BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
IN THE MATTER OF
:
)
1
STATIONARY RECIPROCATING INTERNAL
)
PCB R07- 18
COMBUSTION ENGINES AND TURBINES:
)
AMENDMENTS TO 35 ILL. ADM. CODE
)
SECTION 201.146, PARTS 2 1 1 AND 2 17
1
NOTICE OF FILING
To:
Dorothy Gunn, Clerk
Timothy Fox
Illinois Pollution Control Board
Hearing Officer
100 West Randolph Street
Illinois Pollution Control Board
Suite 1 1-500
100 West Randolph, Suite 1 1-500
Chicago, Illinois 60601
Chicago, Illinois 60601
Mathew Dunn
Illinois Attorney General's Office
Environmental Control Division
James R. Thompson Center
100 West Randolph Street
Chicago, Illinois 60601
Virginia I
.
Yang, Deputy Counsel
Illinois Department of Natural Resources
One Natural Resources Way
Springfield, Illinois 62702-1 27 1
Rachel Doctors
Division of Legal Counsel
Illinois Environmental Protection Agency
102 1 North Grand Avenue East
P.O. Box 19276
Springfield, Illinois 62794-9276
Please take notice that on April 16,2007, we filed with the Office of the Clerk of the Illinois Pollution
Control Board via electronic mail the
OBJECTION TO USE OF SECTION 28.5 FAST TRACK
PROCEDURES FOR CONSIDERATION OF NITROGEN OXIDE PROPOSAL AS FILED,
and
APPEARANCE
copies of which are served upon you.
ANR PIPELINE COMPANY, NATURAL GAS PIPELINE
COMPANY, TRUNKLINE GAS COMPANY, AND
PANHANDLE EASTERN PIPELINE COMPANY
(COLLECTIVELY, THE "PIPELINE CONSORTIUM")
By:
pne of their ~ttorny~s
Renee Cipriano
Elizabeth
A. Leifel
Sonnenschein Nath
&
Rosenthal LLP
7800 Sears Tower
233 S. Wacker Drive
Chicago, IL 60606-6404
Electronic Filing, Received, Clerk's Office, April 16, 2007
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
IN THE MATTER OF
:
1
)
STATIONARY RECIPROCATING INTERNAL
)
PCB R07-18
COMBUSTION ENGINES AND TURBINES:
1
AMENDMENTS TO 35 ILL. ADM. CODE
1
SECTION 201.146, PARTS 21 1 AND 21 7
)
OBJECTION TO USE OF SECTION 28.5 FAST TRACK PROCEDURES
FOR CONSIDERATION OF NITROGEN OXIDE PROPOSAL AS FILED
Now comes ANR Pipeline Company, Natural Gas Pipeline Company, Trunkline Gas
Company, and Panhandle Eastern Pipeline Company (collectively, the "Pipeline Consortium"),
by their attorneys, Sonnenschein Nath and Rosenthal, LLP, and respectfully request that the
Board reject the proposal of the Illinois Environmental Protection Agency ("IEPA" or the
"Agency") to proceed with this proposed rulemaking, as currently presented to this Board, under
the procedures of Section 28.5 of the Illinois Environmental Protection Act (the "Act"), 41
5
ILCS 5128.5. The Agency's proposal to amend 35 Ill. Adm. Code
6
201.146, and Parts 21 1 and
21 7, to the extent it applies to units other than
NOx SIP Call Phase I1 affected units, does not
satisfy the requirements of Section 28.5 because application of the rule statewide is not
"federally required to be adopted" by the Clean Air Act, 42 U.S.C.
5
7401,
et
seq. As such, the
proceeding as proposed by the Agency is not the type of situation contemplated by the General
Assembly when it enacted the Section 28.5 "fast
track" authority and is an improper exercise of
Section 28.5 of the Act.
The Pipeline Consortium is willing to set aside its objection as to the portion of the
Agency's proposal that applies to
NOx SIP Call Phase I1 affected units, but only if the Board
grants the request of the Pipeline Consortium to bifurcate and move the portion of the Agency's
Electronic Filing, Received, Clerk's Office, April 16, 2007
proposal that does not apply to NOx SIP Call Phase I1 affected units to a separate docket that
proceeds under Section 27 of the Act.'
I.
INTRODUCTION
The Pipeline Consortium is a group of natural gas suppliers that provide safe and reliable
delivery of natural gas for servicing local utilities and distribution companies, industrial and
small businesses, farmers, and the expansive commercial and residential customers in Illinois
and adjacent states. The pipeline facilities operated by Consortium members are intentionally
over-designed. Indeed, FERC-regulated pipeline systems are specifically required to be
designed for peak capacity to assure available capacity for the public at all times (although the
engines and turbines are not run at all times). This is a critical point for this rulemaking, because
the targeted engines and turbines tend to be small, and because low utilization of these engines
and turbines is commonplace at many facilities.
The Agency's proposal, deemed filed on April 6,2007, is designed to reduce nitrogen
oxide
("NOx") emissions from natural gas-fired stationary reciprocating internal combustion
engines and turbines. The Agency has justified proceeding with its proposed rule pursuant to
Section 28.5 because it contends the proposal is required pursuant to U.S.
EPA's NOx State
Implementation Plan ("SIP") Call Phase
11. The Agency's position unfortunately becomes
confusing and misleading through the Agency's further and apparent attempt to justify the
proceeding by bundling together several different regulatory programs that are not all necessary
'
The Pipeline Consortium notes that the Agency's proposal, filed days before the religious holiday weekend and
accepted as filed on April 6,2007, contains the Agency's position and arguments on the use of the fast-track
rulemaking procedure. As such, this filing presents a response to the Agency's assertion that it has satisfied the
requirements of Section 28.5. Because the Agency has already had an opportunity to make its case, the Pipeline
Consortium does not believe that the requirements of 35
Ill. Adm. Code
§
101.500(d) apply. However, in the event
that the Board elects to treat the Pipeline Consortium's objection and proposal to bifurcate as subject to the time
frames in Section
101.500(d), strict adherence to the 14-day response time requirement is inappropriate here.
Indeed, regardless of the Board's position, the Board should not proceed to accept the Agency's proposal and set the
requisite schedule until such time as the Pipeline Consortium's objection and proposal to bifurcate are fully
considered and decided by this Board.
Electronic Filing, Received, Clerk's Office, April 16, 2007
under, or even relevant to, Phase I1 of the SIP Call. As such, and for reasons stated herein, the
Pipeline Consortium objects to proceeding pursuant to Section 28.5 to the extent the Agency's
proposal includes requirements beyond those responsive to Phase
I1 of the SIP Call.
Accordingly, the Pipeline Consortium respectfully requests that the Board move portions of the
Agency's proposal that are not relevant to the Phase
I1 of the SIP Call to a separate docket that
proceeds according to Section
27's general rulemaking procedures.
11.
