ILLINOIS POLLUTION CONTROL BOARD
May 7, 2009
IN THE MATTER OF:
AMENDMENTS TO 35 ILL. ADM. CODE
217, NITROGEN OXIDES EMISSIONS,
AND 35 ILL. ADM. CODE 211
)
)
)
)
)
R08-19
(Rulemaking - Air)
Proposed Rule. First Notice.
OPINION AND ORDER OF THE BOARD (by A.S. Moore):
On May 9, 2008, the Illinois Environmental Protection Agency (Agency or Illinois EPA
or IEPA) filed a proposal under the general rulemaking provisions of Sections 27 and 28 of the
Environmental Protection Act (Act) (415 ILCS 5/27, 28 (2006)). On both January 30, 2009, and
March 23, 2009, the Agency filed motions to amend the proposal based on negotiations with
interested parties. Generally, the Agency proposes to amend Parts 211 and 217 of the Board’s
air pollution regulations (35 Ill. Adm. Code 211, 217) to control nitrogen oxides (NO
x
) emissions
from major stationary sources in the nonattainment areas and from emission units including
industrial boilers, process heaters, glass melting furnaces, cement kilns, lime kilns, furnaces used
in steelmaking and aluminum melting, and fossil fuel-fired stationary boilers at such sources.
The first-notice amendments set forth below are intended primarily to reduce NO
x
emissions from those various sources and units. Publication of these proposed amendments in
the
Illinois Register
will begin a 45-day public comment period.
In this opinion, the Board first reviews the procedural history of this rulemaking before
addressing a preliminary issue and providing a brief background on regulation of NO
x
emissions.
The Board then summarizes the post-hearing comments before addressing technical and
economic considerations. The Board then discusses its proposal for first-notice publication on a
section-by-section basis. The order following the opinion then sets forth the proposed
amendments for first-notice publication.
PROCEDURAL HISTORY
On May 9, 2008, the Agency filed a rulemaking proposal (Prop.) under the general
rulemaking provisions of Sections 27 and 28 of the Act. A Statement of Reasons (Statement)
and a Technical Support Document (TSD) accompanied the proposal. A motion for waiver of
copy requirements also accompanied the proposal. In an order dated June 5, 2008, the Board
accepted the Agency’s proposal for hearing and granted the Agency’s motion for waiver of copy
requirements.
In a letter dated June 6, 2008, the Board requested that the Department of Commerce and
Economic Opportunity (DCEO) conduct an economic impact study of the Agency’s rulemaking
proposal.
See
415 ILCS 5/27(b) (2006). DCEO has not responded to the Board’s request.
2
In an order dated June 12, 2008, the hearing officer scheduled a first hearing to begin on
October 14, 2008, in Springfield and a second hearing to begin December 9, 2008, in Chicago.
The order directed participants wishing to testify at the first hearing to pre-file their testimony no
later than September 2, 2008. The order also directed participants to pre-file questions based on
the Agency’s pre-filed testimony no later than September 16, 2008. Finally, the order directed
the Agency to pre-file written answers to those pre-filed questions no later than September 30,
2008.
On August 29, 2008, the Agency pre-filed testimony by Mr. Robert Kaleel (Kaleel Pre-
filed Test.), Mr. Vir Gupta (Gupta Pre-filed Test.), and James E. Staudt, Ph.D. (Staudt Pre-filed
Test.).
On September 15, 2008, Midwest Generation filed questions for the Agency’s witnesses
(MG Questions). On September 16, 2008, ExxonMobil Oil Corporation (ExxonMobil) filed
questions for the Agency’s witnesses (ExxonMobil Questions). Also on September 16, 2008, the
Illinois Environmental Regulatory Group (IERG) filed questions for the Agency’s witnesses
(IERG Questions). On September 30, 2008, the Agency filed three documents: answers to
questions submitted by Midwest Generation (MG Answers); answers to questions submitted by
ExxonMobil (ExxonMobil Answers); and answers to questions submitted by IERG (IERG
Answers).
