.
Board Discussion of Section 27 of the Act
As to the issue of whether the record contains information sufficient to determine the
technical feasibility and economic reasonableness of the MPS, the Board refers to the discussion
infra
at 22 and 54. In essence, the Board has reviewed the record and based on the information
in the record found that the MPS is technically feasible and economically reasonable. As will be
discussed below, the Board is aware of the issues facing Kincaid in complying with any part of
this proposed rule. However, the individual problems faced by Kincaid can be addressed in
other forums. Generally, the Board believes the MPS offers a viable alternative for compliance.
Therefore, Kincaid’s argument that adoption of the MPS would violate Section 27 of the Act
(415 ILCS 5/27 (2004)) is not persuasive. The Board finds that because the Board has taken into
account the technical feasibility and the economic reasonableness of the MPS, the adoption of
the MPS is allowed under Section 27 of the Act (415 ILCS 5/27 (2004)).
The Board also rejects Midwest Generation’s argument that the rule violates Section 27
of the Act because the rule is not technically feasible and economically reasonable as defined by
the court in
Commonwealth Edison. As discussed
infra
at 53 and 78, the Board has found the
proposed rule to be technically feasible and economically reasonable. The Board finds that the
regulated community with one exception, Kincaid, can comply with the proposed rule as
amended at second notice. As discussed below, the Board believes that Kincaid should seek
relief from the rule requirements.
83
As to Ameren’s position that the Act allows the Board to adopt “exceptions” in a rule of
general applicability, the Board agrees with Ameren. The court in Commonwealth Edison
stated:
Substantive rules of this nature are promulgated for general, not special,
application. Consequently, investigators for the Board gather facts and solicit
expert advice in regard to pollution problems affecting all types of companies in a
particular trade. In a case like the present one, the Board would have been
charged with investigating facts and operations of all types of generating units --
single-and multi-unit, commercial, industrial, and public utility -- and from these
surveys extrapolate the appropriate principles and propose the necessary
regulations. The Board cannot be expected to research, evaluate, and make
allowance for every special, unusual, or unique problem involving every producer
of electrical energy. Where one fails to challenge the rules generally and instead
seeks to relax their enforcement against him exclusively due to arbitrary and
unreasonable hardship, the legislature has determined that the appropriate remedy
is for the aggrieved party to seek a variance in accordance with Title IX of the
Act. If that is denied, the aggrieved can petition to this court for review based on
the record at that proceeding. We hold, therefore, that Commonwealth's ‘as
applied’ argument cannot be raised at this stage of review. Commonwealth
Edison 25 Ill. App. 3d at 281, 323 N.E.2d at 90.
Plainly, the court’s finding is that an individual company cannot challenge the Board’s rules of
general applicability based on hardships associated with that individual company. However,
nothing in the court’s statements, nor the Act, limits the Board’s ability to develop compliance
alternatives for companies in a rule of general applicability.
The Board finds that the authority of the Board pursuant to the Act does allow the Board
to amend a rule of general applicability to create exceptions. In this case, the MPS is available to
all companies operating in the State. The Board is aware that Kincaid, due to its unique
circumstances, may not be able to utilize the MPS; however, that fact does not limit the Board’s
authority to adopt the MPS.
Section 10 of the Act
Kincaid’s Comment
Kincaid argues that Section 10 of the Act (415 ILCS 5/10 (2004)) prohibits the adoption
of SO
2
regulations and emissions standards for existing fuel combustion stationary emissions
sources outside Chicago, St. Louis, and Peoria Metropolitan areas unless those regulation are
necessary to meet the Primary National Ambient Air Quality Standards (NAAQS). PC 6299 at
30. Kincaid argues that there is no evidence in the record that the SO
2
portion of the MPS is
necessary for attaining and maintaining the SO
2
NAAQS.
Id
. Further, Kincaid notes that many
of Ameren’s and Dynegy’s facilities are located outside the three metropolitan areas.
Id
.
Kincaid maintains that the fact that the MPS is one method of achieving overall compliance with
84
the mercury proposal does not relieve the Board from the prescription of Section 10 of the Act
(415 ILCS 5/10 (2004)). PC 6299 at 30.
Midwest Generation’s Comment
Midwest Generation agrees with Kincaid that Section 10 of the Act (415 ILCS 5/10
(2004)) prohibits the adoption of SO
2
regulations. PC 6300 at 29. Midwest Generation argues
that the plain language of Section 10 is clear and limits the extent to which SO
2
can be regulated.
Id
. Midwest Generation asserts that as a result the Board cannot enact regulations that are more
restrictive than necessary to attain the primary or secondary NAAQS for SO
2
.
Id
. Midwest
Generation maintains that because there are no SO
2
nonattainment areas in the State, the Board
cannot adopt SO
2
limitations outside the three metropolitan areas. PC 6300 at 20. Midwest
Generation maintains that the record does not support inclusion of NO
x
and SO
2
because the
Agency can point to no requirements that are necessary for the State to comply with ozone or
particulate matter NAAQS. PC 6300 at 28.
Board Discussion of Section 10 of the Act
The Board is unpersuaded by the argument that Section 10(B) of the Act (415 ILCS
5/10(B) (2004)) prohibits adoption of the MPS. Section 10(B) of the Act (415 ILCS 5/10
(2004)) provides that the Board “shall adopt sulfur dioxide regulations and emissions
standards . . .” for the State, except for Chicago, St. Louis, and Peoria Metropolitan areas, that
are “not more restrictive than necessary to attain and maintain” the primary NAAQS SO
2
and
within a reasonable time the secondary NAAQS SO
2
. 415 ILCS 5/10(B)(1) (2004)).
Kincaid and Midwest Generation’s arguments must fail because the Board is not adopting
sulfur dioxide regulations in this rulemaking. The Board is developing a rule which limits the
emissions of mercury in the State. One compliance option for mercury emissions limitations is
the use of the MPS. The MPS will allow a source to voluntarily reduce SO
2
emissions to allow
for co-benefits that limits mercury emissions. If a source does not choose to use the MPS for
mercury control, there are no new emissions limits for SO
2
. Thus, the Board finds that Section
10 of the Act does not prohibit the adoption of the MPS language.
Supremacy Clause and Commerce Clause
Kincaid’s Comment
Kincaid argues that adoption of the MPS would violate both the Commerce Clause and
the Supremacy Clause of the U.S. Constitution. PC 6299 at 31-32. The Supremacy Clause
invalidates state laws that interfere with or are contrary to federal law; while the Commerce
Clause prohibits restrictions on interstate commerce.
Id
. Kincaid relies on Clean Air Markets v.
Pataki, 194 F. Supp. 2d 147 (N.D.N.Y. 2002) to support the argument.
Id
. Specifically, Kincaid
notes that in Clean Air Markets, New York passed a law restricting trading of SO
2
allowances
and the court found federal law preempted the restriction. PC 6299 at 31. Further, in
Clean Air
Markets, the court found that New York’s law imposed a burden on interstate commerce. PC
6299 at 32.
85
Kincaid notes that the MPS requires that SO
2
allowances be surrendered. Kincaid argues
that this surrender effectively prohibits trading of SO
2
allowances. PC 6299 at 31. Kincaid
maintains that surrendering of allowances, for the Agency to retire, reduces the size of
allowances available pursuant to Title IV of the CAA. Kincaid asserts that under the Supremacy
Clause and Clean Air Markets, Illinois cannot impede the CAA’s cap and nationwide SO
2
allowance trading systems. PC 6299 at 31-32. Therefore, Kincaid argues that the CAA may
preempt the MPS.
Further, Kincaid asserts that adoption of the MPS may violate the Commerce Clause. PC
6299 at 32. Kincaid states that like Clean Air Markets, the MPS may prohibit Illinois sources
from transferring SO
2
allowances in spite of the federal free-market system.
Id
.
Midwest Generation’s Comment
Midwest Generation too relies on
Clean Air Markets in arguing that the adoption of the
MPS would violate the Supremacy Clause and the Commerce Clause of the U.S. Constitution.
PC 6300 at 30-34. Midwest Generation’s arguments regarding the Supremacy Clause and the
Commerce Clause echo those presented by Kincaid and will not be repeated. However, Midwest
Generation also questions whether the MPS is a truly “voluntary” option for companies in
Illinois. PC 6300 at 30. Midwest Generation relies on U.S. v. Butler, 297 U.S. 1 (1936) for the
proposition that “voluntary” is not always “voluntary” in fact. PC 6300 at 30. In Butler, the
court determined that the price of refusing to comply was a loss of benefits and as a result the
“asserted power of choice is illusory” in that case. PC 6300 at 31, citing Butler 297 U.S. at 70-
71.
Midwest Generation argues that the underlying mercury rule is so stringent that
companies cannot comply with the requirements absent some relief. PC 6300 at 31. The only
option for delaying compliance is the MPS and the MPS is the only “safe harbor” according to
Midwest Generation.
Id
. Thus, Midwest Generation asserts that the “voluntary” language of the
MPS is illusory.
Id
.
Ameren’s Comment
Ameren disagrees with Kincaid and Midwest Generation and argues that
Clean Air
Markets does not apply to the MPS and federal law will not be violated by the adoption of the
MPS. PC 6301 at 14. Ameren argues that the MPS is significantly different from the New York
statute invalidated in
Clean Air Markets because the MPS has no direct impact on either out-of-
state or in-state EGUs that choose not to participate in the MPS.
Id
. Ameren points out that the
New York statute took revenues from the sale of allowances by New York EGUs to upwind
sources and required a restrictive covenant on all sales that prohibited sale to upwind sources.
PC 6301 at 15. Ameren argues that, by contrast, participation in the MPS is voluntary and does
not conflict with Title IV of the CAA.
Id
. According to Ameren, the voluntary nature of the
MPS eliminates the concern of the
Clean Air Markets court that the allowances be freely
transferable to any other person. PC 6301 at 16. Ameren maintains that by making the election
to participate in the MPS, the company is agreeing to freely transfer allowances to the Agency.
86
Id
. Ameren also asserts that Title IV of the CAA allows for transfer of allowances to the state
for retirement and that USEPA has entered into agreements, which required the surrender of
allowances. PC 6301 at 16-17.
Ameren maintains that the MPS does not discriminate against interstate commerce and,
therefore, does not violate the Commerce Clause. PC 6301 at 18. Ameren notes that the court in
Clean Air Markets struck down the statute because the law did not restrict or penalize transfer of
allowances between New York generators, the statute gave a preferred right of access to in-state
units over units in upwind states. PC 6301 at 19. Ameren argues that no such preference exists
with the MPS; both in-state and out-of-state utilities will be deprived of the surrendered
allowances.
Id
.
Agency’s Comment
The Agency agrees that the MPS does not allow trading of allowances that are generated
as a result of measures taken to comply with the MPS numeric emissions limits for NO
x
and SO
2
.
PC 6298 at 49. The allowances needed to meet the MPS limits are required to be retired or
surrendered on an annual basis; however, over-complying with the MPS limits can result in
allowances which may be sold or traded. PC 6298 at 50.
The Agency notes that under CAIR, certain allowances for SO
2
and NO
x
must be retired
each year. PC 6298 at 53. The Agency maintains that only the incremental amount of any
additional allowances retired as necessary to meet the MPS limits could have an impact on the
trading program.
Id
. The Agency asserts that there should be no additional NO
x
allowances
retried due to participation in the MPS.
Id
. The Agency further asserts that the impact on SO
2
allowances would also be minimal due to the region-wide scope of the trading program.
Id
.
Board Discussion of Supremacy Clause and Commerce Clause
The Board is not convinced that the adoption of the MPS will violate either the
Commerce Clause or the Supremacy Clause. Midwest Generation and Kincaid’s reliance on
Clean Air Markets is misplaced, as the facts of that case are obviously distinguishable from the
facts surrounding the MPS. In
Clean Air Markets, the New York statute clearly limited the
ability to trade allowances by among other things requiring that a restrictive covenant be placed
on an allowance when traded. The
Clean Air Markets court found that the restrictions on trading
violated both the Commerce Clause and the Supremacy Clause. However, that is not the case
with the MPS. The MPS does not restrict trading; rather, an allowance is surrendered to the
Agency, which in turn retires the allowance. Agreeing to participate in the MPS and thus placing
the company in the position of surrendering an allowance is voluntary. If a company does not
participate in the MPS, nothing in the rule limits the ability to trade, sell or purchase NO
x
and
SO
2
allowances. Therefore, the MPS is factually distinguishable from the New York statute and
is not contrary to the Commerce Clause or the Supremacy Clause.
As previously discussed, the Board finds that the MPS is voluntary. Nothing in the
language of the MPS requires a company to utilize the MPS. And in fact, the proposed rule
87
includes other options for compliance such as the TTBS and averaging. Therefore, the Board
finds that adopting the MPS is not contrary to the court’s decision in Butler.
Due Process Clause
Midwest Generation asserts that mercury emissions cannot be measured with sufficient
accuracy to determine compliance with or violation of the proposed rule. PC 6300 at 46. Thus,
according to Midwest Generation, the rule fails to provide adequate notice or fair notice as
required by the Due Process Clause of the US Constitution.
Id
. Midwest Generation maintains
that a regulation imposing a binding legal obligation must provide fair notice of those obligations
to the parties being regulated.
Id
. Midwest Generation relies on several cases to support this
proposition.
Id
. Those cases are General Electric Co. v. EPA, 53 F.3d 1324, 1328-29 (D.C. Cir.
1995); Trinity Broad. of Florida, Inc. v. FCC, 21 1 F.3d 618, 628 (D.C. Cir. 2000); United States.
v. Chrysler Corp., 158 F.3d 1350, 1355 (D.C. Cir. 1998); United States v. Hoechst Celanese
Corp., 128 F.3d 216, 224 (4th Cir. 1997); Diamond Roofing Co. v. OSHRC, 528 F.2d 645, 649
(5th Cir. 1976); Phelps Dodge Corp. v. FMSHRC, 681 F.2d 1189, 1193 (9th Cir. 1982).
Id
.
Midwest Generation argues that the monitoring technology required by the rule is not
accurate enough for a company to determine compliance with the rule; thus a company cannot
know if the emissions are in compliance. PC 6300 at 46. Midwest Generation argues that this
makes the proposed rule invalid because a company will not have proper notice of what is
compliant with the rule.
Id
.
Board Discussion of Due Process Clause
The Board finds that the rule does not violate the Due Process clause of the Constitution.
As discussed above, the measurement methods included in the proposal are nearly identical to
the measurement requirements of CAMR. Thus, even if the Board were to adopt CAMR, the
regulated community would be subject to the same requirements for measurement. Further, the
Board has found that the measurement methods proposed are technically feasible and will allow
for the measurement of mercury emissions. Therefore, the rule does give proper notice as to
what will be noncompliance and accordingly does not violate the Due Process Clause.
KINCAID
As discussed above, Kincaid believes that due to the unique aspects of Kincaid’s
operations, Kincaid is not eligible for the flexibilities in the proposed rule. PC 6299 at 14.
Further, the MPS also provides no relief for Kincaid, because Kincaid argues that reductions in
NO
x
and SO
2
required by the MPS are reductions Kincaid has already achieved. PC 6299 at 14.
Therefore, Kincaid asks the Board to include language that would be applicable to Kincaid that
would require Kincaid to install mercury control equipment on both units in 2009, disallows
trading of mercury allowances, and targets greater mercury reductions than CAMR, sooner. PC
6299 at 33.
The Board agrees that compliance with the rule as proposed, even with the inclusion of
the MPS and TTBS, is not feasible for Kincaid due to the unique circumstances of the facility in
88
Illinois. The Board has reviewed the amendments offered by Kincaid, but the Board does not
find the record adequately supports the changes suggested by Kincaid. Therefore, the Board
recommends that Kincaid seek relief from this rule of general applicability using the variance,
adjusted standard or site-specific rule provisions of the Act.