ARGUMENT
Background
Of Illinois' Fast Track Rulemaking
The Agency has filed this rulemaking proposal pursuant to Section 28.5 of the Act, 415
ILCS 5128.5, which allows certain rules required under the federal Clean Air Act to proceed on
an expedited schedule to prevent imposition of sanctions by the United States Environmental
Protection Agency ("U.S. EPA"). The intent and history of Section 28.5 demonstrate that the
fast track procedures were meant as a narrow solution to a very particular problem,
i. e. that
lengthy formal rulemaking processes could hinder the Board from promulgating rules required
under the Clean Air Act in accordance with federally-imposed
deadline^.^
Whether a rule may proceed on this "fast track" depends on whether the rule is required
to be adopted under the Clean Air Act. For purposes of Section 28.5, "requires to be adopted"
refers only to those regulations or parts of regulations for which the U.S. EPA "is empowered to
impose sanctions against the State for failure to adopt such rules." 415 ILCS
5/28.5(c). If the
Agency fails to demonstrate that the rule is required under federal law and sanctions may be
imposed, the Board may decide not to allow the rule to proceed on a fast track.
35 Ill. Adm.
Code
5
102.302.
See
Report of the Attorney General's Task Force on Environmental Legal Issues
-
1992.
Electronic Filing, Received, Clerk's Office, April 16, 2007
Background of the NOx SIP Call
In October 1998, U.S. EPA took final action in the NOx SIP Call Rule to prohibit
specified amounts of emissions of
NOx, one of the main precursors of ground-level ozone, to
reduce ozone transport across State boundaries in the eastern half of the United States. 63 Fed.
Reg. 57,355-57,538 (Oct. 27, 1998). U.S. EPA concluded that 22 states and the District of
Columbia emit
NOx in amounts that contribute to the non-attainment of ozone standards in
downwind states. U.S.
EPA,used its authority under Sections 110(a)(l) and 110(k)(5) and issued
a SIP Call, requiring those 23 states to amend their
SIPs to reduce NOx emissions so as not to
adversely affect the ozone attainment status of downwind states.
Several industry and labor groups challenged the
NOx SIP Call in federal court. In
response to the resulting court order, U.S. EPA divided the
NOx SIP Call into two phases: Phase
I and Phase
11. Under Phase I, U.S. EPA required 19 states and the District of Columbia to
comply with the SIP Call by October 30,2000 for Phase I affected units. Under Phase
11, U.S.
EPA required the remaining states to comply with the SIP Call by April 1, 2005 and required all
states with large reciprocating internal combustion engines to develop
SIPs by April 1, 2005 to
achieve
NOx reductions commensurate with Phase I1 rule requirements.
The
NOx SIP Call Phase I1 makes clear that states have the flexibility to adopt "the
appropriate mix of controls for their State to meet the
NOx emissions reductions requirements of
the
NOx SIP Call." Specifically, U.S. EPA recognizes that states may choose to regulate large
internal combustion engines to meet the
NOx reduction targets, or they may choose to establish
emissions reductions targets for individual companies and allow those companies to develop a
plan to achieve that target.
Electronic Filing, Received, Clerk's Office, April 16, 2007
On February 8,2006, U.S. EPA found that Illinois had failed to submit the required SIP
revisions in response to Phase
I1 of the SIP Call. This finding of failure indicated that U.S. EPA
intended to develop a Federal Implementation Plan ("FIP") pursuant to Section 1
10(c) of the
Clean Air Act that would be implemented in place of the SIP in the event the deficient states
failed to amend their
SIPS in a timely manner. 71 Fed. Reg. 6347 (Feb. 8,2006)
Importantly, the
NOx SIP Call affected only large engines, with average ozone season
emissions in 1995 grater than one ton per day, which is equivalent to approximately 2,400 hp
with 100% utilization for the entire 153-day season. IEPA inappropriately concludes that a SIP
Call engine is equivalent to 1,500 hp3 and has proposed measures here that go well beyond
requirements sufficient to satisfy U.S.
EPAYs SIP Call, arguing that all elements of the proposal,
including the regulation of
all
engines 500 hp and larger and turbines 3.5 MW and larger,
regardless of their location, are authorized to proceed as a Section 28.5 fast track rulemaking.
IEPA's Statement of Reasons Does Not Support A Fast Track Proceeding
The Agency characterizes its proposal as purportedly intending to satisfy Illinois'
obligations under the
NOx SIP Call Phase 11,
as well as
the Clean Air Act's requirements for
reasonable further progress, reasonably available control technology
("RACT"), rate-of-progress
("ROP"), and attainment demonstrations for the 8-hour ozone and PM2.5 National Ambient Air
Quality Standards
("NAAQS") (IEPA's Statement of Reasons, at pp. 1-2). The only piece of the
proposal, however, that is even arguably federally necessary in this veritable bundle of emission
reduction strategies is the reductions related to
NOx SIP Call Phase I1 units.
First and foremost, while additional
NOx reductions may eventually be necessary to
address PM and ozone non-attainment, there is nothing under the
NOx SIP Call Phase 11, or other
existing federal law, that requires a state specifically to regulate internal combustion engines and
3
Technical Support Document, p. 17.
Electronic Filing, Received, Clerk's Office, April 16, 2007
turbines, let alone requires control of these engines statewideY4 or control of units as small as 500
hp and 3.5
MW. In fact, NOx RACT is predominantly implemented in non-attainment areas
only, and U.S. EPA only requires that the state
consider NOx RACT for sources in non-
attainment areas. The Agency cannot use Phase I1 of the NOx SIP Call to justify the imposition
of
NOx RACT.
Most critical to the fast track analysis, there is not an immediate time constraint or threat
of federal sanctions pertaining to deficiencies associated with 8-hour ozone or fine particulate
SIPS, as the SIP Call clearly is based only on the 1-hour ozone NAAQS.~ Therefore, the NOx
RACT provisions are not appropriate for a Section 28.5 proceeding to the extent they go beyond
what is required for Phase
I1 unitsS6
Further, although the Agency has said that it cannot "submit a plan that would
demonstrate attainment or meet RACT or ROP requirements for the
PM2
5
or 8-hour ozone
NAAQS" without the proposed rule, this is simply not true.
(IEPAYs Statement of Reasons, at p.
10). IEPA has provided no justification for the need or environmental benefit of control of all
units statewide at the proposed thresholds or compared the efficacy of these measures with the
broad array of other candidate control approaches. Any number of other measures or
combinations of measures could be proposed that would achieve similar or greater reductions.
In fact, consequences against the State for failing to meet U.S. EPA requirements would
attach only upon
IEPA's tardiness in addressing the Phase I1 units, and even those consequences
may not be considered "sanctions" within the meaning of Section 28.5. In the February 8,2006,
69 Fed. Reg. 21,604,21,605 (April 21, 2004).
'
The Pipeline Consortium believes its assertion that the NOx RACT portion of the Agency's proposal is not
federally required to be adopted at this time is sufficient to support moving this portion of the proposal to a separate
docket proceeding as a Section 27 rulemaking. However, to the extent the Board accepts the Agency's
characterization that the
NOx RACT proposal is "federally required" under general federal SIP requirements, the
Pipeline Consortium further responds that at the very least, the portion of the
NOx RACT proposal that applies in
attainment areas is not federally required and should be moved to a separate docket.