The first hearing took place as scheduled on October 14, 2008, in Springfield. At the first
hearing, the hearing officer admitted into the record four exhibits:
Finding of Failure to Submit State Implementation Plans Required for the 1997 8-Hour
Ozone NAAQS, 73 Fed. Reg. 15416-21 (Mar. 24, 2008) (Exh. 1);
[Illinois Environmental Protection] Agency Analysis of Economic and Budgetary Effects
of Proposed Rulemaking (35 Ill. Adm. Code 211) (Exh. 2);
[Illinois Environmental Protection] Agency Analysis of Economic and Budgetary Effects
of Proposed Rulemaking (35 Ill. Adm. Code 217) (Exh. 3); and
Cleaver Brooks letter dated May 19, 2006, to New Hampshire Division of Environmental
Services (Exh. 4).
On October 24, 2008, the Board received the transcript of the first hearing (Tr.1).
On November 5, 2008, the Agency filed its responses to questions raised at the first
hearing (PC 1).
On November 25, 2008, the Board received pre-filed testimony for the December 9,
2008, hearing from Mr. Scott Miller and Mr. Kent Wanninger on behalf of Midwest Generation,
from Ms. Deirdre K. Hirner and Mr. David J. Kolaz on behalf of IERG, from Mr. Larry G.
Siebenberger and Mr. Blake E. Stapper on behalf of U.S. Steel, and from Mr. David W. Dunn on
3
behalf of ConocoPhillips. Also on November 25, 2008, the Board received pre-filed comments
submitted by ArcelorMittal (ArcelorMittal Comment). In addition, on November 25, 2008, the
Board received post-hearing comments relating to the October 14, 2008 hearing from Saint-
Gobain Containers, Inc. (Saint-Gobain) (PC 2).
The second hearing took place as scheduled on December 9 and 10, 2008, in Chicago.
Over the two days of the second hearing, the hearing officer admitted into the record fourteen
exhibits:
Pre-Filed Testimony of Deirdre K. Hirner on Behalf of the Illinois Environmental
Regulatory Group (Exh. 5);
Pre-Filed Testimony of David J. Kolaz on Behalf of the Illinois Environmental
Regulatory Group (Exh. 6);
from Final Rule to Implement the 8-Hour Ozone National Ambient Air Quality
Standard; Final Rule, 70 Fed. Reg. 71657 (Nov. 29, 2005) (Exh. 7);
Summary of NO
x
Budget Allocations and Usage 2007-2007 (Exh. 8);
Pre-Filed Testimony of David W. Dunn on Behalf of ConocoPhillips Company (Exh. 9);
Pre-Filed Testimony of Larry G. Siebenberger on Behalf of United States Steel
Corporation (Exh. 10);
Pre-Filed Testimony of Blake E. Stapper on Behalf of United States Steel Corporation
(Exh. 11);
Testimony of Scott Miller of Behalf of Midwest Generation (Exh. 12);
Testimony of Kent Wanninger on Behalf of Midwest Generation (Exh. 13);
IHS-CERA Power Capital Costs Index (PCCI) (Graph Included on Page 7 of Kent
Wanninger’s Testimony on Behalf of Midwest Generation) (Exh. 14);
Baldwin 3 graph (Exh. 15);
Joliet 71 boiler graph (Exh. 16);
Bureau of Labor Statistics Producer Price Index. Commodities Group: Metals and metal
products Item: Hot rolled bars, plates, and structural shapes (December 4, 2008) (Exh.
17); and
Bureau of Labor Statistics Producer Price Index. Commodities Group: Metals and metal
products Item: Carbon scrap steel (Dec. 4, 2008) (Exh. 18).
4
On December 30, 2008, the Board received the transcript of December 10, 2008, the second day
of the second hearing (Tr.3). On January 5, 2009, the Board received the transcript of December
9, 2008, the first day of the second hearing (Tr.2).
In an order dated December 23, 2008, the hearing officer scheduled a third hearing for
February 3, 2009, in Edwardsville and directed participants wishing to testify at the third hearing
to pre-file testimony no later than January 20, 2009.