See
415 ILCS 5/28, 28.1, 35 (2004).
The Board notes that both Section 28.1(e) and Section 38(b) of the provide an automatic stay of
the rule of general applicability if the petition for adjusted standard or variance is filed within 20
days of the adoption of the rule. 415 ILCS 5/28.1, 38(b) (2004). This avenue for relief for
Kincaid, will allow Kincaid to work with the Agency to develop a complete record for the
Board’s consideration.
FEDERAL REQUIREMENTS
Kincaid’s Comment
Kincaid notes that under CAMR, each state must demonstrate that the emissions in the
state will meet the mercury cap established under CAMR. PC 6299 at 32. Kincaid asserts that
how demonstrating compliance with CAMR can be done if the Board adopts the MPS is unclear.
Id
. Kincaid maintains that if Ameren alone opts into the MPS, the emissions increase will be
500 pound.
Id
. Kincaid argues that if other sources opt into the MPS there is a question of
whether or not compliance with mercury cap can be achieved.
Id
.
Kincaid also asserts that the adoption of the MPS would not meet the federal
requirements for public participation in adoption of state regulations. PC 6299 at 33. Kincaid
argues that the public notice did not include any indication that SO
2
and NO
x
would be regulated
by the proposal.
Id
. Kincaid opines that any rule submitted to USEPA without proper public
participation must be rejected.
Id
.
Prairie State’s Comment
Prairie State is concerned that the proposed rule creates a future regulatory uncertainty
and one way to eliminate that uncertainty is to adopt CAMR’s model trading rule and layer the
Illinois requirement on top of the model trading rule. PC 6394 at 6-7. Prairie State believes that
this is necessary because if Illinois opts out of CAMR, then the CAMR mercury budget for
Illinois will be a hard cap on annual emissions in Illinois. PC 6294 at 7. Prairie State is troubled
that in 2018, utilities could be in compliance with the Illinois rule, but the total emissions could
exceed the CAMR budget.
Id
. If that were to happen, Prairie State argues that Illinois would
need to require more reductions of mercury because utilities could not purchase allowances from
other states.
Id
. Prairie State opines that one way for Illinois emissions to exceed the mercury
budget is if mercury control technologies do not perform a advertised and this is of particular
concern with high sulfur coals. PC 6294 at 8.
Environmental Advocates’ Comment
The Environmental Advocates argue that the proposed rule is consistent with CAMR,
while also being more advanced. PC 6297 at 2. The Environmental Advocates note that CAMR
gives states the option to develop their own regulatory approaches for the control of mercury.
Id
.
89
Environmental Advocates assert that the Agency’s proposal is more advanced and targeted than
CAMR in protecting the health, safety and welfare if Illinois residents and preserving Illinois’
natural environment.
Id
. Environmental Advocates opine that the question is not whether
mercury should be controlled, because CAMR does that, but rather whether the Agency’s
proposal “will produce public health and environmental benefits through deeper, faster
reductions than those mandated under CAMR in a manner that is reasonable for regulated
entities to achieve.”
Id
.
Agency’s Comment
The Agency asserts that the proposed rule is sufficiently stringent so as to not jeopardize
any exceedances of the CAMR caps. PC 6298 at 66. The Agency states that the budgeted
emissions for Illinois equate to a reduction in mercury emissions of approximately 47% by 2010
and 78% by 2018. PC 6298 at 65. Because the proposed rule targets 90% reductions beginning
in July 2009, compliance with the CAMR budgeted emissions should occur in both phase 1 an 2
of CAMR.
Id
. The Agency notes that the proposed rule does not include the CAMR budgeted
emissions because several factors could affect Illinois’ actual mercury emissions approaching the
CAMR budgeted emissions.
Id
. Those factors included growth in the industry and additional
emissions due to the TTBS and MPS.
Id
. However, the Agency does not believe that the
introduction of the additional flexibility in the rule significantly increases the emissions of
mercury so as to jeopardize the ability of Illinois to meet the CAMR budgeted emissions. PC
6298 at 66.
Specifically, the Agency asserts that with the MPS, by 2009, companies opting into the
MPS are required to install mercury controls that will achieve 90% reduction on all units except
certain small units. PC 6298 at 66. The small units are allowed delayed compliance until the
end of 2012.
Id
. The Agency argues that the additional emissions from these small units would
be minimal compared to the overall reductions and even after 2012, units not required to achieve
90% reduction must still achieve a high level of reduction. PC 6298 at 66-67.
The Agency also believes that the TTBS will not significantly impact Illinois meeting the
CAMR budgeted emissions limits. PC 6298 at 67. The Agency notes that under the TTBS only
25% of a company’s capacity is allowed to avoid the 90% reduction; however control is still
required.
Id
. The Agency asserts that the difference in emissions for a company utilizing the
TTBS will be small.
Id
Board Discussion
The Board is convinced that even with the TTBS and the MPS in the rule, there is little
potential for exceeding the CAMR cap. The Agency has indicated that the mercury emissions
reductions that will occur for companies utilizing the TTBS and the MPS are significant enough
to be within the CAMR cap. The Board agrees that with a target of 90% reduction, the amounts
that will be over that 90% reduction due to companies utilizing the TTBS or the MPS, will not
result in an exceedence of the CAMR cap. Because the Board does not find a potential for
exceedence of the CAMR cap, the Board will not consider trading in the rule.
90
The Board has previously addressed the issue of notice concerning the addition of the
MPS. Kincaid’s arguments do not persuade the Board to alter that prior discussion. The subject
of this rulemaking is mercury emissions control. The inclusion of an MPS that calls for co-
benefits to achieve the emissions standards is a logical outgrowth of the rule and the regulation
of SO
2
and NO
x
emissions is the result of a voluntary program. The Board finds that this
rulemaking has satisfied the public participation requirements of the USEPA.
Changes to the Rule
In addition to the inclusion of the MPS as discussed above, the Board has made changes
designed to make the rule more readable and to clarify the language. The Board will not discuss
those changes in detail, but the changes are shown in the rule language using strike-through and
underline.
CONCLUSION
The Board finds that the proposal, as amended in this opinion and order, is technically
feasible and economically reasonable. Further, the Board finds that the Board has the authority
to include the MPS in the proposal at second notice and the Board does so. The Board finds that
the rule allows flexibility to achieve compliance and will provide health benefits for the citizens
of Illinois. Therefore, the Board adopts the proposal for second notice and the rule will be
submitted to JCAR for second notice.
ORDER
The Board directs the Clerk to cause the filing of the following rule with the Joint
Committee on Administrative Rules for second-notice review.
TITLE 35: ENVIRONMENTAL PROTECTION
SUBTITLE B: AIR POLLUTION
CHAPTER I: POLLUTION CONTROL BOARD
SUBCHAPTER c: EMISSION STANDARDS AND LIMITATIONS FOR STATIONARY
SOURCES
PART 225
CONTROL OF EMISSIONS FROM LARGE COMBUSTION SOURCES
SUBPART A: GENERAL PROVISIONS
Section
225.100
Severability
225.120
Abbreviations and Acronyms
225.130
Definitions
225.140
Incorporations by Reference
91
SUBPART B: CONTROL OF MERCURY EMISSIONS FROM COAL-FIRED ELECTRIC
GENERATING UNITS
Section
225.200
Purpose
225.202
Measurement Methods
225.205
Applicability
225.210
Compliance Requirements
225.220
Clean Air Act Permit Program (CAAPP) Permit Requirements
225.230
Emission Standards for EGUs at Existing Sources
225.232
Averaging Demonstrations for Existing Sources
225.233
Multi Pollutant Standard (MPS)
225.234
Temporary Technology-Based Standard for EGUs at Existing Sources
225.235
Units Scheduled for Permanent Shut Down
225.237
Emission Standards for New Sources with EGUs
225.238
Temporary Technology-Based Standard for New Sources with EGUs
225.240
General Monitoring and Reporting Requirements
225.250
Initial Certification and Recertification Procedures for Emissions Monitoring
225.260
Out of Control Periods for Emission Monitors
225.261
Additional Requirements to Provide Heat Input Data
225.263
Monitoring of Gross Electrical Output
225.265
Coal Analysis for Input Mercury Levels
225.270
Notifications
225.290
Recordkeeping and Reporting
225.295
Treatment of Mercury Allowances
AUTHORITY: Implementing and authorized by Section 27 of the Environmental Protection Act
[415 ILCS 5/27].
SOURCE: Adopted at 30 Ill. Reg. _____, effective _________________.
SUBPART A: GENERAL PROVISIONS
Section 225.100
Severability
If any Section, subsection or clause of this Part is found invalid, such finding
must shall not
affect the validity of this Part as a whole or any Section, subsection or clause not found invalid.
Section 225.120
Abbreviations and Acronyms
Unless otherwise specified within this Part, the abbreviations used in this Part must shall be the
same as those found in 35 Ill. Adm. Code 211. The following abbreviations and acronyms are
used in this Part:
Act
Environmental Protection Act [415 ILCS 5]
Btu
British thermal unit
92
CAA
Clean Air Act [42 USC 7401 et seq.]
CAAPP
Clean Air Act Permit Program
CEMS
continuous emission monitoring system
CO
2
carbon dioxide
EGU
electric generating unit
GWh
gigawatt hour
hr
hour
lb
pound
MPS
Multi Pollutant Standard
MW
megawatt
MWe
megawatt electrical
MWh
megawatt hour
NO
x
nitrogen oxides
O
2
oxygen
RATA
relative accuracy test audit
SO
2
sulfur dioxide
TTBS
Temporary Technology Based Standard
USEPA
United States Environmental Protection Agency
Section 225.130
Definitions
The following definitions contained in this Section apply only to for the provisions purposes of
this Part. Unless otherwise defined in this Section and unless or a different meaning of for a
term is clear from it’s its context, the definitions of terms used in this Part shall have the
meanings specified for those terms in 35 Ill. Adm. Code 211.
“Agency” means the Illinois Environmental Protection Agency
“Agency” means the
Illinois Environmental Protection Agency.
[415 ILCS 5/3.105]
“Averaging demonstration” means, with regard to Subpart B of this Part, a demonstration
of compliance that is based on the combined performance of EGUs at two or more
sources.
“Base Emission Rate” means, for a group of EGUs subject to emission standards for NOx
and SO
2
pursuant to Section 225.233, the average emission rate of NOx or SO
2
from the
EGUs, in pounds per million Btu heat input, for calendar years 2003 through 2005 (or
,
for seasonal NOx, the 2003 through 2005 ozone seasons), as determined from the data
collected and quality assured by the USEPA pursuant to the 40 CFR 72 and 96 federal
Acid Rain and NOx Budget Trading Programs for
the emissions and heat input of the that
group of EGUs.
“Board” means the Illinois Pollution Control Board
“Board” means the Illinois Pollution
Control Board.
[415 ILCS 5/3.105]
93
“Boiler” means an enclosed fossil or other fuel-fired combustion device used to produce
heat and to transfer heat to recirculating water, steam, or other medium.
“Bottoming-cycle cogeneration unit” means a cogeneration unit in which the energy
input to the unit is first used to produce useful thermal energy and at least some of the
reject heat from the useful thermal energy application or process is then used for
electricity production.
“Coal” means any solid fuel classified as anthracite, bituminous, subbituminous, or
lignite by the American Society for Testing and Materials (ASTM) Standard
Specification for Classification of Coals by Rank D388-77, 90, 91, 95, 98a, or 99
(Reapproved 2004).
“Coal-derived fuel” means any fuel (whether in a solid, liquid or gaseous state) produced
by the mechanical, thermal, or chemical processing of coal.
“Coal-fired” means combusting any amount of coal or coal-derived fuel, alone or in
combination with any amount of any other fuel, during a specified year.
“Cogeneration unit” means a stationary, fossil fuel-fired boiler or a stationary, fossil fuel-
fired combustion turbine of which both of the following conditions are true:
Having It uses equipment used to produce electricity and useful thermal energy
for industrial, commercial, heating, or cooling purposes through the sequential use
of energy; and
Producing It produces either of the following during the 12-month period starting
beginning on the date the unit first produces electricity, and during any
subsequent calendar year after the calendar year that in which the unit first
produces electricity:
For a topping-cycle cogeneration unit
, both of the following:
Useful thermal energy not less than 5 five percent of total energy
output; and
Useful power that, when added to one-half of useful thermal
energy produced, is not less than 42.5 percent of total energy input,
if useful thermal energy produced is 15 percent or more of total
energy output, or not less than 45 percent of total energy input, if
useful thermal energy produced is less than 15 percent of total
energy output
.; or
For a bottoming-cycle cogeneration unit, useful power not less than 45
percent of total energy input.
94
“Combustion turbine” means:
An enclosed device comprising a compressor, a combustor, and a turbine and in
which the flue gas resulting from the combustion of fuel in the combustor passes
through the turbine, rotating the turbine; and
If the enclosed device under the above paragraph of this definition is combined
cycle, any associated heat recovery steam generator and steam turbine.
“Commence commercial operation” means, with regard to for the purposes of Subpart B
of this Part, with regard to an EGU Electric Generating Unit that serves a generator, to
have begun to produce steam, gas, or other heated medium used to generate electricity for
sale or use, including test generation. Such date must shall remain the unit's date of
commencement of operation even if the
EGU Electric Generating Unit is subsequently
modified, reconstructed or repowered.
“Designated representative” means,
with regard to for the purposes of Subpart B of this
Part, the same as defined in 40 CFR 60.4102.
“Flue” means a conduit or duct through which gases or other matter is exhausted to the
atmosphere.
“Gross electrical output” means the total electrical output from an EGU Electric
Generating Unit before making any deductions for energy output used in any way related
to the production of energy. For an EGU Electric Generating Unit generating only
electricity, the gross electrical output is the output from the turbine/generator set.
“Input mercury” means the mass of mercury that is contained in the coal combusted
within an EGU Electric Generating Unit.
“Nameplate capacity” means, starting from the initial installation of a generator, the
maximum electrical generating output (in MWe) that the generator is capable of
producing on a steady-state basis and during continuous operation (when not restricted by
seasonal or other deratings) as specified by the manufacturer of the generator or, starting
from the completion of any subsequent physical change in the generator resulting in an
increase in the maximum electrical generating output (in MWe) that the generator is
capable of producing on a steady-state basis and during continuous operation (when not
restricted by seasonal or other deratings), such increased maximum amount as specified
by the person conducting the physical change.
“Output-based emission standard” means,
with regard to for the purposes of Subpart B of
this Part, a maximum allowable rate of emissions of mercury per unit of gross electrical
output from an
EGU Electric Generating Unit.
95
“Repowered” means, with regard to for the purposes of an EGU, replacement of a coal-
fired boiler with one of the following coal-fired technologies at the same source as the
coal-fired boiler:
Atmospheric or pressurized fluidized bed combustion;
Integrated gasification combined cycle;
Magnetohydrodynamics;
Direct and indirect coal-fired turbines;
Integrated gasification fuel cells; or
As determined by the USEPA in consultation with the United States Department
of Energy, a derivative of one or more of the technologies under this definition
and any other coal-fired technology capable of controlling multiple combustion
emissions simultaneously with improved boiler or generation efficiency and with
significantly greater waste reduction relative to the performance of technology in
widespread commercial use as of January 1, 2005.
“Rolling 12-month basis” means, with regard to for the purposes of Subpart B of this
Part, a determination made on a monthly basis from the relevant data for a particular
calendar month and the preceding 11 calendar months (total of 12 months of data), with
two exceptions. For determinations involving one EGU, calendar months in which the
EGU does not operate (zero EGU operating hours) must shall not be included in the
determination, and must shall be replaced by a preceding month or months in which the
EGU does operate, so that the determination is still based on 12 months of data. For
determinations involving two or more EGUs, calendar months in which none of the
EGUs covered by the determination operates (zero EGU operating hours) must shall not
be included in the determination, and
must shall be replaced by preceding months in
which at least one of the EGUs covered by the determination does operate, so that the
determination is still based on 12 months of data.