Electronic Filing, Received, Clerk's Office, April 16, 2007
Finding of Failure, U.S. EPA expressly states that it will pursue a FIP should a submission to
address Phase
I1 of the SIP Call not be forthcoming. See 71 Fed. Reg. 6347, 6348. It is well-
established that the imposition of a FIP does not constitute a "sanction" under the Clean Air Act.
See Virginia
v. EPA, 74 F.3d 517,521 (4th Cir. 1996) (noting the availability of sanctions under
Section 179 but differentiating these from the imposition of a FIP, which is merely an "additional
incentive for state compliance");
Dynegy Midwest Generation, Inc. v. Ill. Pollution Control Bd.,
Docket No. 06-CH-2 13, Order on Motion for Preliminary Injunction (May 1,2006) (finding that
the plaintiff utilities were likely to succeed on the merits of their claim against the Board because
the imposition of a Federal Mercury Plan did not constitute a sanction under the Clean Air Act).
Not only is the application of the Agency's proposed rule to non-Phase
I1 units
unnecessary to satisfy Phase
I1 of the SIP Call, the Agency has also failed to demonstrate the
rule's importance to protecting air quality. In fact, modeling by the Lake Michigan Air Directors
Consortium ("LADCO") demonstrates that emission reductions for all units need not be adopted
statewide to improve air quality in Illinois (See "Attachment A" of the Agency's Technical
Support Document). The modeling shows that attainment area emissions from non-electricity
generating units have a relatively minor impact relative to emissions within the non-attainment
area, which have far greater impact. Further modeling is already underway that will refine the
existing data. Bifurcating this mlemaking by moving portions applicable to non-Phase
I1 units to
a separate docket will allow the Board to consider this new modeling before making a final
decision on non-Phase
I1 units and will not compromise the State's obligation to address Phase I1
of the SIP Call, in any way.
Electronic Filing, Received, Clerk's Office, April 16, 2007
If The Board Adopts The Rule Through Section 28.5, The Rule Will Be Void And
Unenforceable
Recent actions taken in the Board's mercury rulemaking proceeding demonstrate the
harm of allowing a proposed rule that is more stringent than required by federal law to proceed
as a fast track rulemaking. In
In the Matter of Proposed New 35 Ill. Adm. Code Part 225 Control
of Emissions from Large Combustion Sources,
PCB R06-25, several utility companies objected
to the Agency's proposal to proceed with the rulemaking on a fast track pursuant to Section
28.5.
The utilities argued that the Agency's proposed rule deviated significantly from the federal Clean
Air Mercury Rule ("CAMR") and that CAMR did not justify or compel the Agency's proposal.
After finding that the filing of the utilities' motions were not ripe as of the date on which
the Board was compelled to determine whether the rulemaking could proceed on a fast track,' the
Board ordered the rulemaking to proceed on a fast track and did not take final action on the
arguments raised in the utilities' filings. Once the Board ruled, the utilities filed a Motion for
Temporary Restraining Order in the Circuit Court for the Seventh Judicial Circuit in
Sangamon
County, arguing that the Board's order to proceed with the rulemaking on a fast track caused
irreparable harm by depriving the utilities of a fair hearing. The Court agreed and ordered the
Board to halt proceeding with the mercury rulemaking on a fast track.
Dynegy Midwest
Generation, Inc.
v.
Ill. Pollution Control Bd.,
Docket No. 06-CH-2 13, Order on Motion for
Preliminary Injunction, May 1,2006.
The mercury rulemaking debacle should guide the Board's decision here. As with the
mercury rulemaking, the Pipeline Consortium will be irreparably harmed if the entire proposed
rule is allowed to proceed on the fast track and since the proposed rule, in its entirety, is not
7
The Board found that the utilities' filings were subject to 35 111. Adm. Code
§ 105.500(d),
which requires a 14-day
period for the non-moving party to respond to a motion before the Board may rule. This procedure is subject to
certain exceptions where undue delay or hardship will result to the movant if the motion is not considered, or where
the proceeding in question is deadline-driven and no waiver has been filed.
Electronic Filing, Received, Clerk's Office, April 16, 2007
federally required, the Consortium will likely succeed on the merits.
See Id.
Further, the
Pipeline Consortium is entitled to a formal and complete rulemaking process and the interest of
the public will be better served by having costs of statewide application fully considered.
See Id.
To do otherwise may only invite Court intervention, when it could have easily and appropriately
been avoided.
In addition to a court proceeding to stop the rulemaking from going forward, appellate
courts are also able to overturn a rule that is promulgated outside of the Board's statutory
authority.
See Waste Management of Ill., Inc.
v.
Ill. Pollution Control Bd.,
595 N.E.2d 1171 (lS'
Dist. 1992). Section 28.5 is an exception to the Board's general rulemaking authority under the
Act. Thus, if it appears to the Court that the Board incorrectly misused its authority by adopting
a statewide rule when there is no federal requirement to do so, the Court may very well set aside
the rule.
See, e.g., Ill. State Chamber of Commerce
v.
Ill. Pollution Control Bd.,
384 N.E.2d 922
(lSt Dist. 1978) (overturning a rule because the Board had failed to hold a required hearing on the
rule or obtain the required economic impact study). This is a consequence that benefits no one.
Sensitivity to the use of the fast track procedures is specifically heightened in this case
because a number of features of the traditional Section 27 rulemaking procedure were eliminated
under Section 28.5 to afford a truncated procedure. One such feature eliminated from Section
28.5 fast track rulemakings was the Board's responsibility to obtain an economic impact study.
Here, the Pipeline Consortium believes that an economic impact study of the controls that would
be required under a Section 27 rulemaking would reveal that cost to the natural gas industry of
application of the mle to non-Phase
I1 units would exceed $80 million, a cost that should be fully
considered when the benefit to the environment is minimal, at best.
See Id.
This economic
impact cannot and should not be ignored, and the Pipeline Consortium and public interest must
Electronic Filing, Received, Clerk's Office, April 16, 2007
not be deprived of the ability to obtain an economic impact study to weigh the cost benefit of the
State's proposal.
111.
CONCLUSION
For over one year prior to the Agency's decision to propose this rule with statewide
application included, the Pipeline Consortium worked diligently with the Agency to resolve
various issues with the proposed rule. Continuing in this spirit of cooperation, the Pipeline
Consortium is willing to set aside its objection to proceeding pursuant to Section 28.5 for the
portion of the rule that applies to
NOx SIP Call Phase I1 units. The Pipeline Consortium,
however, cannot agree to allow that portion of the rule related to non-Phase
I1 units to proceed
without the full and complete process offered by Section 27 of the Act, to consider statewide
application and the associated costs in light of the minimal (if any) environmental benefit that
may result.