On January 20, 2009, the Board received post-hearing comments from IERG (PC 3),
Saint-Gobain (PC 4), and ConocoPhillips (PC 5). Also on January 20, 2009, the Board received
pre-filed testimony on behalf of the Agency from Mr. Robert Kaleel (Kaleel Pre-filed Test. 2),
Mr. Michael Koerber (Koerber Pre-filed Test.), and James E. Staudt, Ph.D. (Staudt Pre-filed
Test. 2). Also on January 20, 2009, the Agency filed a motion to correct the transcript of the
second hearing.
On January 30, 2009, the Agency filed a motion to amend its rulemaking proposal (Mot.
Amend 1).
On January 30, 2009, the Board received supporting materials from U.S. Steel. (PC 6).
On February 2, 2009, the Board received pre-filed testimony of Mr. Blake E. Stapper on behalf
of U.S. Steel. On February 3, 2009, the Board received a public comment from Mr. James L.
Kavanaugh of the Missouri Department of Natural Resources (PC 7).
The third hearing took place as scheduled on February 3, 2009, in Edwardsville. During
the third hearing, the hearing officer admitted into the record seven exhibits:
Western Michigan Ozone Study: Draft Report (January 21, 2009) (Exh. 19);
Calculation of Available COG after Consumption in Reheat Furnaces (Exh. 20);
Calculation of Siebenberger Exhibit A Information — COG burned in reheat furnaces per
Siebenberger December testimony (Exh. 21);
Total Boiler COG Usage from Attachment C (Exh. 22);
Calculation of Siebenberger Exhibit A Information — with 2008 COG rate, 35 day
scrubber maint. (Exh. 23);
Calculation of Siebenberger Exhibit A Information — with 2008 COG rate, no COG
scrubber maint. (Exh. 24); and
Pre-Filed Testimony of Blake E. Stapper on Behalf of United States Steel Corporation
(Exh. 25).
On February 11, 2009, the Board received the transcript of the third hearing (Tr.4).
5
In an order dated February 19, 2009, the Board granted the Agency’s motion to amend its
rulemaking proposal and also granted the Agency’s motion to correct the transcript of the second
hearing.
On March 19, 2009, the Agency filed a motion for expedited review. Also on March 19,
2009, the Agency forwarded to the Board’s Acting Chairman, Dr. G. Tanner Girard, a letter from
the United States Environmental Protection Agency (USEPA) (PC 8). On March 20, 2009, the
Board received Midwest Generation’s response to the Agency’s motion for expedited review.
On March 23, 2009, the Board received from Agency Director Douglas P. Scott a letter
regarding expedited review of the Agency’s amended proposal. On March 26, 2009, the Board
received IERG’s response to the Agency’s motion for expedited review. In an order dated April
2, 2009, the Board granted the Agency’s motion for expedited review.
On March 23, 2009, the Board received post-hearing comments from Midwest
Generation (PC 9), ArcelorMittal (PC 10). U.S. Steel (PC 12), IERG (PC 13), and
ConocoPhillips (PC 14). Also on March 23, 2009, the Board received post-hearing comments
from the Agency (PC 11), accompanied by the Agency’s second motion to amend its rulemaking
proposal (Mot. Amend 2).
As the Board has granted the Agency’s motion for expedited review, the “mailbox rule”
at 35 Ill. Adm. Code 101.300(b)(2) does not apply to filing these first-notice comments. The
Board’s Clerk must receive these comments before the close of business on the final day of the
statutory 45-day comment period. Although documents may be filed electronically through the
Filing Public Comments
First-notice publication of these proposed rules in the
Illinois Register
will start a period
of at least 45 days during which any person may file a public comment with the Board,
regardless of whether the person has already filed a public comment in this proceeding.
See
5
ILCS 100/5-40(b) (2006) (Illinois Administrative Procedure Act).
As noted above under “Procedural History,” the Board on April 2, 2009, granted the
Agency’s motion for expedited review of the amended proposal. The Board is therefore highly
unlikely to grant any motion for an extension of the first-notice comment period. Consequently,
the Board strongly encourages participants who wish to file a public comment on these proposed
amendments to do so within the statutory 45-day period.