Section 225.140
Incorporations by Reference
The following materials are incorporated by reference. These incorporations do not include any
later amendments or editions.
a)
40 CFR 60, § 60.17, § 60.45a, § 60.49a(k)(1), § 60.49a(p) and (p), § 60.50a(h), and
§§ 60.4170 through 60.4176 (2005).
b)
40 CFR 75 (2005).
96
c)
ASTM. The following methods from the American Society for Testing and
Materials, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken PA
19428-2959, (610) 832-9585:
1)
ASTM D388-77 (approved February 25, 1977), D388-90 (approved
March 30, 1990), D388-91a (approved April 15, 1991), D388-95
(approved January 15, 1995), D388-98a (approved September 10, 1998),
or D388-99 (approved September 10, 1999, reapproved in 2004),
Classification of Coals by Rank
(Reapproved 2004).
2)
ASTM D3173-03, Standard Test Method for Moisture in the Analysis
Sample of Coal and Coke (Approved April 10, 2003).
3)
ASTM D3684-01, Standard Test Method for Total Mercury in Coal by the
Oxygen Bomb Combustion/Atomic Absorption Method (Approved
October 10, 2001).
4)
ASTM D5865-04, Standard Test Method for Gross Calorific Value of
Coal and Coke (Approved April 1, 2004).
5)
ASTM D6414-01, Standard Test Method for Total Mercury in Coal and
Coal Combustion Residues by Acid Extraction or Wet Oxidation/Cold
Vapor Atomic Absorption (Approved October 10, 2001).
6)
ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method) (Approved April 10, 2002).
SUBPART B: CONTROL OF MERCURY EMISSIONS FROM COAL-FIRED ELECTRIC
GENERATING UNITS
Section 225.200
Purpose
The purpose of this Subpart B is to control the emissions of mercury from coal-fired electrical
generating units
operating in Illinois.
Section 225.202
Measurement Methods
Measurement of mercury
must shall be according to the following:
a)
Continuous emission monitoring pursuant to 40 CFR 75 (2005).
97
b)
ASTM D3173-03, Standard Test Method for Moisture in the Analysis Sample of
Coal and Coke (Approved April 10, 2003), incorporated by reference in Section
225.140.
c)
ASTM D3684-01, Standard Test Method for Total Mercury in Coal by the
Oxygen Bomb Combustion/Atomic Absorption Method (Approved October 10,
2001), incorporated by reference in Section 225.140.
d)
ASTM D5865-04, Standard Test Method for Gross Calorific Value of Coal and
Coke (Approved April 1, 2004), incorporated by reference in Section 225.140.
e)
ASTM D6414-01, Standard Test Method for Total Mercury in Coal and Coal
Combustion Residues by Acid Extraction or Wet Oxidation/Cold Vapor Atomic
Absorption (Approved October 10, 2001)
, incorporated by reference in Section
225.140.
f)
ASTM D6784-02, Standard Test Method for Elemental, Oxidized, Particle-Bound
and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources
(Ontario Hydro Method) (Approved April 10, 2002), incorporated by reference in
Section 225.140.
Section 225.205
Applicability
The following stationary coal-fired boilers and stationary coal-fired combustion turbines are
EGUs and are subject to this Subpart B:
a)
Except as provided in subsection (b) of this Section, a unit serving, at any time
since the start-up of the unit’s combustion chamber, a generator with nameplate
capacity of more than 25 MWe producing electricity for sale.
b)
For a unit that qualifies as a cogeneration unit during the 12-month period starting
on the date the unit first produces electricity and continues to qualify as a
cogeneration unit, a cogeneration unit serving at any time a generator with
nameplate capacity of more than 25 MWe and supplying in any calendar year
more than one-third of the unit's potential electric output capacity or 219,000
MWh, whichever is greater, to any utility power distribution system for sale. If a
unit qualifies as a cogeneration unit during the 12-month period starting on the
date the unit first produces electricity but subsequently no longer qualifies as a
cogeneration unit, the unit
must shall be subject to subsection (a) of this Section
starting on the day on which the unit first no longer qualifies as a cogeneration
unit.
Section 225.210
Compliance Requirements
a)
Permit Requirements
98
The owner or operator of each source with one or more EGUs subject to this
Subpart B at the source must apply for a CAAPP permit that addresses the
applicable requirements of this Subpart B.
b)
Monitoring Requirements
1)
The owner or operator of each source and each EGU at the source must
comply with the monitoring requirements of Sections 225.240 through
225.290 of this Subpart
B.
2)
The compliance of each EGU with the mercury requirements
of under
Sections 225.230 and 225.237 of this Subpart must shall be determined by
the emissions measurements recorded and reported in accordance with
Sections 225.240 through 225.290 of this Subpart
B.
c)
Mercury Emission Reduction Requirements
The owner or operator of any EGU subject to this Subpart
B must shall comply
with applicable requirements for control of mercury emissions of under Section
225.230 or Section 225.237 of this Subpart B.
d)
Recordkeeping and Reporting Requirements
Unless otherwise provided, the owner or operator of a source with one or more
EGUs at the source must shall keep on site at the source each of the documents
listed in subsections (d)(1) through (d)(3) of this Section for a period of five years
from the date the document is created. This period may be extended, in writing
by the Agency, for cause, at any time prior to the end of five years, in writing by
the Agency.
1)
All emissions monitoring information
, gathered in accordance with
Sections 225.240 through 225.290 of this Subpart.
2)
Copies of all reports, compliance certifications, and other submissions and
all records made or required or documents necessary to demonstrate
compliance with the requirements of this Subpart B.
3)
Copies of all documents used to complete a permit application and any
other submission under this Subpart B.
e)
Liability
1)
The owner or operator of each source with one or more EGUs
must shall
meet the requirements of this Subpart
B.
99
2)
Any provision of this Subpart B that applies to a source must shall also
apply to the owner and operator of such source and to the owner and
operator of each EGU at the source.
3)
Any provision of this Subpart B that applies to an EGU must shall also
apply to the owner and operator of such EGU.
f)
Effect on Other Authorities. No provision of this Subpart B must shall be
construed as exempting or excluding the owner
or and operator of a source or
EGU from compliance with any other provision of an approved State
Implementation Plan, a permit, the Act, or the CAA.
Section 225.220
Clean Air Act Permit Program (CAAPP) Permit Requirements
a)
Application Requirements
1)
Each source with one or more EGUs subject to the requirements of this
Subpart
B is required to submit a CAAPP permit application that
addresses all applicable requirements of this Subpart B, applicable to each
EGU at the source.
2)
For any EGU that commenced commercial operation:
A)
on or before December 31, 2008, the owner or operator of such
EGUs must submit an initial permit application or application for
CAAPP permit modification that meets the requirements of this
Section on or before by December 31, 2008.
B)
after December 31, 2008, the owner or operator of any such EGU
must submit an initial CAAPP permit application or application for
CAAPP modification that meets the requirements of this Section
not later than 180 days before initial startup of the EGU, unless the
construction permit issued for the EGU addresses the requirements
of this Subpart
B.
b)
Contents of Permit Applications
In addition to other information required for a complete application for CAAPP
permit or CAAPP permit modification, the application must shall include the
following information:
1)
The ORIS (Office of Regulatory Information Systems) or facility
code assigned to the source by the
U.S. Department of Energy,
Energy Information Administration, if applicable.
2)
Identification of each EGU at the source.
100
3)
The intended approach to the monitoring requirements of Sections
225.240 through 225.290 of this Subpart B.
4)
The intended approach to the mercury emission reduction
requirements of Section 225.230 or 225.237 of this Subpart B, as
applicable.
c)
Permit Contents
1)
Each CAAPP permit issued by the Agency for a source with one or more
EGUs subject to the requirements of this Subpart B must shall contain
federally enforceable conditions addressing all applicable requirements of
this Subpart
B, which conditions must shall be a complete and segregable
portion of the source’s entire CAAPP permit.
2)
In addition to conditions related to the applicable requirements of this
Subpart
B, each such CAAPP permit must shall also contain the
information specified under subsection (b) of this Section.
Section 225.230
Emission Standards for EGUs at Existing Sources
a)
Emission Standards
1)
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 shall comply with one of
the following standards for each EGU on a rolling 12-month basis:
A)
An emission standard of 0.0080 lb mercury/GWh gross electrical
output; or
B)
A minimum 90-percent reduction of input mercury.
2)
For an EGU complying with subsection (a)(1)(A) of this Section, the
actual mercury emission rate of the EGU for each 12-month rolling period,
as monitored in accordance with this Subpart
B and calculated as follows,
must shall not exceed the applicable emission standard:
∑
=
∑
=
=÷
12
i1
i
12
i1
ER
E
i
O
Where:
ER
= Actual mercury emissions rate of the EGU for the particular 12-
month rolling period, expressed in lb/GWh.
101
E
i
=
Actual mercury emissions of the EGU, in lbs, in an individual
month in the 12-month rolling period, as determined in accordance
with the emissions monitoring provisions of this Subpart
B.
O
i
=
Gross electrical output of the EGU, in GWh, in an individual
month in the 12-month rolling period, as determined in accordance
with Section 225.263 of this Subpart
B.
3)
For an EGU complying with subsection (a)(1)(B) of this Section, the
actual control efficiency for mercury emissions achieved by the EGU for
each 12-month rolling period, as monitored in accordance with this
Subpart
B and calculated as follows, must shall meet or exceed the
applicable efficiency requirement:
∑
=
∑
=
=×−
÷
12
i1
i
12
i1
CE 100 {1 (
E
i
I)}
Where:
CE
= Actual control efficiency for mercury emissions of the EGU for the
particular 12-month rolling period, expressed as a percent.
E
i
=
Actual mercury emissions of the EGU, in lbs, in an individual
month in the 12-month rolling period, as determined in accordance
with the emissions monitoring provisions of this Subpart
B.
I
i
=
Amount of mercury in the fuel fired in the EGU, in lbs pounds, in
an individual month in the 12-month rolling period, as determined
in accordance with Section 225.265 of this Subpart
B.
b)
Alternative Emission Standards for Single EGUs
1)
As an alternative to compliance with
one of the above emission standards
in subsection (a) of this Section, the owner or operator of the EGU may
comply with the emission standards of this Subpart
B by demonstrating
that the actual emissions of mercury from the EGU are less than the
allowable emissions of mercury from the EGU on a rolling 12-month
basis.
2)
For
this the purpose of demonstrating compliance with the alternative
emission standards of this subsection (b), for each rolling 12-month
period, the actual emissions of mercury from the EGU, as monitored in
accordance with this Subpart
B, must not exceed the allowable emissions
of mercury from the EGU, as further provided by the following formulas:
E
12
≤
A
12
∑
=
=
12
i1
E
12
E
i
102
∑
=
=
12
i1
A
12
A
i
Where:
E
12
= Actual mercury emissions of the EGU for the particular 12-month
rolling period.
A
12
= Allowable mercury emissions of the EGU for the particular 12-
month rolling period.
E
i
= Actual mercury emissions of the EGU in an individual month in the
12-month rolling period.
A
i
= Allowable mercury emissions of the EGU in an individual month in
the 12-month rolling period, based on either the input mercury to the unit
(A
Input i
) or the electrical output from the EGU (A
Output i
), as selected by the
owner or operator of the EGU for that given month.
A
Input i
= Allowable mercury emissions of the EGU in an individual month
based on the input mercury to the EGU, calculated as 10.0 percent (or
0.100) of the input mercury to the EGU.
A
Output i
= Allowable mercury emissions of the EGU in a particular month
based on the electrical output from the EGU, calculated as the product of
the output based mercury limit, i.e., 0.0080 lb/GWh, and the electrical
output from the EGU, in GWh.
3)
If the owner or operator of an EGU does not conduct the necessary
sampling, analysis, and recordkeeping, in accordance with Section
225.265 of this Subpart
B, to determine the mercury input to the EGU, the
allowable emissions of the EGU must be calculated based on the electrical
output of the EGU.
c)
If two or more EGUs are served by common stack(s) and the owner or operator
conducts monitoring for mercury emissions in the common stack(s), as provided
for by 40 CFR 75, Subpart I, such that the mercury emissions of each EGU are
not determined separately, compliance of the EGUs with the applicable emission
standards of this Subpart
B must shall be determined as if the EGUs were a single
EGU.
d)
Alternative Emission Standards for Multiple EGUs
1)
As an alternative to compliance with the emission standards of subsection
(a) of this Section, the owner or operator of a source with
multiple an
EGUs
may comply with the emission standards of this Subpart B by
demonstrating that the actual emissions of mercury from all EGUs at the
source are less than the allowable emissions of mercury from all EGUs at
the source on a rolling 12-month basis.
103
2)
For
this the purposes of the alternative emission standard of subsection
(d)(1) of this Section, for each rolling 12-month period, the actual
emissions of mercury from all the EGUs at the source, as monitored in
accordance with this Subpart
B, must not exceed the sum of the allowable
emissions of mercury from all the EGUs at the source, as further provided
by the following formulas:
E
S
≤
A
S
∑
=
=
n
i1
E
S
E
i
∑
=
=
n
i1
A
S
A
i
Where:
E
S
= Sum of the actual mercury emissions of the EGUs at the source.
A
S
= Sum of the allowable mercury emissions of the EGUs at the source.
E
i
= Actual mercury emissions of an individual EGU at the source, as
determined in accordance with subsection (b)(2) of this Section.
A
i
= Allowable mercury emissions of an individual EGU at the source, as
determined in accordance with subsection (b)(2) of this Section.
n = Number of EGUs covered by the demonstration.
3)
If an owner or operator of a source with two or more EGUs that is relying
on this subsection (d) to demonstrate compliance fails to meet the
requirements of this subsection (d) in a given 12-month rolling period, all
EGUs at such source covered by the compliance demonstration are
considered out of compliance with the applicable emission standards of
this Subpart
B for the entire last month of that period.
Section 225.232
Averaging Demonstrations for Existing Sources
a)
Through December 31, 2013, as an alternative to compliance with the emission
standards of Section 225.230(a) of this Subpart
B, the owner or operator of an
EGU may comply with the emission standards of this Subpart
B by means of an
Averaging Demonstration (Demonstration) that
demonstrates shows that the
actual emissions of mercury from the EGU and other EGUs at the source and
other EGUs at other sources covered by the Demonstration are less than the
allowable emissions of mercury from all EGUs covered by the Demonstration on
a rolling 12-month basis.
104
b)
The EGUs at each source covered by a Demonstration must also comply with one
of the following emission standards on a source-wide basis for the period covered
by the Demonstration:
1)
An emission standard of 0.020 lb mercury/GWh gross electrical output; or
2)
A minimum 75 percent reduction of input mercury.
c)
For the purpose of this Section, compliance
must shall be determined
demonstrated using the equations in Section 225.230(a)(2), (a)(3), or (d)(2) of this
Subpart, as applicable, addressing all EGUs at the sources covered by the
Demonstration, rather than
by using only the EGUs at one source.
d)
Limitations on Demonstrations
1)
The owners or operators of more than one existing source with EGUs can
only participate in Demonstrations that include other existing sources that
they own or operate.
2)
Single Existing Source Demonstrations
A)
The owner or operator of only a single existing source with EGUs
(i.e., City, Water, Light & Power, City of Springfield, ID
167120AAO;
Electric Energy, Inc., ID 127855AAC; Kincaid
Generating Station, ID 021814AAB; and Southern Illinois Power
Cooperative/Marion Generating Station, ID 199856AAC) can only
participate in Demonstrations with other such owners or operators
of a single existing source of EGUs.