For all the reasons stated above, the Pipeline Consortium respectfully requests that the
Board place the portion of the proposed rule that applies to non-Phase
I1 units in a separate
docket for full consideration.' To assist the Board in bifurcating this proceeding and to
demonstrate the ease in so doing, the Pipeline Consortium includes as Exhibits A the proposal to
address
NOx SIP Call Phase I1 units that may proceed under Illinois' fast track process. The
proposal that should proceed under Section 27 of the Act could similarly be fashioned by
addressing units and associated provisions excluded from Exhibit
A
and removing the Exhibit A
affected units.
The Board has, in the past, segregated portions of a proposed rule into a separate docket where the Board
determines that it needs additional information.
See, e.g., In the Matter oj TieredApproach to Corrective Action
Objectives (TACO), 35
Ill. Adm. Code Part 742,
PCB R97-12(A) (April 17, 1997).
Electronic Filing, Received, Clerk's Office, April 16, 2007
Dated April 16,2007
Respectfully submitted,
ANR PIPELINE COMPANY, NATURAL GAS
PIPELINE COMPANY, TRUNKLINE GAS
COMPANY, AND PANHANDLE EASTERN
PIPELINE COMPANY (COLLECTIVELY, THE
"PIPELINE CONSORTIUM")
By:
Renee Cipriano
Elizabeth A. Leifel
SONNENSCHEIN NATH
&
ROSENTHAL LLP
7800 Sears Tower
233 South Wacker Drive
Chicago, Illinois 60606
(3 12) 876-8000
Electronic Filing, Received, Clerk's Office, April 16, 2007
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
IN
THE MATTER OF
:
)
)
STATIONARY RECIPROCATING INTERNAL
)
PCB R07- 18
COMBUSTION ENGINES AND TURBINES:
1
AMENDMENTS TO 35 ILL. ADM. CODE
)
SECTION 20 1.146, PARTS 2 1 1 AND 2 17
1
APPEARANCE
The undersigned, as one of its attorneys, hereby enters an Appearance on behalf of ANR
PPELINE COMPANY, NATURAL GAS PIPELINE COMPANY, TRUNKLINE GAS COMPANY,
AND PANHANDLE EASTERN PIPELINE COMPANY (COLLECTIVELY, THE "PIPELINE
CONSORTIUM").
ANR PIPELINE COMPANY, NATURAL GAS
PIPELINE COMPANY, TRUNKLINE GAS
COMPANY, AND PANHANDLE EASTERN
PIPELINE COMPANY (COLLECTIVELY, THE
"PIPELINE CONSORTIUM")
Renee Cipriano
Elizabeth A. Leifel
Sonnenchein Nath
&
Rosenthal LLP
7800 Sears Tower
233 South Wacker Drive
Chicago, Illinois 60606
Electronic Filing, Received, Clerk's Office, April 16, 2007
CERTIFICATE OF SERVICE
The undersigned, an attorney, certify that I have served upon the individuals named on the
attached Notice of Filing true and correct copies of the
OBJECTION TO USE OF SECTION 28.5
FAST TRACK PROCEDURES FOR CONSIDERATION OF NITROGEN OXIDE PROPOSAL
AS FILED, and APPEARANCE
via First Class Mail, postage prepaid on April 16, 2007.
Electronic Filing, Received, Clerk's Office, April 16, 2007
Exhibit A
Electronic Filing, Received, Clerk's Office, April 16, 2007
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
TITLE 35: ENVIRONMENTAL PROTECTION
SUBTITLE B: AIR POLLUTION
CHAPTER I: POLLUTION CONTROL BOARD
SUBCHAPTER C: EMISION STANDARDS AND LIMITATIONS
FOR STATIONARY SOURCES
PART 217
NITROGEN OXIDES EMISSIONS
SUBPART Q: STATIONARY RECIPROCATING INTERNAL COMBUSTION ENGINES
AND TURBINES
Section 217.386
Applicability
a)
A stationary reciprocating internal combustion engine
listed in Appendix G
or
turbine that meets the criteria in subsection (a)(1) or (a)(2) of this Section is an
affected unit and is subject to the requirements of this Subpart Q.
1)
The engine at nameplate capacity is rated at equal to or greater than 500
bhp output; or
2)
The turbine is rated at equal to or greater than 3.5 MW (4,694 bhp) output
at 14.7 psia, 59
o
F, and 60 percent relative humidity.
b)
Notwithstanding subsection (a) of this Section, an engine or turbine will not be an
affected unit and is not subject to the requirements of this Subpart Q, if the engine
or turbine is or has:
1)
Used as an emergency or standby unit as defined by 35 Ill. Adm. Code
211.1920;
2)
Used for research or for the purposes of performance verification or
testing;
Electronic Filing, Received, Clerk's Office, April 16, 2007
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
3)
Used to control emissions from landfills, where at least 50 percent of the
heat input is gas collected from a landfill;
4)
Used for agricultural purposes including the raising of crops or livestock
that are produced on site, but not associated businesses like packing
operations, sale of equipment or repair;
5)
A nameplate capacity rated at less than 1500 bhp (1118 kW) output,
mounted on a chassis or skids, designed to be moveable, and moved to a
different source at least once every 12 months; or
6)
Regulated under Subpart W or a subsequent federal NO
x
Trading program
for electrical generating units.
c)
If an exempt unit ceases to fulfill the criteria specified in subsection (b) of this
Section, the owner or operator must notify the Agency in writing within 30 days
after becoming aware that the exemption no longer applies and comply with the
control requirements of this Subpart Q.
d)
The requirements of this Subpart Q will continue to apply to any engine or turbine
that has ever been subject to the control requirements of Section 217.388, even if
the affected unit ceases to fulfill the rating requirements of subsection (a) of this
Section or becomes eligible for an exemption pursuant to subsection (b) of this
Section.
Section 217.388
Control and Maintenance Requirements
On and after the applicable compliance date in Section 217.392, an owner or operator of an
affected unit must inspect and maintain affected units as required by subsection (d) of this
Section and comply with either the applicable emissions concentration as set forth in subsection
(a) of this Section, or the requirements for an emissions averaging plan as specified in subsection
(b) of this Section or the requirements
for operation as a low usage unit as specified in subsection
(c) of this
Section
.
a)
The owner or operator must limit the discharge from an affected unit into the
atmosphere of any gases that contain NO
x
to no more than:
1)
150 ppmv (corrected to 15 percent O
2
on a dry basis) for spark-ignited
rich-burn engines;
2)
210 ppmv (corrected to 15 percent O
2
on a dry basis) for spark-ignited
Electronic Filing, Received, Clerk's Office, April 16, 2007
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
lean-burn engines, except for existing spark-ignited Worthington engines
that are not listed in Appendix G;
3)
365 ppmv (corrected to 15 percent O
2
on a dry basis) for existing spark-
ignited Worthington engines that are not listed in Appendix G;
4)
660 ppmv (corrected to 15 percent O
2
on a dry basis) for diesel engines;
5)
42 ppmv (corrected to 15 percent O
2
on a dry basis) for gaseous fuel-fired
turbines; and
6)
96 ppmv (corrected to 15 percent O
2
on a dry basis) for liquid fuel-fired
turbines.