Public comments must be filed with the Clerk of the Board at the following address:
Pollution Control Board
John T. Therriault, Assistant Clerk
James R. Thompson Center
100 W. Randolph Street, Suite 11-500
Chicago, IL 60601
The docket number for this rulemaking, R08-19, should be indicated on the public comment.
6
Clerk’s Office On-Line (COOL) from the Board’s Web site at www.ipcb.state.il.us, all electronic
or approved fax filings must be received by the Clerk's Office no later than 4:30 PM on the 45th
day of the comment period. Any questions about electronic filing through COOL should be
directed to the Clerk’s Office at (312) 814-3629.
Please note that all filings with the Clerk of the Board must be served on the hearing
officer and on those persons on the Service List for this rulemaking. Before filing any document
with the Clerk, please check with the hearing officer or the Clerk’s Office to verify the current
version of the Service List.
PRELIMINARY ISSUE
On March 23, 2009, the Agency filed its second motion to amend its rulemaking
proposal. In the motion the Agency states that, “[s]ince the last hearing, the Illinois EPA has
continued to engage in negotiations with interested parties on remaining unresolved issues.”
Mot. Amend 2 at 1. The Agency further states that such negotiations with ConocoPhillips, U.S.
Steel, and ArcelorMittal have resulted in agreement to amend various provisions of the proposal.
Id
. at 1-2. Specifically, the Agency seeks 15 amendments to its original proposal.
Id
. at 6-14.
No participant responded to the Agency’s motion to amend.
See
35 Ill. Adm. Code
101.500(d). Based on its review of the Agency’s motion, and in the absence of any response to
that motion, the Board grants the Agency’s second motion to amend its rulemaking proposal.
While the Agency’s motion summarizes each of its proposed amendments, the Board addresses
those amendments on a section-by-section basis below in its discussion of the first-notice
proposal.
BACKGROUND ON REGULATION OF NO
x
EMISSIONS
NO
x
is one of the primary precursors to the formation of ozone and is also a precursor to
the formation of PM
2.5
.
1
The Agency also reports that, “[o]n July 18, 1997, USEPA revised the NAAQS for
particulate matter to add new standards for fine particles, using PM
2.5
as the indicator, and
established primary annual and 24-hour standards for PM
2.5
. Statement at 4, citing 62 Fed. Reg.
38652 (July 18, 1997). The Agency states that USEPA has recently strengthened the 24-hour
Statement at 2, 3.
The Agency reports that, “[o]n July 18, 1997, USEPA revised the NAAQS [National
Ambient Air Quality Standard] for ozone by replacing the 1-hour standard with an 8-hour
standard.” Statement at 3, citing 62 Fed. Reg. 38856 (July 18, 1997). Illinois includes two areas
designated as nonattainment for the 8-hour ozone standard. Statement at 3. The Chicago
nonattainment area includes Cook, DuPage, Kane, Lake, McHenry, and Will Counties, Goose
Lake and Aux Sable Townships in Grundy County, and Oswego Township in Kendall County.
Id
. The Metro East nonattainment area includes Jersey, Madison, Monroe, and St. Clair
Counties.
Id.
at 3, 5.
1
“PM
2.5
refers to particulate matter that is 2.5 micrometers or smaller in size.” Statement at 4.
7
standard. Statement at 4, citing 71 Fed. Reg. 61144 (Oct. 17, 2006). Illinois includes two areas
designated nonattainment for the PM
2.5
standard. Statement at 4. The Chicago nonattainment
area includes Cook, DuPage, Kane, Lake, McHenry, and Will Counties, Goose Lake and Aux
Sable Townships in Grundy County, and Oswego Township in Kendall County.
Id
. at 4-5. The
Metro East nonattainment area includes Madison, Monroe, and St. Clair Counties and Baldwin
Township in Randolph County.
Id
. at 5, citing 40 C.F.R. § 81.314.