B)
Participation in Demonstrations under this Section by the owner or
operator of only a single existing source with EGUs must be
authorized through federally enforceable permit conditions for
each such source participating in the Demonstration.
e)
A source may be included in only one Demonstration during each rolling 12-
month period.
f)
The owner or operator of EGUs using Demonstrations to show compliance with
this Subpart
B must complete the determination of compliance for each 12-month
rolling period no later than 60 days following the end of the period.
g)
If averaging is used to demonstrate compliance with this Subpart
B, the effect of a
failure to demonstrate compliance
must shall be that the compliance status of each
source
must shall be determined under Section 225.230 of this Subpart B as if the
sources were not covered by a Demonstration.
105
h)
For purposes of this Section, if the owner or operator of any source that
participates in a Demonstration with an owner or operator of a source that does
not maintain the required records, data, and reports for the EGUs at the source, or
that does not submit copies of such records, data, or reports to the Agency upon
request, then the effect of this failure will be deemed to be a failure to
demonstrate compliance and the compliance status of each source
must shall be
determined under Section 225.230 of this Subpart
B as if the sources were not
covered by a Demonstration.
Section 225.233
Multi-Pollutant Standards (MPS)
a)
General
.
1)
As an alternative to compliance with the emissions standards of Section
225.230(a)
of this Subpart, the owner of eligible EGUs may elect for such
those EGUs to comply with demonstrate compliance pursuant to this
Section, which establishes control requirements and standards for
emissions of NO
x
and SO
2
, as well as for emissions of mercury.
2)
For the purpose of this Section
, the following requirements apply:
A)
An eligible EGU is an EGU
that is located in Illinois that and
which commenced commercial operation on or before December
31, 2004
.; and
B)
For the purposes of this Section, ownership Ownership of an
eligible EGU is determined based on direct ownership,
or by the
holding a majority interest in a company that owns an the EGU or
EGUs
, or by the common ownership of the company that owns the
EGU, whether through a
parent /subsidiary parent-subsidiary
relationship, as a sister corporation, or as an affiliated corporation
with the same parent corporation, provided that the owner has the
right or authority to submit a CAAPP application on behalf of the
EGU.
3)
The owner of one or more EGUs electing to
comply demonstrate
compliance with this Subpart B by means of purusant to this Section must
submit an application for a CAAPP permit modification to the Agency, as
provided in Section 225.220
of this Subpart, that includes the information
specified in subsection (b) of this Section and
that which clearly states the
owner’s election to
comply with the provisions of demonstrate compliance
pursuant to this Section 225.233.
A)
If the owner of one or more EGUs elects to
comply with
demonstrate compliance with this Subpart by means of purusant to
106
this Section, then all EGUs it owns in Illinois as of July 1, 2006, as
defined in subsection (a)(2)(B) of this Section,
must shall be
thereafter subject to the standards and control requirements of this
Section, except as provided in subsection (a)(3)(B) below. Such
EGUs
must shall be referred to as an a Multi-Pollutant Standard
(MPS) Group.
B)
Notwithstanding the foregoing, the owner may exclude from
the an
MPS Group any EGU scheduled for permanent shutdown that the
owner so designates in its CAAPP application required to be
submitted pursuant to subsection (a)(3)
of this Section, with
compliance for such
unit(s) units to be achieved by means of
Section 225.235
of this Subpart.
4)
When an EGU is subject to
the requirements of this Section, the
requirements
of this Section must shall apply to all owners and operators
of the EGU, and to the designated representative for the EGU.
b)
Notice of Intent
.
The owner of one or more EGUs that intends to comply with this Subpart
B by
means of this Section
must shall notify the Agency of its intention by December
31, 2007
,. which notification must shall be accompanied by the The following
information must accompany the notification
:
1)
Identification The identification of each of the EGUs EGU that will be
complying with this Subpart
B by means of the multi-pollutant standards
contained in this Section, with evidence that the owner has identified all
EGUs that
its owns it owned in Illinois as of July 1, 2006, and that which
commenced commercial operation on or before December 31, 2004.;
2)
If an EGU identified
in subsection (b)(1) of this Section above is also
owned or operated by
an entity a person different than the owner
submitting the notice of intent, a demonstration that the submitter has the
right to commit the EGU or authorization from the responsible official for
the EGU accepting the application
.;
3)
The Base Emission Rates for the EGUs, with copies of supporting data
and calculations
.;
4)
A summary of the current control devices
installed and operating on the
EGUs each EGU and identification of the additional control devices that
will likely be needed for the
the EGUs each EGU to comply with emission
control requirements of this
section Section, including identification of the
EGUs each EGU in the MPS group that will be addressed by subsection
107
(c)(1)(B) of this Section, with information showing that the eligibility
criteria for this
paragraph subsection (b) are satisfied.; and
5)
Identification of
any each EGU or EGUs that are is scheduled for
permanent shut down, as provided by Section 225.235, which will not be
part of the MPS Group and
which will not be complying demonstrating
compliance with this Subpart B by means of pursuant to this Section.
c)
Control Technology Requirements for Emissions of Mercury
:.
1)
Requirements for EGUs in an MPS Group.
A)
For each EGU in an MPS Group other than an EGU that is
addressed by
paragraph subsection (c)(1)(B) of this Section for the
period beginning July 1, 2009 (or December 31, 2009 for an EGU
for which an SO
2
scrubber or fabric filter is being installed to be in
operation by December 31, 2009), and ending on December 31,
2014
(or such earlier date that the EGU is subject to the mercury
emission standard in subsection (d)(1) of this Section), the owner
or operator of the EGU
must shall install, to the extent not already
installed, and properly operate and maintain one of the following
emissions control devices
:
i)
A Halogenated Activated Carbon Injection System,
complying with the sorbent injection requirements of
subsection (c)(2) of this Section, except as may be
otherwise provided by subsection (c)(4) of this Section, and
followed by a Cold-Side Electrostatic Precipitator or Fabric
Filter; or
ii)
If the boiler fires bituminous coal, a Selective Catalytic
Reduction (SCR) System and an SO
2
Scrubber.
B)
An owner of an EGU
in an MPS Group has two options under this
subsection
(c). For an MPS Group that contains EGUs smaller
than 90 gross MW in capacity, the owner may designate any such
EGUs to be not subject to subsection (c)(1)(A) of this
section
Section
. Or, for an MPS Group that contains EGUs with gross
MW capacity of less than 115 MW, the owner may designate any
such EGUs to be not subject to subsection (c)(1)(A) of this
Section, provided that the aggregate gross MW capacity of
such
the designated EGUs does not exceed 4% of the total gross MW
capacity of the MPS Group. For
such EGUs any EGU subject to
one of these two options, unless the EGU is subject to the emission
standards in subsection (d)(2) of this Section, beginning on January
1, 2013, and continuing until such date that the owner or operator
108
of the EGU commits to comply with the mercury emission
standard in subsection (d)(2) of this Section, the owner or operator
of the EGU
must shall install and properly operate and maintain a
Halogenated Activated Carbon Injection System
, complying that
complies with the sorbent injection requirements of subsection
(c)(2)
of this Section, except as may be otherwise provided by
subsection (c)(4) of this Section, and followed by either a Cold-
Side Electrostatic Precipitator or Fabric Filter. The use of a
properly installed, operated
, and maintained Halogenated
Activated Carbon Injection System that meets the sorbent injection
requirements of subsection (c)(2) of this Section is
referred to
defined as the “principal control technique.”
2)
For each EGU for which injection of halogenated activated carbon is
required by subsection (c)(1) of this Section, the owner or operator of the
EGU
must shall inject halogenated activated carbon in an optimum
manner, which, except as provided in subsection (c)(4) of this Section,
must shall be deemed to be is defined as all of the following:
A)
Use The use of an injection system designed for effective
absorption of mercury, considering the configuration of the EGU
and its ductwork;
B)
The injection of halogenated activated carbon manufactured by
Alstom, Norit, or Sorbent Technologies, or the injection of
any
other halogenated activated carbon or sorbent that the owner or
operator of the EGU
shows has demonstrated to have similar or
better effectiveness for control of mercury emissions; and
C)
The injection of sorbent at the following minimum rates, as
applicable:
i)
For an EGU firing subbituminous coal, 5.0
lbs pounds per
million actual cubic feet or
, for any cyclone-fired EGU that
will install a scrubber and baghouse by December 31, 2012
,
and
which already meeting meets an emission rate of 0.020
lb mercury/GWh gross electrical output or at least 75
percent reduction of input mercury, 2.5
lbs pounds per
million actual cubic feet
.;
ii)
For an EGU firing bituminous coal, 10.0
lbs pounds per
million actual cubic feet or for any cyclone-fired EGU that
will install a scrubber and baghouse by December 31, 2012,
and
which already meeting meets an emission rate of 0.020
lb mercury/GWh gross electrical output or at least 75
109
percent reduction of input mercury, 5.0
lbs pounds per
million actual cubic feet
.;
iii)
For an EGU firing a blend of subbituminous and
bituminous coal, a rate that is the weighted average of the
above rates, based on the blend of coal being fired
.; or
iv)
A rate or rates
set lower by the Agency, in writing, than the
rate specified
above may be set in any of subsections
(c)(2)(C)(i), (c)(2)(C)(ii), or (c)(2)(C)(iii) of this Section on
a unit-specific basis
, to the extent provided that the owner
or operator of the EGU
demonstrates has demonstrated that
such rate or rates are needed so that carbon injection will
not increase particulate matter emissions or opacity so as to
threaten
compliance noncompliance with applicable
requirements for particulate matter or opacity.
D)
For
the purposes of this subsection (c)(2)(C) of this Section this
purpose, the flue gas flow rate must shall 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 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.
3)
The owner or operator of an EGU that seeks to operate an EGU with an
activated carbon injection rate or rates that are set on a unit-specific basis
pursuant to subsection (c)(2)(C)(iv) of this Section
must shall submit an
application to the Agency proposing such rate or rates, and
must shall
meet the
following requirements of subsections (c)(3)(A) and (c)(3)(B) of
this Section, subject to the limitations of subsections (c)(3)(C) and
(c)(3)(D) of this Section:
A)
The application
must shall be submitted as an application for a new
or revised federally enforceable operating permit for the EGU
, and
it must include a summary of relevant mercury emission data for
the EGU, the unit-specific injection rate or rates that are proposed
,
and detailed information to support the proposed injection rate or
rates
.; and
B)
This application
must shall be submitted no later than the date that
activated carbon must first be injected. For example, the owner or
operator of an EGU that must inject activated carbon pursuant to
subsection (c)(1)(A) of this subsection
must shall apply for unit-
110
specific injection rate or rates by July 1, 2009. Thereafter, the
owner or operator of the EGU may supplement its application.
C)
The Any decision of the Agency denying a permit or granting a permit
with conditions that set a lower injection rate or rates may be appealed to
the Board pursuant to Section 39 of the Act
.; and
D)
The owner or operator of an EGU may operate at the injection rate or rates
proposed in its application until a final decision is made on the
application, including a final decision on any appeal to the Board.
4)
During
an any evaluation of the effectiveness of a listed sorbent, an
alternative sorbent, or other technique to control mercury emissions, the
owner or operator of an EGU need not comply with the requirements of
subsection (c)(2) of this Section for
such any system as needed to carry
out
an the evaluation of the practicality and effectiveness of such
technique, as further provided below:
A)
The owner or operator of the EGU
must shall conduct the
evaluation in accordance with a formal evaluation program
submitted to the
Agency Illinois EPA at least 30 days in advance.
prior to commencement of the evaluation;
B)
The duration and scope of the evaluation
must shall may not
exceed the duration and scope reasonably needed to complete the
desired evaluation of the alternative control technique, as initially
addressed by the owner or owner in a support document submitted
with the evaluation program
.;
C)
The owner or operator of the EGU
must shall submit a report to the
Agency Illinois EPA no later than 30 days after the conclusion of
the evaluation
describing that describes the evaluation that was
conducted and providing which provides the results of the
evaluation
.; and
D)
If the evaluation of the alternative control technique shows less
effective control of mercury emissions from the EGU than
was
achieved with the principal control technique, the owner or
operator of the EGU
must shall resume use of the principal control
technique. If the evaluation of the alternative control technique
shows comparable effectiveness to the principal control technique,
the owner or operator of the EGU may either continue to use the
alternative control technique in a manner that is at least as effective
as the principal control technique
, or it may resume use of the
principal control technique. If the evaluation of the alternative
control technique shows more effective control of mercury
111
emissions
than the control technique, the owner or operator of the
EGU
must shall continue to use the alternative control technique in
a manner that is more effective than the principal control
technique,
if so long as it continues to be subject to this subsection
(c) of this Section.
5)
In addition to complying with the applicable recordkeeping and
monitoring requirements in Sections 225.240 through 225.290
of this
Subpart, the owner or operator of an EGU electing that elects to comply
with this Subpart
B by means of this Section must shall also comply
with the following additional requirements:
A)
For the first 36 months that injection of sorbent is required,
it must
maintain records of the usage of sorbent, the exhaust gas flow rate
from the EGU, and the sorbent feed rate, in pounds per million
actual cubic feet of exhaust gas at the injection point, on a weekly
average
.;
B)
After the first 36 months that injection of sorbent is required,
it
must monitor activated sorbent feed rate to the EGU, flue gas
temperature at the point of sorbent injection, and exhaust gas flow
rate from the EGU, automatically recording this data and the
sorbent carbon feed rate, in pounds per million actual cubic feet of
exhaust gas at the injection point, on an hourly average
.; and
C)
If a blend of bituminous and sub-bituminous coal is fired in the
EGU,
it must keep records of the amount of each type or coal
burned and the required injection rate for injection of activated
carbon, on a weekly basis.
6)
In addition to complying with the applicable reporting requirements in
Sections 225.240 through 225.290
of this Subpart , the owner or operator
of an EGU
electing that elects to comply with this Subpart B by means of
this Section
must shall also submit quarterly reports for the recordkeeping
and monitoring conducted pursuant to subsection (c)(5) of this Section.
d)
Emission Standards for Mercury
.
1)
For each EGU in an MPS Group that is not addressed by subsection
(c)(1)(B) of this Section, beginning January 1, 2015 (or such earlier date
that when the owner or operator of the EGU notifies the Agency that it
will comply with these standards) and
continuing thereafter, the owner or
operator of the EGU
must shall comply with one of the following
standards on a rolling 12-month basis:
112
A)
An emission standard of 0.0080 lb mercury/GWh gross electrical
output; or
B)
A minimum 90-percent reduction of input mercury.
2)
For each EGU in an MPS Group that has been addressed under subsection
(c)(1)(B) of this Section, beginning on the date
that when the owner or
operator of the EGU notifies the Agency that it will comply with these
standards and
continuing thereafter, the owner or operator of the EGU
must shall comply with one of the following standards on a rolling 12-
month basis:
A)
An emission standard of 0.0080 lb mercury/GWh gross electrical
output; or
B)
A minimum 90-percent reduction of input mercury.
3)
Compliance with the mercury emission standard or reduction requirement
of this subsection (d) must shall be calculated in accordance with Section
225.230(a) or (d)
of this Subpart.
e)
Emission Standards for NO
x
and SO
2
.
1)
NO
x
Emission Standards:.
A)
Beginning in calendar year 2012, and
continuing in each calendar
thereafter, for the EGUs in each MPS Group, the
owners owner
and operators operator of the EGUs must shall comply with an
overall NOx annual emission rate of no more than 0.11 lbs/million
Btu or
a an emission rate equivalent to 52 percent of the Base
Annual Rate of NO
x
emissions, whichever is more stringent.
B)
Beginning in the 2012 ozone season and
continuing in each ozone
season thereafter, for the EGUs in each MPS Group, the
owners
owner and operators operator of the EGUs must shall comply with
an overall NO
x
seasonal emission rate of no more than 0.11
lbs/million Btu or
a an emission rate equivalent to 80 percent of the
Base Seasonal Rate of NO
x
emissions, whichever is more
stringent.