b)
The owner or operator must comply with the requirements of the applicable
emissions averaging plan as set forth in Section 217.390.
c)
The owner or operator must operate the affected unit as a low usage unit pursuant
to subsection (c)(1) or (c)(2) of this Section. Low usage units are not subject to
the requirements of this Subpart Q except for the requirements to inspect and
maintain the unit pursuant to subsection (d) of this Section, and retain records
pursuant to Sections 217.396(b) and (c). Only one of the following exemptions
may be utilized at a particular source:
1)
The potential to emit (PTE) is no more than 100 TPY NO
x
aggregated
from all engines and turbines located at the source that are not otherwise
exempt pursuant to Section 217.386(b), and not complying with the
requirements of subsection (a) or (b) of this Section and the NO
x
PTE
limit is contained in a federally enforceable permit; or
2)
The aggregate bhp-hr/MW-hr from all affected units located at the source
that are not exempt pursuant to Section 217.386(b), and not complying
with the requirements of subsection (a) or (b) of this Section, are less than
or equal to the bhp-hrs and MW-hrs operation limit listed in subsection
(c)(2)(A) and (c)(2)(B) of this Section. For units not located at a natural
gas transmission compressor station or storage facility that drive a natural
gas compressor station, the operation limits of subsections (c)(2)(A) and
(B) of this
Section must be contained in a federally enforceable permit.
A)
8 mm bhp-hrs or less on an annual basis for engines; and
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B)
20,000 MW-hrs or less on an annual basis for turbines.
d)
The owner or operator must inspect and perform periodic maintenance on the
affected unit, in accordance with a Maintenance Plan that documents:
1)
For a unit not located at natural gas transmission compressor station or
storage facility either:
A)
The manufacturer’s recommended inspection and maintenance of
the applicable air pollution control equipment, monitoring device,
and affected unit; or
B)
If the original equipment manual is not available or substantial
modifications have been made that require an alternative procedure
for the applicable air pollution control device, monitoring device,
or affected unit, the owner or operator must establish a plan for
inspection and maintenance in accordance with what is customary
for the type of air pollution control equipment, monitoring device,
and affected unit.
2)
For a unit located at a natural gas compressor station or storage facility,
the operator’s maintenance procedures for the applicable air pollution
control device, monitoring device, and affected unit.
Section 217.390
Emissions Averaging Plans
a)
An owner or operator of certain affected units may comply through an emissions
averaging plan.
1)
The unit or units that commenced operation before January 1, 2002, may
be included in an emissions averaging plan as follows:
A)
Units located at a single source or at multiple sources in Illinois, so
long as the units are owned by the same company or parent
company where the parent company has working control through
stock ownership of its subsidiary corporations. A unit may be
listed in only one emissions averaging plan;
B)
Units that have a compliance date later than the control period for
which the averaging plan is being used for compliance; and
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C)
Units which the owner or operator may claim as exempt pursuant
to Section 217.386(b) but does not claim exempt. For as long as
such a unit is included in an emissions averaging plan, it will be
treated as an affected unit and subject to the applicable emission
concentration limits, testing, monitoring, recordkeeping and
reporting requirements.
2)
The following types of units may not be included in an emissions
averaging plan:
A)
Units that commence operation after January 1, 2002, unless the
unit replaces an engine or turbine that commenced operation on or
before January 1, 2002, or it replaces an engine or turbine that
replaced a unit that commenced operation on or before January 1,
2002. The new unit must be used for the same purpose as the
replacement unit. The owner or operator of a unit that is shutdown
and replaced must comply with the provisions of Section
217.396(d)(3) before the replacement unit may be included in an
emissions averaging plan.
B)
Units which the owner or operator is claiming are exempt pursuant
to Section 217.386(b) or as a low usage unit pursuant to Section
217.388(c).
b)
An owner or operator must submit an emissions averaging plan to the Agency by
the applicable compliance date set forth in Section 217.392. The plan must
include, but is not limited to:
1)
The list of affected units included in the plan by unit identification number
and permit number.
2)
A sample calculation demonstrating compliance using the methodology
provided in subsection (f) of this Section for both the ozone season and
calendar year.
c)
An owner or operator may amend an emissions averaging plan only once per
calendar year. An amended plan must be submitted to the Agency by May 1 of
the applicable calendar year. If an amended plan is not received by the Agency
by May 1 of the applicable calendar year, the previous year’s plan will be the
applicable emissions averaging plan.
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d)
Notwithstanding subsection (c) of this Section, an owner or operator, and the
buyer, if applicable:
1)
Must submit an updated emissions averaging plan or plans to the Agency
within 60 days, if a unit that is listed in an emissions averaging plan is sold
or taken out of service.
2)
May amend its emissions averaging plan to include another unit within 30
days of discovering that the unit no longer qualifies as an exempt unit
pursuant to Section 217.386(b) or as a low usage unit pursuant to Section
217.388(c).
e)
An owner or operator must:
1)
Demonstrate compliance for both the ozone season (May 1 through
September 30) and the calendar year (January 1 through December 31) by
using the methodology and the units listed in the most recent emissions
averaging plan submitted to the Agency pursuant to subsection (b) of this
Section; the higher of the monitoring or test data determined pursuant to
Section 217.394; and the actual hours of operation for the applicable
control period;
2)
Notify the Agency by October 31 following the ozone season, if
compliance cannot be demonstrated for that ozone season; and
3)
Submit to the Agency by January 31 following each calendar year, a
compliance report containing the information required by Section
217.396(d)(4).
f)
The total mass of actual NO
x
emissions from the units listed in the emissions
averaging plan must be equal to or less than the total mass of allowable NO
x
emissions for those units for both the ozone season and calendar year. The
following equation must be used to determine compliance:
N
act
≤
N
all
Where:
n
N
act
=
Σ
EM
act (i)
i
=1
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n
N
all
=
Σ
i
=1
EM
all(i)
N
act
=
Total sum of the actual NO
x
mass emissions from units
included in the averaging plan for each fuel used (lbs per
ozone season and calendar year).
N
all
=
Total sum of the allowable NO
x
mass emissions from units
included in the averaging plan for each fuel used (lbs
per ozone season and calendar year).
EM
all(i)
=
Total mass of allowable NO
x
emissions in lbs for a unit as
determined in subsection (g)(2), (g)(3), (g)(4), (g)(5),or
(g)(6) of this Section.
EM
act(i)
=
Total mass of actual NO
X
emissions in lbs for a unit as
determined in subsection (g)(1), (g)(3), (g)(5) or (h) of
this Section.
i
=
Subscript denoting an individual unit and fuel used.
n
=
Number of different units in the averaging plan.
g)
For each unit in the averaging plan, and each fuel used by a unit, determine actual
and allowable NO
x
emissions using the following equations, except as provided
for in subsection (h) of this Section:
1)
Actual emissions must be determined as follows:
EM
act(i)
=
E
act(i)
x H
i
m
2)
Allowable emissions must be determined as follows:
EM
all(i)
=
E
all(i)
x H
i
Where:
EM
act(i)
=
Total mass of actual NO
x
emissions in lbs for a unit.