The Agency states that Section 110 of the Clean Air Act (CAA) and other related
provisions require states to submit for USEPA approval State Implementation Plans (SIP) “that
provide for the attainment and maintenance of standards established by USEPA through control
programs directed to sources of the pollutants involved.” Statement at 2, citing 42 U.S.C. §
7410. The Agency further states that “[t]he CAA also provides for the State to address emissions
sources on an area-specific basis through such requirements as reasonably available control
measures (“RACM”) and reasonable available control technology (“RACT”).” Statement at 2,
citing 42 U.S.C §§ 7502, 7511a. Specifically, the CAA requires Illinois for each nonattainment
area “to demonstrate that it has adopted ‘all reasonably available control measures as
expeditiously as possible (including such reductions in emissions from existing sources in the
area as may be obtained through the adoption, at a minimum, of reasonable available control
technology) and shall provide for attainment of the national primary ambient air quality
standards.’” Statement at 2, 5, citing 42 U.S.C. § 7502(c)(1).
The Agency characterizes RACT as “[a] subset of RACM.” Statement at 6, citing 44
Fed. Reg. 53762 (Sept. 17, 1979). The Agency states that “Section 182(b)(2) of the CAA
requires states to adopt RACT rules for all areas designated nonattainment for ozone and
classified as moderate or above.” Statement at 6-7, citing 42 U.S.C. § 7511a(b)(2). The Agency
further states that Section 182(f) of the CAA requires each state in which all or part of a
moderate nonattainment area is located to adopt RACT for major NO
x
sources. Statement at 7,
citing 42 U.S.C. § 7511a(f). The Agency notes that “Section 302 of the CAA defines ‘major
stationary source’ as any stationary facility or source of air pollutants that directly emits, or has
the potential to emit, one hundred tons per year or more of any air pollutant.” Statement at 7,
citing 42 U.S.C. § 7602.
The Agency argues that these authorities “establish the requirements for Illinois to submit
NO
x
RACT regulations for all major stationary sources of NO
x
in PM
2.5
nonattainment areas and
ozone nonattainment areas classified as moderate and above.” Statement at 7, citing 72 Fed.
Reg. 20586 (Apr. 25, 2007); 70 Fed. Reg. 71612 (Nov. 29, 2005). The Agency further argues
that, because Illinois includes nonattainment areas classified as moderate and above for the 8-
hour ozone NAAQS, it was “required to submit by September 15, 2006, a SIP demonstrating that
sources specified under the CAA were subject to RACT requirements.” Statement at 7-8, citing
70 Fed. Reg. 71612 (Nov. 29, 2005). The Agency claims that “[o]n March 24, 2008, USEPA
made a finding that Illinois, among other states, failed to make a RACT submittal required under
Part D of Title I of the CAA for its two moderate nonattainment areas.” Statement at 8, citing 73
Fed. Reg. 15416 (Mar. 24, 2008). The Agency notes that “[s]uch finding starts the 18-month
emission offset sanctions clock and 24-month highway funding sanctions clock under Section
179(a) and (b) of the CAA and the 24-month clock for the promulgation by USEPA of a Federal
8
Implementation Plan under Section 110(c) of the CAA”. Statement at 8, citing 42 U.S.C. §§
7509(a) and (b), 7410(c).
In testimony for the third hearing, Mr. Kaleel stated that USEPA on December 22, 2008,
designated areas as nonattainment for the 24-hour PM
2.5
standard. Kaleel Pre-filed Test. 2 at 3.
He further stated that, in Illinois, USEPA has designated “the same areas designated previously
as nonattainment for the annual PM
2.5
standard.”
Id
. He added that “Illinois must develop an
attainment plan and adopt control measures needed to attain the 24-hour PM
2.5
standard within
three years of the effective date of U.S. EPA’s decision, and Illinois must attain the standards
within five years of the effective date.”
Id
.
Mr. Kaleel also addressed the establishment of nonattainment areas for the 2008 8-hour
ozone standard. He stated that the Agency’s “initial proposal is for Illinois to recommend to
USEPA to establish nonattainment boundaries for the 2008 standard that generally match the
boundaries already established for the 1997 ozone standard.” Kaleel Pre-filed Test. 2 at 3. He
anticipated that USEPA will complete nonattainment designations in 2010, “initiating a new
cycle of planning and regulatory development.”