2)
SO
2
Emissions Standards:.
A)
Beginning in calendar year 2013 and continuing in calendar year
2014, for the EGUs in each MPS Group, the
owners owner and
operators operator of the EGUs must shall comply with an overall
SO
2
annual emission rate of 0.33 lbs/million Btu or a rate
113
equivalent to 44 percent of the Base Rate of SO
2
emissions,
whichever is more stringent.
B)
Beginning in calendar year 2015, and continuing in each calendar
year thereafter, for the EGUs in each MPS Grouping, the
owners
owner and operators operator of the EGUs must shall comply with
an overall annual emission rate for SO
2
of 0.25 lbs/million Btu or a
rate equivalent to 35 percent of the Base Rate of SO
2
emissions,
whichever is more stringent.
3)
Compliance with the NO
x
and SO
2
emission standards must shall be
determined demonstrated in accordance with Sections 225.310, 225.410,
and 225.510
of this Part. The owners owner or operators operator of
EGUs must complete the
determination demonstration of compliance by
before March 1 of the following year for annual standards and by before
November 1 for seasonal standards, by which date a compliance report
must shall be submitted to the Agency.
f)
Requirements for NO
x
and SO
2
Allowances.
1)
The
owners owner or operators operator of EGUs in an MPS Group must
shall not sell or trade to any person or otherwise exchange with or give to
any person NO
x
allowances allocated to the EGUs in the MPS Group for
vintage years 2012 and beyond that would otherwise be available for sale,
trade
, or exchange as a result of actions taken to comply with the standards
in subsection (e) of this Section. Such allowances that are not retired for
compliance
must shall be surrendered to the Agency on an annual basis,
beginning in calendar year 2013. This provision does not apply to the use,
sale, exchange, gift
, or trade of allowances among the EGUs in an MPS
Group.
2)
The owners or operators of EGUs in an MPS Group
must shall not sell or
trade to any person or otherwise exchange with or give to any person
SO2
SO
2
allowances allocated to the EGUs in the MPS Group for vintage years
2013 and beyond that would otherwise be available for sale or trade as a
result of actions taken to comply with the standards in subsection (e) of
this Section. Such allowances that are not retired for compliance or
otherwise surrendered pursuant to a consent decree to which the State of
Illinois is a party,
must shall be surrendered to the Agency on an annual
basis, beginning in calendar year 2014. This provision does not apply to
the use, sale, exchange, gift
, or trade of allowances among the EGUs in an
MPS Group.
3)
The provisions of this subsection
(f) do not restrict or inhibit the sale or
trading of allowances that become available from one or more EGUs in a
MPS Group as a result of holding allowances that represent over-
114
compliance with the NO
x
or SO
2
standard in subsection (e) of this Section,
once such a standard becomes effective, whether such over-compliance
results from control equipment, fuel changes, changes in the method of
operation
, or unit shut downs, or for other reasons.
4)
For purposes of this subsection
(f), NO
x
and SO
2
allowances must shall
mean allowances necessary for compliance with Sections 225.310,
225.410,
or 225.510 of this Part, 40 CFR Part 72, or Subparts AA and
AAAA of 40 CFR 96.101, et seq., and 40 CFR 96.301, et seq. The
provisions of this This Section do does not prohibit the owners owner or
operators operator of EGUs in an MPS Group from purchasing or
otherwise obtaining allowances from other sources as allowed by law for
purposes of complying with federal or state requirements,
excluding
except as specifically the requirements of set forth in this Section.
5)
By Before March 1, 2010, and continuing each year thereafter, the owner
or operator of EGUs in an MPS Group
must shall submit a report to the
Agency
demonstrating that demonstrates compliance with the
requirements of this subsection
(f) for the previous calendar year, and
which must shall include includes identification of any allowances that
have been surrendered to the USEPA or to the Agency
, and identification
of any allowances that were sold, gifted, used, exchanged, or traded
because they became available due to over-compliance.
All allowances
that are required to be surrendered must be surrendered by August 31,
unless USEPA has not yet deducted the allowances from the previous
year. A final report must be submitted to the Agency by August 31 of
each year, verifying that the actions described in the initial report have
taken place or, if such actions have not taken place, an explanation of all
changes that have occurred and the reasons for such changes. If USEPA
has not deducted the allowances from the previous year by August 31, the
final report must be due, and all allowances required to be surrendered
must be surrendered, within 30 days after such deduction occurs.
g)
Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied
with the applicable emission standards of subsections (d) and (e) of this Section
for 12 months, the owner or operator of the EGU
must shall obtain a construction
permit for any new or modified air pollution control equipment
proposed that it
proposes to be constructed construct for control of emissions of mercury, NO
x
, or
SO
2
.
Section 225.234 Temporary Technology-Based Standard for EGUs at Existing Sources
a)
General
.
1)
At a source with EGUs that commenced commercial operation on or
before December 31, 2008, for an EGU that meets the eligibility criteria in
115
subsection (b) of this Section,
as an alternative to compliance with the
mercury emission standards in Section 225.230 of this Subpart, the owner
or operator of the EGU may temporarily comply with the requirements of
this Section
, through June 30, 2015 as an alternative to compliance with
the mercury emission standards in Section 225.230, as further provided in
subsections (c), (d), and (e) of this Section.
2)
An EGU that is complying with the emission control requirements of this
Subpart
B by operating under pursuant to this Section may not be included
in a compliance demonstration involving other EGUs during the period
that is operating
under pursuant to this Section.
3)
The owner or operator of an EGU that is complying with this Subpart
B by
means of
the temporary alternative emission standards of this Section is
not excused from
any of the applicable monitoring, recordkeeping, and
reporting requirements
set forth in Sections 225.240 through 225.290 of
this Subpart
b)
Eligibility
.
To be eligible to operate an EGU
under pursuant to this Section, the following
criteria
must shall be met for the EGU:
1)
The EGU is equipped and operated with the air pollution control
equipment or systems that include injection of halogenated activated
carbon and either a cold-side electrostatic precipitator or a fabric filter.
2)
The owner or operator of the EGU is injecting halogenated activated
carbon in an optimum manner for control of mercury emissions, which
must shall include injection of Alstrom, Norit, Sorbent Technologies, or
other halogenated activated carbon that the owner or operator of the EGU
shows 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,
with using an
injection system designed for effective absorption of mercury, considering
the configuration of the EGU and its ductwork. For
this the purpose
purposes of this subsection (b)(2)
, the flue gas flow rate must shall 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.
116
A)
For an EGU firing subbituminous coal, 5.0
lbs pounds per million
actual cubic feet.
B)
For an EGU firing bituminous coal, 10.0
lbs pounds per million
actual cubic feet.
C)
For an EGU firing a blend of subbituminous and bituminous coal,
a rate that is the weighted average of the above rates, based on the
blend of coal being fired.
D)
A rate or rates set on a unit-specific basis that are lower than the
rate specified above to the extent that the owner or operator of the
EGU demonstrates that such rate or rates are needed so that carbon
injection would not increase particulate matter emissions or
opacity so as to threaten compliance with applicable regulatory
requirements for particulate matter or opacity.
3)
The total capacity of the EGUs that operate
under pursuant to this Section
does not exceed the applicable
value below of the following values:
A)
For the owner or operator of more than one existing source with
EGUs, 25 percent of the total rated capacity, in MW, of all the
EGUs at
such the existing sources that it owns or operates, other
than any EGUs operating pursuant to Section 225.235 of this
Subpart
B.
B)
For the owner or operator of only a single existing source with
EGUs (i.e., City, Water, Light & Power, City of Springfield, ID
167120AAO;
Electric Energy, Inc., ID 127855AAC; Kincaid
Generating Station, ID 021814AAB; and Southern Illinois Power
Cooperative/Marion Generating Station, ID 199856AAC), 25
percent of the total rated capacity, in MW, of the all the EGUs at
such the existing sources, other than any EGUs operating pursuant
to Section 225.235
of this Subpart.
c)
Compliance Requirements
.
1)
Emission Control Requirements
.
The owner or operator of an EGU that is operating pursuant to this Section
must shall continue to maintain and operate the EGU to comply with the
criteria for eligibility for operation
under pursuant to this Section, except
during an evaluation of the current sorbent, alternative sorbents or other
techniques to control mercury emissions, as provided by subsection (e) of
this Section.
117
2)
Monitoring and Recordkeeping Requirements
.
In addition to complying with all applicable reporting requirements in
Sections 225.240 through 225.290
of this Subpart, the owner or operator
of an EGU operating pursuant to this Section
must shall also:
A)
Through December 31, 2012,
it must maintain records of the usage
of activated carbon, the exhaust gas flow rate from the EGU, and
the activated carbon feed rate, in pounds per million actual cubic
feet of exhaust gas at the injection point, on a weekly average.
B)
Beginning January 1, 2013,
it must monitor activated carbon feed
rate to the EGU, flue gas temperature at the point of sorbent
injection, and exhaust gas flow rate from the EGU, automatically
recording this data and the activated carbon feed rate, in pounds
per million actual cubic feet of exhaust gas at the injection point,
on an hourly average.
C)
If a blend of bituminous and subbituminous coal is fired in the
EGU,
it must maintain records of the amount of each type of coal
burned and the required injection rate for injection of halogenated
activated carbon, on a weekly basis.
3)
Notification and Reporting Requirements
.
In addition to complying with all applicable reporting requirements in
Sections 225.240 through 225.290
of this Subpart, the owner or operator
of an EGU operating pursuant to this Section
must shall also submit the
following notifications and reports to the Agency:
A)
Written notification prior to the month in which any of the
following events will occur:
i)
the The EGU will no longer be eligible to operate under
this Section due to a change in operation;
ii)
the The type of coal fired in the EGU will change; the
mercury emission standard with which the owner or
operator is attempting to comply for the EGU will change;
or
iii)
operation Operation under this Section will be terminated.
B)
Quarterly reports for the recordkeeping and monitoring conducted
pursuant to subsection (c)(2) of this Section.
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C)
Annual reports detailing activities conducted for the EGU to
further improve control of mercury emissions, including the
measures taken during the past year and activities planned for the
current year.
d)
Applications to Operate under the Technology-Based Standard
1)
Application Deadlines.
A)
The owner or operator of an EGU that is seeking to operate the
EGU
under pursuant to this Section must shall submit an
application to the Agency no later than three months prior to the
date
that on which compliance with Section 225.230 of this
Subpart B
would otherwise have to be demonstrated. For example,
the owner or operator of an EGU that is applying to operate the
EGU pursuant to this Section on June 30, 2010, when compliance
with applicable mercury emission standards must be first
demonstrated, must
shall apply by March 31, 2010 to operate
under this Section.
B)
Unless the Agency finds that the EGU is not eligible to operate
under pursuant to this Section or that the application for operation
under pursuant to this Section does not meet the requirements of
subsection (d)(2) of this Section, the owner or operator of the EGU
is authorized to operate the EGU
under pursuant to this Section
beginning 60 days after receipt of the application by the Agency.
C)
The owner or operator of an EGU operating pursuant to this
Section must reapply to operate pursuant to this Section:
i)
If it operated the EGU
pursuant to this Section 225.234
during the period of June 2010 through December 2012 and
it seeks to operate the EGU
pursuant to this Section
225.234
during the period from January 2013 through June
2015.
ii)
If it is planning a physical change to or a change in the
method of operation of the EGU, control equipment or
practices for injection of activated carbon that is expected
to reduce the level of control of mercury emissions.
2)
Contents of Application. An application to operate an EGU pursuant to
this Section 225.234
must shall be submitted as an application for a new
or revised federally enforceable operating permit for the EGU,
and it must
include the following documents and information:
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A)
A formal request to operate pursuant to this Section showing that
the EGU is eligible to operate pursuant to this Section and
describing the reason for the request, the measures that have been
taken for control of mercury emissions, and factors preventing
more effective control of mercury emissions from the EGU.
B)
The applicable mercury emission standard in Section 225.230(a)
with which the owner or operator of the EGU is attempting to
comply and a summary of relevant mercury emission data for the
EGU.
C)
If a unit-specific rate or rates for carbon injection are proposed
pursuant to subsection (b)(2) of this Section, detailed information
to support the proposed injection rates.
D)
An action plan describing the measures that will be taken while
operating under this Section to improve control of mercury
emissions. This plan must
shall address measures such as
evaluation of alternative forms or sources of activated carbon,
changes to the injection system, changes to operation of the unit
that affect the effectiveness of mercury absorption and collection,
changes to the particulate matter control device to improve
performance,
and changes to other emission control devices. For
each measure contained in the plan, the plan must
shall provide a
detailed description of the specific actions that are planned, the
reason that the measure is being pursued and the range of
improvement in control of mercury that is expected, and the factors
that affect the timing for carrying out the measure, together
with
the current schedule for the measure.
e)
Evaluation of Alternative Control Techniques for Mercury Emissions
1)
During an evaluation of the effectiveness of the current sorbent,
alternative sorbent, or other technique to control mercury emissions, the
owner or operator of an EGU operating
under pursuant to this Section
need not comply with the eligibility criteria for operation
under pursuant
to
this Section as needed to carry out an evaluation of the practicality and
effectiveness of such technique,
as further provided as follows subject to
the following limitations:
A)
The owner or operator of the EGU must
shall conduct the
evaluation in accordance with a formal evaluation program that it
has submitted to the Agency Illinois EPA at least 30 days in
advance prior to beginning the evaluation.
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B)
The duration and scope of the formal
evaluation program must
shall not exceed the duration and scope reasonably needed to
complete the desired evaluation of the alternative control
technique, as initially addressed by the owner or owner in a
support document that it has
submitted with the formal evaluation
program pursuant to subsection (e)(1)(A) of this Section
.
C)
Notwithstanding 35 Ill. Adm. Code 201.146(hhh), the owner or
operator of the EGU must
shall obtain a construction permit for
any new or modified air pollution control equipment to be
constructed as part of the evaluation of the alternative control
technique.
D)
The owner or operator of the EGU must
shall submit a report to the
Agency
Illinois EPA, no later than 90 days after the conclusion of
the formal
evaluation program, describing the evaluation that was
conducted, and providing the results of the formal
evaluation
program
.
2)
If the evaluation of the alternative control technique shows less effective
control of mercury emissions from the EGU than achieved with the prior
control technique, the owner or operator of the EGU must
shall resume
use of the prior control technique. If the evaluation of the alternative
control technique shows comparable control
effectiveness, the owner or
operator of the EGU may either continue to use the alternative control
technique in an optimum manner or resume use of the prior control
technique. If the evaluation of the alternative control technique shows
more effective control of mercury emissions, the owner or operator of the
EGU must
shall continue to use the alternative control technique in an
optimum manner, if it continues to operate
under pursuant to this Section.
Section 225.235
Units Scheduled for Permanent Shut Down
a)
The emission standards of Section 225.230(a)
of this Subpart are not applicable to
an EGU that will be permanently shut down as
follows described in this Section.:
1)
The owner or operator of an EGU
for which that relies on this Section is
being relied upon must shall by no later than complete the following
actions before June 30, 2009:
A)
Have notified the Agency
Illinois EPA that it is planning to
permanently shut down the EGU by the applicable date specified
in subsection (a)(3) or (4) of this Section. This notification must
shall be accompanied by include a description of the actions that
have already been taken to allow the shut down of the EGU and a
121
description of the future actions that must be accomplished to
complete the shut down of the EGU, with the anticipated schedule
for those actions and the anticipated date of permanent shut down
of the unit.
B)
Have applied for a construction permit or be actively pursuing a
federally enforceable agreement that requires the EGU to be
permanently shut down in accordance with this Section.