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EM
all(i)
=
Total mass of allowable NO
x
emissions in lbs for a unit.
E
act
=
Actual NO
x
emission rate (lbs/mmBtu) calculated
according to the above equation.
E
all
=
Allowable NO
x
emission rate (lbs/mmBtu) calculated
according to the above equation.
H
=
Heat input (mmBtu/ozone season or mmBtu/year)
calculated from fuel flow meter and the heating value of the
fuel used.
C
d(act)
=
Actual concentration of NO
x
in lb/dscf (ppmv x 1.194 x
10
-7
) on a dry basis for the fuel used. Actual concentration
is determined on each of the most recent test run or
monitoring pass performed pursuant to Section 217.394,
whichever is higher.
C
d(all)
=
Allowable concentration of NO
x
in lb/dscf (allowable
emission limit in ppmv specified in Section 217.388(a),
except as provided for in subsection (g)(6) of this Section,
if applicable.
multiplied by 1.194 x 10
-7
) on a dry basis for the fuel used.
F
d
=
The ratio of the gas volume of the products of combustion
to the heat content of the fuel (dscf/mmBtu) as given in the
table of F Factors included in 40 CFR 60, Appendix A,
Method 19 or as determined using 40 CFR 60, Appendix A,
Method 19.
%O
2d
=
Concentration of oxygen in effluent gas stream measured
on a dry basis during each of the applicable test or
monitoring runs used for determining emissions, as
represented by a whole number percent, e.g., for 18.7%O
2d
,
18.7 would be used.
i
=
Subscript denoting an individual unit and the fuel used.
j
=
Subscript denoting each test run or monitoring pass for an
affected unit for a given fuel.
m
=
The number of test runs or monitoring passes for an
affected unit using a given fuel.
3)
For a replacement unit that is electric-powered, the allowable NO
x
emissions from the affected unit that was replaced should be used in the
averaging calculations and the actual NO
x
emissions for the electric-
powered replacement unit (EM
(i)act elec
) are zero. Allowable NO
x
emissions for the electric-powered replacement are calculated using the
actual total bhp-hrs generated by the electric-powered replacement unit on
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an ozone season and on an annual basis multiplied by the allowable NO
x
emission rate in lb/bhp-hr of the replaced unit.
The allowable mass of NO
x
emissions from an electric-powered
replacement unit (EM
(i)all elec
) must be determined by multiplying the
nameplate capacity of the unit by the hours operated during the ozone
season or annually and the allowable NO
x
emission rate of the replaced
unit (E
all rep
) in lb/mmBtu converted to lb/bhp-hr. For this calculation the
following equation should be used:
EM
all elec(i)
= bhp x OP x F x E
all rep(i)
Where:
EM
all elec(i)
=
Mass of allowable NO
x
emissions from the electric-
powered replacement unit in pounds per ozone season or
calendar year.
bhp
=
Nameplate capacity of the electric-powered
replacement unit in brake-horsepower.
OP
=
Operating hours during the ozone season or calendar year.
F
=
Conversion factor of 0.0077 mmBtu/bhp-hr.
E
all rep(i)
=
Allowable NO
X
emission rate (lbs/mmBtu) of the replaced
unit.
i
=
Subscript denoting an individual electric unit and the fuel
used.
4)
For a replacement unit that is not electric, the allowable NO
x
emissions
rate used in the above equations set forth in subsection (g)(2) of this
Section must be either:
A)
Prior to the applicable compliance date for the replaced unit
pursuant to Section 217.392, the higher of the actual NO
x
emissions as determined by testing or monitoring data or the
applicable uncontrolled NO
x
emissions factor from Compilation of
Air pollutant emission Factors: AP-42, Volume I: Stationary Point
and Area Sources, as incorporated by reference in Section 217.104
for the unit that was replaced; or
B)
On and after the applicable compliance date for the replaced unit
pursuant to Section 217.392, the applicable emissions
concentration for the type of unit that replaced pursuant to Section
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217.388(a).
5)
For a unit that is replaced with purchased power, the allowable NO
x
emissions rate used in the above equations set forth in subsection (g)(2) of
this Section must be the emissions concentration as set forth in Section
217.388(a) or subsection (g)(6) of this Section, when applicable, for the
type of unit that was replaced. For owners or operators replacing units
with purchased power, the annual hours of operations that must be used
are the calendar year hours of operation for the unit that was shutdown
averaged over the three-year period prior to the shutdown. The actual
NO
x
emissions for the units replaced by purchased power (EM
(i)act
) are
zero. These units may be included in any emissions averaging plan for no
more than five years beginning with the calendar year that the replaced
unit is shut down.
6)
For units that have a later compliance date,
For non-Appendix G units
used in an emissions averaging plan,
allowable emissions rate used in
the above equations set forth in subsection (g)(2) of this Section must be:
A)
Prior to the applicable compliance date pursuant to Section
217.392, the higher of the actual NO
x
emissions as determined by
testing or monitoring data, or the applicable uncontrolled NO
x
emissions factor from Compilation of Air Pollutant Emission
Factors: AP-42, Volume I: Stationary Point and Areas Sources, as
incorporated by reference in Section 217.104
; and
B)
On and after the units applicable compliance date pursuant to
Section 217.392, the applicable emissions concentration for that
type of unit pursuant to Section 217.388(a).
h)
For units that use CEMS the data must show that the total mass of actual NO
x
emissions determined pursuant to subsection (h)(1) of this Section is less than or
equal to the allowable NO
x
emissions calculated in accordance with the equations
in subsections (f) and (h)(2) of this Section for both the ozone season and calendar
year. The equations in subsection (g) of this Section will not apply.
1)
The total mass of actual NO
x
emissions in lbs for a unit (EM
act
) must be
the sum of the total mass of actual NO
x
emissions from each affected unit
using CEMS data collected in accordance with 40 CFR 60 or 75, or
alternate methodology that has been approved by the Agency or USEPA
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and included in a federally enforceable permit.
2)
The allowable NO
x
emissions must be determined as follows:
Where:
EM
all(i)
=
Total mass of allowable NO
x
emissions in lbs for a unit.
Flow
i
=
Stack flow (dscf/hr) for a given stack.
Cd
i
=
Allowable concentration of NO
x
(ppmv) specified in
Section 217.388(a) of this subpart for a given stack. (1.194
x 10
-7
) converts to lb/dscf).
j
=
subscript denoting each hour operation of a given unit.
m
=
Total number of hours of operation of a unit.
i
=
Subscript denoting an individual unit and the fuel used.