C)
Have applied for revisions to the operating
permit(s) permits for
the EGU to include provisions that terminate the authorization to
operate the unit in accordance with this Section.
2)
The owner or operator of an EGU
for which that relies on this Section is
being relied upon must, shall by no later than before June 30, 2010,
complete the following actions:
A)
Have obtained a construction permit or entered into a federally
enforceable agreement as
addressed by described in subsection
(a)(1)(B) of this Section; or
B)
Have obtained revised operating
permit(s) permits in accordance
with subsection (a)(1)(C) of this Section.
3)
The plan for permanent shut down of the EGU must provide for the EGU
to be permanently shut down by no later than the applicable date specified
below:
A)
If the owner or operator of the EGU is not constructing a new EGU
or other generating
units unit to specifically replace the existing
EGU, by December 31, 2010.
B)
If the owner or operator of the EGU is constructing a new EGU or
other generating
units unit to specifically replace the existing EGU,
by December 31, 2011.
4)
The owner or operator of the EGU must permanently shut down the EGU
by the date specified in subsection (a)(3) of this Section, unless the owner
or operator submits a demonstration to the Agency
Illinois EPA before
such the specified date showing that circumstances beyond its reasonable
control (such as protracted delays in construction activity, unanticipated
outage of another EGU, or protracted shakedown of a replacement unit)
have occurred that interfere with the plan for permanent shut down of the
EGU, in which case the Agency may accept the demonstration as
substantiated and extend the date for shut down of the EGU may be
extended as follows:
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A)
If the owner or operator of the EGU is not constructing a new EGU
or other generating
units unit to specifically replace the existing
EGU, for up to one year, i.e., permanent shut down of the EGU to
occur by no later than December 31, 2011
.; or
B)
If the owner or operator of the EGU is constructing a new EGU or
other generating
units unit to specifically replace the existing EGU,
for up to 18 months, i.e., permanent shutdown of the EGU to occur
by no later than June 30, 2013; provided, however, that after
December 31, 2012, the existing EGU must
shall only operate as a
back-up unit to address periods when the new generating units are
not in service.
b)
Notwithstanding Sections 225.230 and 225.232
of this Subpart, any EGU that is
not required to comply with Section 225.230
of this Subpart pursuant to this
Section must
shall not be included when determining whether any other EGUs at
the source or other sources are in compliance with Section 225.230
of this
Subpart.
c)
If an EGU, for which the owner or operator of the source has relied upon this
Section in lieu of complying with Section 225.230(a)
of this Subpart is not
permanently shut down as required by this Section, the EGU must
shall be
considered to be a new EGU subject to the emission standards in Section
225.237(a)
of this Subpart beginning in the month after the EGU was required to
be permanently shut down, in addition to any other penalties that may be imposed
for failure to permanently shut down the EGU in accordance with this Section.
Section 225.237
Emission Standards for New Sources with EGUs
a)
Standards.
1)
The owner or operator of a source with one or more EGUs, but that
previously had not had any EGUs that commenced commercial operation
before January 1, 2009, must
shall comply with one of the following
emission standards for each EGU on a rolling 12-month basis:
A)
An emission standard of 0.0080 lb mercury/GWh gross electrical
output; or
B)
A minimum 90 percent reduction of input mercury.
2)
For this purpose, compliance may be demonstrated using the equations in
Section 225.230(a)(2), (a)(3), or (b)(2)
of this Subpart.
123
b)
The initial 12-month rolling period for which compliance with the emission
standards of subsection (a)(1) of this Section must be demonstrated for a new
EGU
shall will commence on the date that the initial performance test for the
mercury emission standard under 40 CFR 60.45a also commences. The CEMSs
continuous emission monitoring system required by this Subpart B for mercury
emissions from the EGU must be certified prior to this date. Thereafter,
compliance must
shall be demonstrated on a rolling 12-month basis in terms of
based on calendar months.
Section 225.238 Temporary Technology-Based Standard for New Sources with EGUs
a)
General.
1)
At a source with EGUs that previously had not had any EGUs that
commenced commercial operation before January 1, 2009, for an EGU
that meets the eligibility criteria in subsection (b) of this Section, as an
alternative to compliance with the mercury emission standards in Section
225.237of
this Subpart, the owner or operator of the EGU may
temporarily comply with the requirements of this Section, through
December 31, 2018, as further provided in subsections (c), (d), and (e) of
this Section.
2)
An EGU that is complying with the emission control requirements of this
Subpart B
by operating under pursuant to this Section may not be included
in a compliance demonstration involving other EGUs at the source during
the period that
such the temporary technology-based standard is in effect.
3)
The owner or operator of an EGU that is complying with this Subpart B
by
means of pursuant to this Section is not excused from applicable
monitoring, recordkeeping, and reporting requirements
in of Sections
225.240 through 225.290
of this Subpart.
b)
Eligibility.
To be eligible to operate an EGU under pursuant to this Section, the
following criteria must
shall be met for the EGU:
1)
The EGU is subject to Best Available Control Technology (BACT) for
emissions of sulfur dioxide, nitrogen oxides,
and particulate matter, and the
EGU is equipped and operated with the air pollution control equipment or
systems specified below, as applicable to the category of EGU:
A)
For coal-fired boilers, injection of sorbent or other mercury control
technique (e.g. reagent) approved by the Agency halogenated
activated carbon.
124
B)
For an EGU firing fuel gas produced by coal gasification,
processing of the raw fuel gas prior to combustion for removal of
mercury with a system using a sorbent or other mercury control
technique approved by the Agency activated carbon.
2)
For an EGU for which injection of a sorbent or other mercury control
technique halogenated activated carbon is required by pursuant to
subsection (b)(1) of this Section, the owner or operator of the EGU is
injecting sorbent or other mercury control technique
halogenated activated
carbon in an optimum manner for control of mercury emissions, which
must
shall include injection of Alstrom, Norit, Sorbent Technologies, or
other sorbent or other mercury control technique
halogenated activated
carbon that the owner or operator of the EGU shows demonstrates to have
similar or better effectiveness for control of mercury emissions, at least at
the
following rates 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
halogenated
activated carbon are established in a federally enforceable operating
permit issued for the EGU, with an injection system designed for effective
absorption of mercury. For
this purpose the purposes of this subsection
(b)(2), the flue gas flow rate must shall 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.
A)
For an EGU firing subbituminous coal, 5.0 pounds per million
actual cubic feet.
B)
For an EGU firing bituminous coal, 10.0 pounds per million actual
cubic feet.
C)
For an EGU firing a blend of subbituminous and bituminous coal,
a rate that is the weighted average of the above rates, based on the
blend of coal being fired.
D)
A rate or rates set on a unit-specific basis that are lower than the
rate specified in subsections (b)(2)(A), (B), and (C) of this Section,
above to the extent that the owner or operator of the EGU
demonstrates that such rate or rates are needed so that sorbent
injection or other mercury control technique would not increase
particulate matter emissions or opacity so as to threaten
compliance with applicable regulatory requirements for particulate
matter or opacity or cause a safety issue.
125
c)
Compliance Requirements .
1)
Emission Control Requirements.
The owner or operator of an EGU that is
operating pursuant to this Section must
shall continue to maintain and
operate the EGU to comply with the criteria for eligibility for operation
under this Section, except during an evaluation of the current sorbent,
alternative sorbents,
or other techniques to control mercury emissions, as
provided by subsection (e) of this Section.
2)
Monitoring and Recordkeeping Requirements.
In addition to complying
with all applicable reporting requirements in Sections 225.240 through
225.290
of this Subpart,, the owner or operator of a new EGU operating
pursuant to this Section must
shall also:
A)
Monitor sorbent
activated carbon feed rate to the EGU, flue gas
temperature at the point of sorbent injection or other mercury
control technique, and exhaust gas flow rate from the EGU,
automatically recording this data and the sorbent
activated carbon
feed rate, in pounds per million actual cubic feet of exhaust gas at
the injection point, on an hourly average.
B)
If a blend of bituminous and subbituminous coal is fired in the
EGU, maintain
records of the amount of each type of coal burned
and the required injection rate for injection of sorbent
halogenated
activated carbon, on a weekly basis.
C)
If a mercury control technique other than sorbent injection is
approved by the Agency, monitor appropriate parameter for that
control technique as specified by the Agency
3)
Notification and Reporting Requirements.
In addition to complying with
all applicable reporting requirements
in of Sections 225.240 through
225.290
of this Subpart, the owner or operator of an EGU operating
pursuant to this Section must
shall also submit the following notifications
and reports to the Agency:
A)
Written notification prior to the month in which any of the
following events will occur: the EGU will no longer be eligible to
operate under this Section due to a change in operation; the type of
coal fired in the EGU will change; the mercury emission standard
with which the owner or operator is attempting to comply for the
EGU will change; or operation under this Section will be
terminated.
B)
Quarterly reports for the recordkeeping and monitoring conducted
pursuant to subsection (c)(2) of this Section.
126
C)
Annual reports detailing activities conducted for the EGU to
further improve control of mercury emissions, including the
measures taken during the past year and activities planned for the
current year.
d)
Applications to Operate under the Technology-Based Standard.
1)
Application Deadlines.
A)
The owner or operator of an EGU that is seeking to operate the
EGU
under pursuant to this Section must shall submit an
application to the Agency no later than three months prior to the
date that compliance with Section 225.237
of this Subpart would
otherwise have to be demonstrated.
B)
Unless the Agency finds that the EGU is not eligible to operate
under pursuant to this Section or that the application for operation
under this Section does not meet the requirements of subsection
(d)(2) of this Section, the owner or operator of the EGU is
authorized to operate the EGU
under pursuant to this Section
beginning 60 days after receipt of the application by the Agency.
C)
The owner or operator of an EGU operating pursuant to this
Section must reapply to operate pursuant to this Section if it is
planning a physical change to or a change in the method of
operation of the EGU, control equipment,
or practices for injection
of sorbent or other mercury control technique
activated carbon that
is expected to reduce the level of control of mercury emissions.
2)
Contents of Application. An application to operate pursuant to this
Section must
shall be submitted as an application for a new or revised
federally enforceable operating permit for the new EGU,
and it must
include the following information:
A)
A formal request to operate pursuant to this Section showing that
the EGU is eligible to operate pursuant to this Section and
describing the reason for the request, the measures that have been
taken for control of mercury emissions, and factors preventing
more effective control of mercury emissions from the EGU.
B)
The applicable mercury emission standard in Section 225.237 with
which the owner or operator of the EGU is attempting to comply
and a summary of relevant mercury emission data for the EGU.
127
C)
If a unit-specific rate or rates for sorbent or other mercury control
technique carbon injection are proposed pursuant to subsection
(b)(2) of this Section, detailed information to support the proposed
injection rates.
D)
An action plan describing the measures that will be taken while
operating
under pursuant to this Section to improve control of
mercury emissions. This plan must
shall address measures such as
evaluation of alternative forms or sources of sorbent or other
mercury control technique activated carbon, changes to the
injection system, changes to operation of the unit that affect the
effectiveness of mercury absorption and collection, and changes to
other emission control devices. For each measure contained in the
plan, the plan must
shall provide a detailed description of the
specific actions that are planned, the reason that the measure is
being pursued and the range of improvement in control of mercury
that is expected, and the factors that affect the timing for carrying
out the measure, with the current schedule for the measure.
e)
Evaluation of Alternative Control Techniques for Mercury Emissions
1)
During an evaluation of the effectiveness of the current sorbent,
alternative sorbent, or other technique to control mercury emissions, the
owner or operator of an EGU operating
under pursuant to this Section
does not
need not to comply with the eligibility criteria for operation under
pursuant to this Section as needed to carry out an evaluation of the
practicality and effectiveness of such technique,
as further provided as
follows subject to the following limitations:
A)
The owner or operator of the EGU must
shall conduct the
evaluation in accordance with a formal evaluation program that it
has submitted to the Agency Illinois EPA (JCAR) at least 30 days
in advance prior to beginning the evaluation.
B)
The duration and scope of the formal
evaluation program must
shall not exceed the duration and scope reasonably needed to
complete the desired evaluation of the alternative control
technique, as initially addressed by the owner or operator in a
support document that it has
submitted with the formal evaluation
program pursuant to subsection (e)(1)(A) of this Section
.
C)
Notwithstanding 35 Ill. Adm. Code 201.146(hhh), the owner or
operator of the EGU must
shall obtain a construction permit for
any new or modified air pollution control equipment to be
constructed as part of the evaluation of the alternative control
technique.
128
D)
The owner or operator of the EGU must
shall submit a report to the
Agency
Illinois EPA no later than 90 days after the conclusion of
the formal
evaluation program describing the evaluation that was
conducted and providing the results of the formal
evaluation
program
.
2)
If the evaluation of the alternative control technique shows less effective
control of mercury emissions from the EGU than was
achieved with the
prior control technique, the owner or operator of the EGU must
shall
resume use of the prior control technique. If the evaluation of the
alternative control technique shows comparable effectiveness, the owner
or operator of the EGU may either continue to use the alternative control
technique in an optimum manner or resume use of the prior control
technique. If the evaluation of the alternative control technique shows
more effective control of mercury emissions, the owner or operator of the
EGU must
shall continue to use the alternative control technique in an
optimum manner, if it continues to operate
under pursuant to this Section.
Section 225.240
General Monitoring and Reporting Requirements
The owner or operator of an EGU must
shall comply with the monitoring, recordkeeping, and
reporting requirements as provided in this Section, Sections 225.250 through 225.290 of this
Subpart B
, and Subpart I of 40 CFR Part 75 (sections 75.80 through 75.84), incorporated by
reference in Section 225.140. If the EGU utilizes a common stack with units that are not EGUs
and the owner or operator of the EGU does not conduct emissions monitoring in the duct to the
common stack from each EGU, the owner or operator of the EGU must
shall conduct emissions
monitoring in accordance with 40 CFR 75.82(b)(2) and this Section, including monitoring in the
duct to the common stack from each unit that is not an EGU, unless the owner or operator of the
EGU counts the combined emissions measured at the common stack as the mass emissions of
mercury for the EGUs for recordkeeping and compliance purposes.
a)
Requirements for installation, certification, and data accounting. The owner or
operator of each EGU must
shall:
1)
Install all monitoring systems required
under pursuant to this Section and
Sections 225.250 through 225.290
of this Subpart for monitoring mercury
mass emissions (including all systems required to monitor mercury
concentration, stack gas moisture content, stack gas flow rate, and CO
2
or
O
2
concentration, as applicable, in accordance with 40 CFR 75.81 and
75.82).
2)
Successfully complete all certification tests required
under pursuant to
Section 225.250 and meet all other requirements of this Section, Sections
225.250 through 225.290
of this Subpart, and Subpart I of 40 CFR Part 75
129
applicable to the monitoring systems required under subsection (a)(1) of
this Section.
3)
Record, report, and
quality-assure assure the quality of the data from the
monitoring systems required under subsection (a)(1) of this Section.
4)
If the owner or operator elects to use the low mass emissions excepted
monitoring methodology for an EGU that emits no more than 464 ounces
(29 pounds) of mercury per year pursuant to 40 CFR 75.81(b),
also it must
perform emissions testing in accordance with 40 CFR 75.81(c) to
demonstrate that the EGU is eligible to use this excepted emissions
monitoring methodology, as well as comply with all other applicable
requirements of 40 CFR 75.81(b) through (f). Also, the owner or operator
must submit a copy of any information required to be submitted to the
USEPA
under pursuant to these provisions to the Agency Illinois EPA.
The initial emissions testing to demonstrate eligibility of an EGU for the
low mass emissions excepted methodology must
shall be conducted by the
applicable of the
following dates:
A)
If the EGU has commenced commercial operation before July 1,
2008, at least by January 1, 2009, or 45 days prior to relying on the
low mass emissions excepted methodology, whichever date is
later.