Section 217.392
Compliance
a)
An owner or operator of an affected unit may not operate that unit unless it meets
the applicable concentration limit in Section 217.388(a), or is included in an
emissions averaging plan pursuant to Section 217.388(b), or meets the low usage
requirements pursuant to Section 217.388(c), and complies with all other
applicable requirements of this Subpart Q by the earliest applicable date listed
below:
1)
On and after May 1, 2007, an owner or operator of an affected engine
listed in Appendix G may not operate the affected engine unless the
requirements of this Subpart Q are met or the affected engine is exempt
pursuant to Section 217.386(b)
.
;
2)
On and after January 1, 2009, an owner or operator of an affected unit and
that is located in Cook, DuPage, Aux Sable Township and Goose Lake
Township in Grundy, Kane, Oswego Township in Kendall, Lake,
McHenry, Will, Jersey, Madison, Monroe, Randolph Township in
Randolph, or St. Clair County, and is not listed in Appendix G may not
operate the affected unit unless the requirements of this Subpart Q are met
or the affected unit is exempt pursuant to Section 217.386(b);
3)
On and after January 1, 2011, an owner or operator of an affected engine
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with a nameplate capacity rated at 1500 bhp or more, and affected turbines
rated at 5 MW (6,702 bhp) or more that is not subject to subsection (a)(1)
or (a)(2) of this Section, may not operate the affected unit unless the
requirements of this Subpart Q are met or the affected unit is exempt
pursuant to Section 217.386(b); or
4)
On and after January 1, 2012, an owner or operator of an affected engine
with a nameplate capacity rated at less than 1500 bhp or an affected
turbine rated at less than 5 MW (6,702 bhp) that is not subject to
subsection (a)(1), (a)(2) or (a)(3) of this Section, may not operate the
affected engine or turbine unless the requirements of this Subpart Q are
met or the affected unit is exempt pursuant to Section 217.386(b).
b)
Owners and operators of an affected unit may use NO
x
allowances to meet the
compliance requirements in Section 217.388 as specified below. A NO
x
allowance is defined as an allowance used to meet the requirements of a NO
x
trading program administered by USEPA where one allowance is equal to one ton
of NO
x
emissions.
1)
NO
x
allowances may only be used under the following circumstances:
A)
An anomalous or unforeseen operating scenario inconsistent with
historical operations for a particular ozone season or calendar year
that causes an emissions exceedance.
B)
To achieve compliance no more than twice in any rolling five-year
period.
C)
For a unit that is not listed in Appendix G.
2)
The owner or operator of the affected unit must surrender to the Agency
one NO
x
allowance for each ton or portion of a ton of NO
x
by which
actual emissions exceed allowed emissions. For noncompliance with a
seasonal limit, a NO
x
ozone season allowance must be used. For
noncompliance with the emissions concentration limits in Section
217.388(a) or an annual limitation in an emissions averaging plan, only a
NO
x
annual allowance may be used.
3)
The owner or operator must submit a report documenting the
circumstances that required the use of NO
x
allowances and identify what
actions will be taken in subsequent years to address these circumstances
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and must transfer the NO
x
allowances to the Agency’s federal NO
x
retirement account. The report and the transfer of allowances must be
submitted by October 31 for exceedances during the ozone season and
March 1 for exceedances of the emissions concentration or the annual
emission averaging plan limits. The report must contain the NATS serial
numbers of the NO
x
allowances.
Section 217.394
Testing and Monitoring
a)
An owner or operator of an engine or turbine must conduct an initial performance
test pursuant to subsection (c)(1) or (c)(2) of this Section as follows:
1)
By May 1, 2007, for affected engines listed in Appendix G. Performance
tests must be conducted on units listed in Appendix G, even if the unit is
included in an emissions averaging plan pursuant to Section 217.388(b).
2)
By the applicable compliance date as set forth in Section 217.392, or
within the first 876 hours of operation per calendar year, whichever is
later
:
A)
For affected units not listed in Appendix G that operate more than
876 hours per calendar year; and
B)
F
f
or units that are not affected units that are included in an
emissions averaging plan and operate more than 876 hours per
calendar year.
3)
Once within the five-year period after the applicable compliance date as
set forth in Section 217.392:
A)
For affected units that operate fewer than 876 hours per calendar
year; and
B)
For units that are not affected units that are included in an
emissions averaging plan and that operate fewer than 876 hours per
calendar year
b)
An owner or operator of an engine or turbine must conduct subsequent
performance tests pursuant to subsection (c)(1) or (c)(2) of this Section as
follows:
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1)
For affected engines listed in Appendix G and all units included in an
emissions averaging plan, once every five years. Testing must be
performed in the calendar year by May 1 or within 60 days of starting
operation, whichever is later;
2)
If the monitored data shows that the unit is not in compliance with the
applicable emissions concentration or emissions averaging plan, the owner
or operator must report the deviation to the Agency in writing within 30
days and conduct a performance test pursuant to subsection (c) of this
Section within 90 days of the determination of noncompliance; and
3)
When in the opinion of the Agency or USEPA, it is necessary to conduct
testing to demonstrate compliance with Section 217.388, the owner or
operator of a unit must, at his or her own expense, conduct the test in
accordance with the applicable test methods and procedures specified in
this Section 217.394 within 90 days of receipt of a notice to test from the
Agency or USEPA.
c)
Testing Procedures:
1)
For an engine: The owner or operator must conduct a performance test
using Method 7 or 7E of 40 CFR 60, Appendix A, as incorporated by
reference in Section 217.104. Each compliance test must consist of three
separate runs, each lasting a minimum of 60 minutes. NO
x
emissions must
be measured while the affected unit is operating at peak load. If the unit
combusts more than one type of fuel (gaseous or liquid) including backup
fuels, a separate performance test is required for each fuel.
2)
For a turbine
included in an emissions averaging plan
: The owner
operator must conduct a performance test using the applicable procedures
and methods in 40 CFR 60.4400, as incorporated by reference in Section
217.104.
d)
Monitoring: Except for those years in which a performance test is conducted
pursuant to subsection (a) or (b) of this Section, the owner or operator of an
affected unit or a unit included in an emissions averaging plan must monitor NO
x
concentrations annually, once between January 1 and May 1 or within the first
876 hours of operation per calendar year, whichever is later. If annual operation
is less than 876 hours per calendar year, each affected unit must be monitored at
least once every five years. Monitoring must be performed as follows:
1)
A portable NO
x
monitor and utilizing method ASTM D6522-00, as
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incorporated by reference in Section 217.104, or a method approved by
the Agency must be used. If the engine or turbine combusts both liquid or
gaseous fuels as primary or backup fuels, separate monitoring is required
for each fuel.
2)
NO
x
and O
2
concentrations measurements must be taken three times for a
duration of at least 20 minutes. Monitoring must be done at highest
achievable load. The concentrations from the three monitoring runs must
be averaged to determine whether the affected unit is in compliance with
the applicable emissions concentration or emissions averaging plan as
specified in Section 217.388.
e)
Instead of complying with the requirements of subsections (a), (b), (c) and (d) of
this Section, an owner or operator may install and operate a CEMS on an affected
unit that meets the applicable requirements of 40 CFR 60, subpart A, and
Appendix B, incorporated by reference in Section 217.104, and complies with the
quality assurance procedures specified in 40 CFR 60, Appendix F, or 40 CFR 75
as incorporated by reference in Section 217.104, or an alternate procedure as
approved by the Agency or USEPA in a federally enforceable permit. The CEMS
must be used to demonstrate compliance with the applicable emissions
concentration or emissions averaging plan only on an ozone season and annual
basis.
Section 217.396
Recordkeeping and Reporting
a)
Recordkeeping. The owner or operator of a unit included in an emissions
averaging plan or an affected unit that is not exempt pursuant to Section
217.386(b) and is not subject to the low usage exemption of Section 217.388(c)
must maintain records that demonstrate compliance with the requirements of this
Subpart Q which include, but are not limited to:
1)
Identification, type (e.g., lean-burn, gas-fired), and location of each unit.
2)
Calendar date of the record.
3)
The number of hours the unit operated on a monthly basis, and during
each ozone season.
4)
Type and quantity of the fuel used on a daily basis.
5)
The results of all monitoring performed on the unit and reported
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deviations.
6)
The results of all tests performed on the unit.
7)
The plan for performing inspection and maintenance of the units, air
pollution control equipment, and the applicable monitoring device
pursuant to Section 217.388(d).
8)
A log of inspections and maintenance performed on the unit’s air
emissions, monitoring device, and air pollution control device. These
records must include, at a minimum, date, load levels and any manual
adjustments along with the reason for the adjustment (e.g., air to fuel ratio,
timing or other settings).
9)
If complying with the emissions averaging plan provisions of Sections
217.388(b) and 217.390 copies of the calculations used to demonstrate
compliance with the ozone season and annual control period limits,
noncompliance reports for the ozone season, and ozone and annual control
period compliance reports submitted to the Agency.
10)
Identification of time periods for which operating conditions and pollutant
data were not obtained by either the CEMS or alternate monitoring
procedures including the reasons for not obtaining sufficient data and a
description of corrective actions taken.
11)
Any NO
x
allowance reconciliation reports submitted pursuant to Section
217.392(e).
b)
The owner or operator of an affected unit that is complying with the low usage
provisions of Section 217.388(c), must:
1)
For each unit complying with Section 217.388(c)(1), maintain a record of
the NO
x
emissions for each calendar year; or
2)
For each unit complying with Section 217.388(c)(2), maintain a record of
bhp or MW hours operated each calendar year.
c)
The owner or operator of an affected unit or unit included in an emissions
averaging plan must maintain the records required by subsections (a) and (b) of
this Section for a period of five-years at the source at which the unit is located.
The records must be made available to the Agency and USEPA upon request.
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d)
Reporting requirements:
1)
The owner or operator must notify the Agency in writing 30 days and five
days prior to testing pursuant to Section 217.394(a) and:
A)
If after the 30-days notice for an initially scheduled test is sent,
there is a delay (e.g., due to operational problems) in conducting
the performance test as scheduled, the owner or operator of the unit
must notify the Agency as soon as possible of the delay in the
original test date, either by providing at least seven days prior
notice of the rescheduled date of the performance test, or by
arranging a new test date with the Agency by mutual agreement;
B)
Provide a testing protocol to the Agency 60 days prior to testing;
and
C)
Not later than 30 days after the completion of the test, submit the
results of the test to the Agency.
2)
Pursuant to the requirements for monitoring in Section 217.394(d), the
owner or operator of the unit must report to the Agency any monitored
exceedances of the applicable NO
x
concentration from Section 217.388(a)
or (b) within 30 days of performing the monitoring.
3)
Within 90 days of permanently shutting down an affected unit or a unit
included in an emissions averaging plan, the owner or operator of the unit
must withdraw or amend the applicable permit to reflect that the unit is no
longer in service.
4)
If demonstrating compliance through an emissions averaging plan:
A)
By October 31 following the applicable ozone season, the owner or
operator must notify the Agency if he or she cannot demonstrate
compliance for that ozone season; and
B)
By January 30 following the applicable calendar year, the owner or
operator must submit to the Agency a report that demonstrates the
following:
i)
For all units that are part of the emissions averaging plan,
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ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
the total mass of allowable NO
x
emissions for the ozone
season and for the annual control period;
ii)
The total mass of actual NO
x
emissions for the ozone
season and annual control period for each unit included in
the averaging plan;
iii)
The calculations that demonstrate that the total mass of
actual NO
x
emissions are less than the total mass of
allowable NO
x
emissions using equations in Sections
217.390(f) and (g); and
iv)
The information required to determine the total mass of
actual NO
x
emissions and the calculations performed in
subsection (d)(4)(B)(iii) of this Section.
5)
If operating a CEMS, the owner or operator must submit an excess
emissions and monitoring systems performance report in accordance with
the requirements of 40 CFR 60.7(c) and 60.13, or 40 CFR 75 incorporated
by reference in Section 217.104, or an alternate procedure approved by the
Agency or USEPA and included in a federally enforceable permit.
6)
If using NO
x
allowances to comply with the requirements of Section
217.388, reconciliation reports as required by Section 217.392(b)(3).
Electronic Filing, Received, Clerk's Office, April 16, 2007
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
APPENDIX G: EXISTING RECIPROCATING INTERNAL COMBUSTION ENGINES
AFFECTED BY NOx SIP CALL
Plant ID
Point ID
Segment
ANR Pipeline Co. – Sandwich
093802AAF
E-108
1
Natural Gas Pipeline Co. of America 8310
027807AAC
730103540041
1
Natural Gas Pipeline Co. of America Sta 110
073816AAA
851000140011
1
073816AAA
851000140012
2
073816AAA
851000140013
3
073816AAA
851000140014
4
073816AAA
851000140041
1
073816AAA
851000140051
1
Northern Illinois Gas Co. - Stor Stat 359
113817AAA
730105440021
1
113817AAA
730105440031
1
113821AAA
730105430021
1
113821AAA
730105430051
1
Panhandle Eastern Pipe Line Co.-Glenarm
167801AAA
87090038002
1
167801AAA
87090038004
1
167801AAA
87090038005
1
Panhandle Eastern Pipeline - Tuscola St
041804AAC
73010573009
9
041804AAC
73010573010
10
041804AAC
73010573011
11
041804AAC
73010573012
12
041804AAC
73010573013
13
Electronic Filing, Received, Clerk's Office, April 16, 2007
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
Panhandle Eastern Pipeline Co.
149820AAB
7301057199G
3
149820AAB
7301057199I
1
149820AAB
7301057199J
1
149820AAB
7301057199K
1
Panhandle Eastern Pipeline Co.-Glenarm
167801AAA
87090038001
1
Phoenix Chemical Co.
085809AAA
730700330101
1
085809AAA
730700330102
2
085809AAA
730700330103
3
Electronic Filing, Received, Clerk's Office, April 16, 2007