B)
If the EGU has commenced commercial operation on or after July
1, 2008, at least 45 days prior to the applicable date specified
under
pursuant to subsection (b)(2) of this Section or 45 days prior to
relying on the low mass emissions excepted methodology,
whichever date is later.
b)
Emissions Monitoring Deadlines. The owner or operator must
shall 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 shall 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 January 1, 2009.
2)
For the owner or operator of an EGU that commences commercial
operation on or after July 1, 2008, by 90 unit operating days or 180
calendar days, whichever occurs first, after the date on which the EGU
commences commercial operation.
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3)
For the owner or operator of an EGU for which construction of a new
stack or flue or installation of add-on mercury emission controls, a flue
gas desulfurization system, a selective catalytic reduction system, a fabric
filter, or a compact hybrid particulate collector system is completed after
the applicable deadline
under pursuant to subsection (b)(1) or (b)(2) of
this Section, by 90 unit operating days or 180 calendar days, whichever
occurs first, after the date on which emissions first exit to the atmosphere
through the new stack or flue, add-on mercury emissions controls, flue gas
desulfurization system, selective catalytic reduction system, fabric filter,
or compact hybrid particulate collector system.
c)
Reporting Data.
1)
Except as provided in subsection (c)(2) of this Section, the owner or
operator of an EGU that does not meet the applicable emissions
monitoring date set forth in subsection (b) of this Section for any
emissions monitoring system required
under pursuant to subsection (a)(1)
of this Section must
shall, for each such monitoring system, determine,
record, and report the
maximum potential (or, as appropriate, the
minimum potential) values for mercury concentration, the stack gas flow
rate, the
stack gas moisture content, and any other parameters required to
determine mercury mass emissions in accordance with 40 CFR 75.80(g).
2)
The owner or operator of an EGU that does not meet the applicable
emissions monitoring date set forth in subsection (b)(3) of this Section for
any emissions monitoring system required
under pursuant to subsection
(a)(1) of this Section must
shall, for each such monitoring system,
determine, record, and report substitute data using the applicable missing
data procedures as set forth
in 40 CFR 75.80(f), in lieu of the maximum
potential (or, as appropriate, minimum potential) values for a parameter, if
the owner or operator demonstrates that there is continuity between the
data streams for that parameter before and after the construction or
installation
under pursuant to subsection (b)(3) of this Section.
d)
Prohibitions.
1)
No owner or operator of an EGU
must shall may use any alternative
emissions monitoring system, alternative reference method for measuring
emissions, or
any other alternative to the emissions monitoring and
measurement requirements of this Section and Sections 225.250 through
225.290
of this Subpart, unless such alternative is promulgated by the
USEPA and approved in writing by the Agency,
or the use of such
alternative is approved in writing by the Agency and USEPA.
2)
No owner or operator of an EGU
must shall may operate the its EGU so as
to discharge, or allow to be discharged, mercury emissions to the
131
atmosphere without accounting for all such emissions in accordance with
the applicable provisions of this Section, Sections 225.250 through
225.290
of this Subpart, and Subpart I of 40 CFR 75.
3)
No owner or operator of an EGU
must shall may disrupt the CEMS
continuous emission monitoring system, any portion thereof, or any other
approved emission monitoring method, and thereby avoid monitoring and
recording mercury mass emissions discharged into the atmosphere, except
for periods of recertification or periods when calibration, quality assurance
testing, or maintenance is performed in accordance with the applicable
provisions of this Section, Sections 225.250 through 225.290
of this
Subpart, and Subpart I of 40 CFR 75.
4)
No owner or operator of an EGU
must shall may retire or permanently
discontinue use of the CEMS
continuous emission monitoring system or
any component thereof, or any other approved monitoring system
under
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 Subpart I of 40
CFR 75, by the Agency for use at that EGU and that provides
emission data for the same pollutant or parameter as the retired or
discontinued monitoring system; or
B)
The owner or operator or designated representative submits
notification of the date of certification testing of a replacement
monitoring system for the retired or discontinued monitoring
system in accordance with Section 225.250(a)(3)(A)
of this
Subpart.
e)
Long-term Cold Storage
The owner or operator of an EGU that is in long-term cold storage is subject to
the
applicable provisions of 40 CFR 75 for 75.4 and 75.64 relating to monitoring,
recordkeeping, and reporting for units in long-term cold storage.
Section 225.250
Initial Certification and Recertification Procedures for Emissions
Monitoring
a)
The owner or operator of an EGU must
shall comply with the following initial
certification and recertification procedures for a CEMS
continuous emissions
monitoring system (i.e., a CEMS continuous emission monitoring system or an
132
excepted monitoring system (sorbent trap monitoring system)
under pursuant to
40 CFR 75.15, incorporated by reference in Section 225.140 required by Section
225.240(a)(1). The owner or operator of an EGU that qualifies for, and for which
the owner or operator elects to use, the
low mass emissions low-mass-emissions
excepted methodology under pursuant to 40 CFR 75.81(b), incorporated by
reference in Section 225.140 must shall comply with the procedures set forth in
subsection (c) of this Section.
1)
Requirements for Initial Certification. The owner or operator of an EGU
must
shall ensure that, for each CEMS continuous emission monitoring
system required by Section 225.240(a)(1) of this Subpart (including the
automated data acquisition and handling system), the owner or operator
successfully completes all of the initial certification testing required
under
pursuant to 40 CFR 75.80(d), incorporated by reference in Section
225.140 by the applicable deadline in Section 225.240(b) of this Subpart.
In addition, whenever the owner or operator of an EGU installs a
monitoring system to meet the requirements of this Subpart B
in a location
where no such monitoring system was previously installed, the owner or
operator must successfully complete the initial certification requirements
of 40 CFR 75.80(d).
2)
Requirements for Recertification. Whenever the owner or operator of an
EGU makes a replacement, modification, or change in any certified CEMS
continuous emission monitoring system, or an excepted monitoring system
(sorbent trap monitoring system)
under pursuant to 40 CFR 75.15, and
required by Section 225.240(a)(1)
of this Subpart, that may significantly
affect the ability of the system to accurately measure or record mercury
mass emissions or heat input rate or to meet the quality-assurance and
quality-control requirements of 40 CFR 75.21 or Appendix B to 40 CFR
75, each incorporated by reference in Section 225.140
, the owner or
operator of an EGU must
shall recertify the monitoring system in
accordance with 40 CFR 75.20(b), incorporated by reference in Section
225.140. Furthermore, whenever the owner or operator of an EGU makes
a replacement, modification, or change to the flue gas handling system or
the EGU’s operation that may significantly change the stack flow or
concentration profile, the owner or operator must
shall recertify each
CEMS
continuous emission monitoring system, and each excepted
monitoring system (sorbent trap monitoring system)
under pursuant to 40
CFR 75.15, whose accuracy is potentially affected by the change, all in
accordance with 40 CFR 75.20(b). Examples of changes to a CEMS
continuous emission monitoring system that require recertification
include, but are not limited to,
replacement of the analyzer, complete
replacement of an existing CEMS
continuous emission monitoring system,
or change in location or orientation of the sampling probe or site.
133
3)
Approval Process for Initial Certification and Recertification. Subsections
(a)(3)(A) through (a)(3)(D)
of this Section apply to both initial
certification and recertification of a CEMS
continuous emission
monitoring system required by Section 225.240(a)(1) of this Subpart. For
recertifications,
replace the words “certification” and “initial certification”
with are to be read as the word “recertification”, replace the word
“certified”
with is to be read as the word “recertified”, and follow the
procedures set forth
in 40 CFR 75.20(b)(5) are to be followed in lieu of
the procedures set forth
in subsection (a)(3)(E) of this Section.
A)
Notification of Certification. The owner or operator must
shall
submit to the Agency, USEPA Region 5, and the Administrator of
the USEPA written notice of the dates of certification testing, in
accordance with Section 225.270
of this Subpart.
B)
Certification Application. The owner or operator must
shall
submit to the Agency a certification application for each
monitoring system. A complete certification application must
shall
include the information specified in 40 CFR 75.63, incorporated by
reference in Section 225.140.
C)
Provisional Certification Date. The provisional certification date
for a monitoring system must
shall be determined in accordance
with 40 CFR 75.20(a)(3), incorporated by reference in Section
225.140. A provisionally certified monitoring system may be used
under pursuant to this Subpart B for a period not to exceed 120
days after receipt by the Agency of the complete certification
application for the monitoring system
under pursuant to subsection
(a)(3)(B) of this Section. Data measured and recorded by the
provisionally certified monitoring system, in accordance with the
requirements of 40 CFR 75, will be considered valid quality-
assured data (retroactive to the date and time of provisional
certification), provided that the Agency does not invalidate the
provisional certification by issuing a notice of disapproval within
120 days after the date of receipt by the Agency of the complete
certification application.
D)
Certification Application Approval Process. The Agency
will
must issue a written notice of approval or disapproval of the
certification application to the owner or operator within 120 days
after receipt of the complete certification application required by
subsection (a)(3)(B) of this Section. In the event the Agency does
not issue
such a written notice of approval or disapproval within
the 120-day period, each monitoring system that meets the
applicable performance requirements of 40 CFR 75 and which
is
134
included in the certification application will be deemed certified
for use
under pursuant to this Subpart B.
i)
Approval Notice. If the certification application is
complete and shows that each monitoring system meets the
applicable performance requirements of 40 CFR 75, then
the Agency
will must issue a written notice of approval of
the certification application within 120 days after receipt.
ii)
Incomplete Application Notice. If the certification
application is not complete, then the Agency
will must
issue a written notice of incompleteness that sets a
reasonable date by which the owner or operator must
submit the additional information required to complete the
certification application. If the owner or operator does not
comply with the notice of incompleteness by the specified
date, then the Agency may issue a notice of disapproval
under pursuant to subsection (a)(3)(D)(iii) of this Section.
The 120-day review period
must shall will not begin before
receipt of a complete certification application.
iii)
Disapproval Notice. If the certification application shows
that any monitoring system does not meet the performance
requirements of 40 CFR 75,
or if the certification
application is incomplete and the requirement for
disapproval
under pursuant to subsection (a)(3)(D)(ii) of
this Section is met,
then the Agency will must issue a
written notice of disapproval of the certification
application. Upon issuance of such notice of disapproval,
the provisional certification is invalidated
by the Agency,
and the data measured and recorded by each uncertified
monitoring system
must shall will not be considered valid
quality-assured data beginning with the date and hour of
provisional certification (as defined
under pursuant to 40
CFR 75.20(a)(3)). The owner or operator must
shall follow
the procedures for loss of certification set forth
in
subsection (a)(3)(E) of this Section for each monitoring
system that is disapproved for initial certification.
iv)
Audit Decertification. The Agency may issue a notice of
disapproval of the certification status of a monitor in
accordance with Section 225.260(b)
of this Subpart.
E)
Procedures for Loss of Certification. If the Agency issues a notice
of disapproval of a certification application
under pursuant to
subsection (a)(3)(D)(iii) of this Section or a notice of disapproval
135
of certification status
under pursuant to subsection (a)(3)(D)(iv) of
this Section,
then the owner or operator must fulfill the following
requirements:
i)
The owner or operator must
shall substitute the following
values
, for each disapproved monitoring system, and for
each hour of EGU operation during the period of invalid
data specified
under pursuant to 40 CFR 75.20(a)(4)(iii) or
75.21(e),
and continuing until the applicable date and hour
specified
under pursuant to 40 CFR 75.20(a)(5)(i), each
incorporated by reference in Section 225.140. For a
disapproved mercury pollutant concentration monitor and
disapproved flow monitor, respectively, the maximum
potential concentration of mercury and the maximum
potential flow rate, as defined in Sections 2.1.7.1 and
2.1.4.1 of Appendix A to 40 CFR 75, incorporated by
reference in Section 225.140. For a disapproved moisture
monitoring system and disapproved diluent gas monitoring
system, respectively, the minimum potential moisture
percentage and either the maximum potential CO
2
concentration or the minimum potential O
2
concentration
(as applicable), as defined in Sections 2.1.5, 2.1.3.1, and
2.1.3.2 of Appendix A to 40 CFR 75, incorporated by
reference in Section 225.140. For a disapproved excepted
monitoring system (sorbent trap monitoring system)
under
pursuant to 40 CFR 75.15 and disapproved flow monitor,
respectively, the maximum potential concentration of
mercury and maximum potential flow rate, as defined in
Sections 2.1.7.1 and 2.1.4.1 of Appendix A to 40 CFR
Part
75, incorporated by reference in Section 225.140.
ii)
The owner or operator must
shall submit a notification of
certification retest dates and a new certification application
in accordance with subsections (a)(3)(A) and (B) of this
Section.
iii)
The owner or operator must
shall repeat all certification
tests or other requirements that were failed by the
monitoring system, as indicated in the Agency’s notice of
disapproval, no later than 30 unit operating days after the
date of issuance of the notice of disapproval.
b)
Exemption.
1)
If an emissions monitoring system has been previously certified in
accordance with 40 CFR 75 and the applicable quality assurance and
136
quality control requirements of 40 CFR 75.21 and Appendix B to 40 CFR
75 are fully met, the monitoring system
must shall will be exempt from the
initial certification requirements of this Section.
2)
The recertification provisions of this Section
must shall apply to an
emissions monitoring system required by Section 225.240(a)(1)
of this
Subpart exempt from initial certification requirements under pursuant to
subsection (a)(1) of this Section.
c)
Initial certification and recertification procedures for EGUs using the mercury low
mass emissions excepted methodology
under pursuant to 40 CFR 75.81(b). The
owner or operator
of an that has elected to use the mercury-low-mass-emissions-
excepted methodology for a qualified EGU qualified to use, and who has elected
to use, the mercury low mass emissions excepted methodology under pursuant to
40 CFR 75.81(b) must shall meet the applicable certification and recertification
requirements in 40 CFR 75.81(c) through (f), incorporated by reference in Section
225.140.
d)
Certification Applications. The owner or operator of an EGU must
shall submit
an application to the Agency within 45 days after completing all initial
certification or recertification tests required
under pursuant to this Section,
including the information required
under pursuant to 40 CFR 75.63.
Section 225.260
Out of Control Periods for Emission Monitors
a)
Whenever any emissions monitoring system fails to meet the quality-assurance
and quality-control requirements or data validation requirements of 40 CFR
Part
75, incorporated by reference in Section 225.140, data must shall be substituted
using the applicable missing data procedures in Subparts D and I of 40 CFR 75,
each incorporated by reference in Section 225.140.
b)
Audit Decertification. Whenever both an audit of an emissions monitoring
system and a review of the initial certification or recertification application reveal
that any emissions monitoring system should not have been certified or recertified
because it did not meet a particular performance specification or other
requirement
under pursuant to Section 225.250 of this Subpart or the applicable
provisions of 40 CFR 75, both at the time of the initial certification or
recertification application submission and at the time of the audit, the Agency
will
must issue a notice of disapproval of the certification status of such monitoring
system. For the purposes of this subsection (b)
, an audit must shall be either a
field audit or an audit of any information submitted to the Agency. By issuing the
notice of disapproval, the Agency revokes prospectively the certification status of
the emissions monitoring system. The data measured and recorded by the
monitoring system must
shall not be considered valid quality-assured data from
the date of issuance of the notification of the revoked certification status until the
date and time that the owner or operator completes subsequently approved initial
137
certification or recertification tests for the monitoring system. The owner or
operator must
shall follow the applicable initial certification or recertification
procedures in Section 225.250
of this Subpart for each disapproved monitoring
system.
Section 225.261
Additional Requirements to Provide Heat Input Data
The owner or operator of an EGU that monitors and reports mercury mass emissions using a
mercury concentration monitoring system and a flow monitoring system must
shall also monitor
and report the
heat input rate at the EGU level using the procedures set forth in 40 CFR 75,
incorporated by reference in Section 225.140.
Section 225.263
Monitoring of Gross Electrical Output
The owner or operator of an EGU complying with this Subpart B
by means of Section
225.230(a)(1) or using electrical output
(
O
i
) (O
i
) and complying by means of Section 225.230(b)
or (d) or Section 225.232
of this Subpart must shall monitor gross electrical output of the
associated generator(s) in MWh on an hourly basis.
Section 225.265
Coal Analysis for Input Mercury Levels
a)
The owner or operator of an EGU complying with this Subpart B
by means of
Section 225.230(a)(2) or using input mercury levels
(
I
i
) (I
i
) and complying by
means of Section 225.230(b) or (d) or Section 225.232
of this Subpart must shall
fulfill the following requirements
:
1)
Perform daily sampling of the coal combusted in the EGU for mercury
content. The owner or operator of such EGU must
shall collect a
minimum of one 2-lb grab sample per day of operation from the belt
feeders anywhere between the crusher house or breaker building and the
boiler.
Such The sample must shall be taken in such a manner so as to
provide that provides a representative mercury content for the coal burned
on that day.
2)
Analyze the grab coal sample for the following:
A)
Determine the heat content using ASTM D5865-04 or an
equivalent method approved in writing by the Agency.
B)
Determine the moisture content using ASTM D3173-03 or an
equivalent method approved in writing by the Agency.
C)
Measure the mercury content using ASTM D6414-01, ASTM
D3684-01, or an
equivalent method approved in writing by the
Agency.
138
3)
The owner or operator of multiple EGUs at the same source using the
same crusher house or breaker building may take one sample per crusher
house or breaker building, rather than one per EGU.
4)
The owner or operator of an EGU must
shall use the data analyzed under
pursuant to subsection (b) of this Section to determine the mercury content
in terms of lbs/trillion Btu.
b)
The owner or operator of an EGU that must conduct sampling and analysis of coal
pursuant to subsection (a) of this Section must
shall begin such activity by the
following date:
1)
If the EGU is in daily service, at least 30 days before the start of the month
for which such activity will be required.
2)
If the EGU is not in daily service, on the day that the EGU resumes
operation.
Section 225.270
Notifications
The owner or operator of a source with one or more EGUs must
shall submit written notice to the
Agency according to the provisions in 40 CFR 75.61, incorporated by reference in Section
225.140 (as a segment of 40 CFR 75) for each EGU or group of EGUs monitored at a common
stack and each non-EGU monitored
under pursuant to 40 CFR 75.82(b)(2)(ii), incorporated by
reference in Section 225.140.
Section 225.290
Recordkeeping and Reporting
a)
General Provisions
1)
The owner or operator of an EGU and its designated representative must
shall comply with all applicable recordkeeping and reporting requirements
in this Section and with all applicable recordkeeping and reporting
requirements of 40 CFR 75.84, incorporated by reference in Section
225.140.
2)
The owner or operator of an EGU must
shall maintain records for each
month identifying the emission standard in Section 225.230(a) or
225.237(a) of this Section with which it is complying or that is applicable
for the EGU and the following records related to the emissions of mercury
that the EGU is allowed to emit:
A)
For an EGU for which the owner or operator is complying with
this Subpart B
by means of Section 225.230(a)(2) or
225.237(a)(1)(B) or using input mercury levels to determine the
allowable emissions of the EGU, records of the daily mercury
139
content of coal used (lbs/trillion Btu) and the daily and monthly
input mercury (lbs), which must
shall be kept in the file required
under pursuant to 40 CFR 75.84(a).
B)
For an EGU for which the owner or operator of an EGU complying
with this Subpart B
by means of Section 225.230(a)(1) or
225.237(a)(1)(A) or using electrical output to determine the
allowable emissions of the EGU, records of the daily and monthly
gross electrical output (GWh), which must
shall be kept in the file
required under 40 CFR 75.84(a).
3)
The owner or operator of an EGU must
shall maintain records of the
following data
for each EGU:
A)
Monthly emissions of mercury from the EGU.
B)
For an EGU for which the owner or operator is complying by
means of Section 225.230(b) or (d) of this Subpart B
, records of
the monthly allowable emissions of mercury from the EGU.
4)
The owner or operator of an EGU that is participating in an Averaging
Demonstration pursuant to Section 225.232 of this Subpart B
must shall
maintain records identifying all sources and EGUs covered by the
Demonstration for each month and, within 60 days after the end of each
calendar month, calculate and record the actual and allowable mercury
emissions of the EGU for the month and the applicable 12-month rolling
period.
5)
The owner or operator of an EGU must
shall maintain the following
records related to quality assurance activities conducted for emissions
monitoring systems:
A)
The results of quarterly assessments conducted
under pursuant to
Section 2.2 of Appendix B of 40 CFR 75, incorporated by
reference in Section 225.140; and
B)
Daily/weekly system integrity checks
under pursuant to Section
2.6 of Appendix B of 40 CFR 75, incorporated by reference in
Section 225.140.
6)
The owner or operator of an EGU must
shall maintain an electronic copy
of all electronic submittals to the USEPA
under pursuant to 40 CFR
75.84(f), incorporated by reference in Section 225.140
.
7)
The owner or operator of an EGU must
shall retain all records required by
this Section at the source unless otherwise provided in the CAAPP permit
140
issued for the source and must
shall make a copy of any record available
to the Agency upon request.
b)
Quarterly Reports. The owner or operator of a source with one or more EGUs
must
shall submit quarterly reports to the Agency as follows:
1)
These reports must
shall include the following information for operation
of the EGUs during the quarter:
A)
The total operating hours of each EGU and the mercury CEMS, as
also reported in accordance with 40 CFR 75
., incorporated by
reference in Section 225.140.
B)
A discussion of any significant changes in the measures used to
control emissions of mercury from the EGUs or the coal supply to
the EGUs, including changes in the source of coal.
C)
Summary information on the performance of the mercury CEMS.
When the mercury CEMS was not inoperative, repaired, or
adjusted, except for routine zero and span checks, this must
shall
be stated in the report.
D)
If the CEMS downtime was more than 5.0 percent of the total
operating time for the EGU: the date and time identifying each
period during which the CEMS was inoperative, except for routine
zero and span checks; the nature of CEMS repairs or adjustments
and a summary of quality assurance data consistent with 40 CFR
Part 75, i.e., the dates and results of the Linearity Test(s) and any
RATAs
Relative Accuracy Test Audit(s) during the quarter; a
listing of any days when a required daily calibration was not
performed; and the date and duration of any periods when the
CEMS was out-of-control as addressed by Section 225.260
of this
Subpart.
2)
The owner or operator must
shall submit each quarterly report to the
Agency within 45 days following the end of the calendar quarter covered
by the report.
c)
Compliance Certification. The owner or operator of a source with one or more
EGUs must
shall submit to the Agency a compliance certification in support of
each quarterly report based on reasonable inquiry of those persons with primary
responsibility for ensuring that all of the EGUs' emissions are correctly and fully
monitored. The certification must
shall state:
1)
That the monitoring data submitted were recorded in accordance with the
applicable requirements of this Section, Sections 225.240 through 225.270
141
and Section 225.290 of this Subpart B
, and 40 CFR 75, including the
quality assurance procedures and specifications; and
2)
For an EGU with add-on mercury emission controls, a flue gas
desulfurization system, a selective catalytic reduction system, or a
compact hybrid particulate collector system and for all hours where
mercury data are substituted in accordance with 40 CFR 75.34(a)(1):
(A)
That:
(i)
The mercury add-on emission controls, flue gas
desulfurization system, selective catalytic reduction system,
or compact hybrid particulate collector system was
operating within the range of parameters listed in the
quality assurance/quality control program
under pursuant to
Appendix B to 40 CFR 75; or
ii)
With regard to a flue gas desulfurization system or a
selective catalytic reduction system, quality-assured SO
2
emission data recorded in accordance with 40 CFR
Part 75
document that the flue gas desulfurization system was
operating properly, or quality-assured NO
X
emission data
recorded in accordance with 40 CFR
Part 75 document that
the selective catalytic reduction system was operating
properly, as applicable; and
B)
The substitute data values do not systematically underestimate
mercury emissions.
d)
Annual Certification of Compliance
1)
The owner or operator of a source with one or more EGUs subject to this
Subpart B
must shall submit to the Agency an Annual Certification of
Compliance with this Subpart B
no later than May 1 of each year and must
shall address compliance for the previous calendar year. Such
certification must
shall be submitted to the Agency, Air Compliance and
Enforcement Section, and the Air Regional Field Office.
2)
Annual Certifications of Compliance must
shall indicate whether
compliance existed for each EGU for each month in the year covered by
the Certification and
certification it must certify to that effect. In addition,
for each EGU, the owner or operator must
shall provide the following
appropriate data as set forth in subsections (d)(2)(A) through (d)(2)(E) of
this Section, together with the data set forth in subsection (d)(2)(F) of this
Section:
142
A)
If complying with this Subpart B
by means of Section
225.230(a)(1)(A) or 225.237(a)(1)(A):
i)
Actual emissions rate, in lb/GWh, for each 12-month
rolling period ending in the year covered by the
Certification;
ii)
Actual emissions, in lbs, and gross electrical output, in
GWh, for each 12-month rolling period ending in the year
covered by the Certification; and
iii)
Actual emissions, in lbs, and gross electrical output, in
GWh, for each month in the year covered by the
Certification and in the previous year.
B)
If complying with this Subpart B
by means of Section
225.230(a)(1)(B) or 225.237(a)(1)(B):
i)
Actual control efficiency for emissions for each 12-month
rolling period ending in the year covered by the
Certification, expressed as a percent;
ii)
Actual emissions, in lbs, and mercury content in the fuel
fired in such EGU, in lbs, for each 12-month rolling period
ending in the year covered by the Certification; and
iii)
Actual emissions, in lbs, and mercury content in the fuel
fired in such EGU, in lbs, for each month in the year
covered by the Certification and in the previous year.
C)
If complying with this Subpart B
by means of Section 225.230(b):
i)
Actual emissions and allowable emissions for each 12-
month rolling period ending in the year covered by the
Certification; and
ii)
Actual emissions and allowable emissions, and which
standard of compliance the owner or operator was utilizing
for each month in the year covered by the Certification and
in the previous year.
D)
If complying with this Subpart B
by means of Section 225.230(d):
i)
Actual emissions and allowable emissions for all EGUs at
the source for each 12-month rolling period ending in the
year covered by the Certification; and
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ii)
Actual emissions and allowable emissions, and which
standard of compliance the owner or operator was utilizing
for each month in the year covered by the Certification and
in the previous year.
E)
If complying with this Subpart B
by means of Section 225.232:
i)
Actual emissions and allowable emissions for all EGUs at
the source in an Averaging Demonstration for each 12-
month rolling period ending in the year covered by the
Certification; and
ii)
Actual emissions and allowable emissions, with the
standard of compliance the owner or operator was utilizing
for each EGU at the source in an Averaging Demonstration
for each month for all EGUs at the source in an Averaging
Demonstration in the year covered by the Certification and
in the previous year.
F)
Any deviations, data substitutions, or exceptions each month and
discussion of the reasons for such deviations, data substitutions, or
exceptions.
3)
All Annual Certifications of Compliance required to be submitted must
shall include the following certification by a responsible official:
I certify under penalty of law that this document and all attachments were
prepared under my direction or supervision in accordance with a system
designed to assure that qualified personnel properly gather and evaluate
the information submitted. Based on my inquiry of the person or persons
directly responsible for gathering the information, the information
submitted is, to the best of my knowledge and belief, true, accurate, and
complete. I am aware that there are significant penalties for submitting
false information, including the possibility of fine and imprisonment for
knowing violations.
4)
The owner or operator of an EGU must
shall submit its first Annual
Certification of Compliance to address calendar year 2009 or the calendar
year in which the EGU commences commercial operation, whichever is
later. Notwithstanding subsection (d)(2) of this Section, in the Annual
Certifications of Compliance that are required to be submitted by May 1,
2010, and May 1, 2011, to address calendar years 2009 and 2010,
respectively, the owner or operator is not required to provide 12-month
rolling data for any period that ends before June 30, 2010.
144
e)
Deviation Reports. For each EGU, the owner or operator must
shall promptly
notify the Agency of deviations from requirements of this Subpart B
. At a
minimum, these notifications must
shall include a description of such deviations
within 30 days after discovery of the deviations, and a discussion of the possible
cause of such deviations, any corrective actions, and any preventative measures
taken.
f)
Quality Assurance RATA Reports. The owner or operator of an EGU must
shall
submit to the Agency, Air Compliance and Enforcement Section, the quality
assurance RATA report for each EGU or group of EGUs monitored at a common
stack and each non-EGU
under pursuant to 40 CFR 75.82(b)(2)(ii), incorporated
by reference in Section 225.140, within 45 days after completing a quality
assurance RATA.
Section 225.295
Treatment of Mercury Allowances
Any mercury allowances allocated to the Agency by the USEPA must
shall be treated as follows:
a)
No such allowances
must shall may be allocated to any owner or operator of an
EGU or other sources of mercury emissions into the atmosphere or discharges
into the waters of the State.
b)
The Agency must
shall hold all allowances allocated by the USEPA to the State.
At the end of each calendar year, the Agency must
shall instruct the USEPA to
retire permanently all such allowances.
I, Dorothy M. Gunn, Clerk of the Illinois Pollution Control Board, certify that the Board
adopted the above opinion and order on November 2, 2006, by a vote of 4-0.
Dorothy M. Gunn, Clerk
Illinois Pollution Control Board
145
APPENDIX TO THE OPINION AND ORDER
R06-25 – Acronyms/Abbreviations
ACI
activated carbon injection
APA
Administrative Procedure Act
ASTM
American Society for Testing and Materials
CAA
Clean Air Act
CAAPP
Clean Air Act Permit Program
CAIR
Clean Air Interstate Rule
CAMR
Clean Air Mercury Rule
CEMS
continuous emissions monitoring system
CFR
Code of Federal Regulations
CMAQ
Community Multi-Scale Air Quality
CWLP
City Water, Light & Power
DCEO
Department of Commerce and Economic Opportunity
DOE
United States Department of Energy
EGU
Electric Generating Unit
EPA
Environmental Protection Agency
EPRI
Electric Power Research Institute
ESP
electrostatic precipitator
FCMP
Fish Contaminant Monitoring Program
FGD
flue gas desulfurization scrubber
GWh
gigawatt hour
HAP
hazardous air pollutant
HCI
halogenated carbon injection
Hg
0
elemental mercury
Hg
2+
reactive gaseous mercury
Hg
p
particulate mercury
IERG
Illinois Environmental Regulatory Group
MACT
maximum achievable control technology
Mmacf
million actual cubic feet
MPS
Multi-Pollutant Standard
MW
megawatt
MWC
municipal waste combuster
Mwe
megawatt electrical
MWh
megawatt hour
NAAQS
National Ambient Air Quality Standards
NHANES
National Health and Nutrition Examination Survey
NO
x
nitrogen oxides
NRC
National Research Council
PAC
powdered activated carbon
PCB
polychlorinated biphenyls
PM
particulate matter
146
PM
2.5
particulate matter with an aerodynamic diameter less than or equal to a nominal
2.5 micrometers
PPM
parts per million
PRB
Powder River Basin
PSD
prevention of significant deterioration
RATA
relative accuracy test audit
RfD
reference dose
RGM
reactive gaseous mercury
SCA
specific collection area
SCR
selective catalytic reduction
SIP
State Implementation Plan
SIPC
Southern Illinois Power Cooperative
SNCR
selective non- catalytic reduction
SO
2
sulfur dioxide
SO
3
sulfur trioxide
TEAM
Trace Element Analysis Model
TSD
Technical Support Document
TTBS
Temporary Technology Based Standard
USEPA
United States Environmental Protection Agency