Id
. at 3-4. He expects that, because NO
x
is a
precursor to both ozone and PM
2.5
, NO
x
emission reductions will improve air quality.
Id
. at 4.
He argues that “[t]he reductions provided by the subject NO
x
RACT proposal will help to meet
the new standards and should help to address any future requirements to implement RACT for
the new standards.”
Id
. Specifically, he claims that, “[u]nless USEPA issues new guidance
regarding NO
x
control technology, we expect that this RACT proposal will satisfy requirements
to implement NO
x
RACT under the revised NAAQS for the source categories and geographic
areas to which this proposal applies.” MG Answers at 1.
SUMMARY OF POST-HEARING COMMENTS
Midwest Generation (PC 9)
Midwest Generation states that, “[w]ith the amendments proposed to the Board by the
Agency in its Motion to Amend Rulemaking Proposal filed January 30, 2009, Midwest
Generation generally supports the Agency’s proposal as it applies to electric generating units.”
PC 9 at 1. Midwest Generation refers to amendments reflecting agreements with the Agency and
included in the Agency’s September 30, 2008, answers to Midwest Generation’s questions.
Id
.
at 1-2,
see
MG Answers at 4-6 (stating amenability to amending Sections 211.3100, 217.160,
217.340, and 217.342).
Midwest Generation acknowledges that a valid Illinois Clean Air Interstate Rule (CAIR)
“exempts it from the emission limitations of Subpart M.” PC 9 at 3. Midwest Generation also
comments that the Illinois CAIR is a valid rule because the U.S. Court of Appeals for the District
of Columbia remanded without vacating it.
Id
. at 3-4, citing North Carolina v. EPA, 550 F.3d
1176 (D.C. Cir. 2008).
Midwest Generation states that “[a]ll EGUs [electric generating units] subject to Subpart
M are subject to the Illinois CAIR.” PC 9 at 4. Midwest Generation observes, however, that the
Agency seeks in its proposed Subpart M to establish emissions limits for coal-fired EGUs.
Id
.;
9
see
Prop. at 51-52 (proposed new Section 217.344). Midwest Generation states that it sought to
determine that those proposed emission limits constitute RACT. PC 9 at 5. Midwest Generation
further states that, because its units subject to this rule already emit NO
x
at low rates, it “found
that it could not comply with the NO
x
rate proposed, 0.09 lbs/mmBtu, within the cost parameters
that the Agency determined was economically reasonable for this NO
x
RACT rule, $2500-3000
per ton of NO
x
removed.”
Id
. After discussing this position with the Agency and reviewing the
Agency’s first motion to amend its proposal, “Midwest Generation agrees that 0.12 lb/mmBtu is
supportable as NO
x
RACT for coal-fired EGUs” and encourages the Board to adopt that rate.
Id
.,
see
Mot. Amend at 10;
see also
Prop. at 52 (proposing limit of 0.09 lb/mmBtu). In addition,
Midwest Generation claims that, under proposed emission averaging provisions, “these
emissions limits can be determined on a plant-wide basis.” PC 9 at 3;
see
Prop. at 37-41,
Statement at 27-29.
Midwest Generation states that all of these revisions in the Agency’s answers and its
motion to amend “together clarify that EGUs that are subject to Part 225, Subparts C, D, and E
are exempt from the emission limitations of Subpart M.” PC 9 at 3.
ArcelorMittal (PC 10)
ArcelorMittal states that its facility located in Riverdale “has a permitted roller-hearth
tunnel furnace equipped with ultra-low NO
x
burners (ULNBs), which processes thin cast steel
slabs.” PC 10 at 1. ArcelorMittal argues that its tunnel furnace “cannot be considered as a
reheat, annealing, or galvanizing furnace,” and, under the applicability provision at proposed
Section 217.150, “is not subject to his rulemaking.”
Id
.;
see
Prop. at 26-27. ArcelorMittal
further argues, however, that setting and implementing additional NO
x
controls is neither
technologically feasible nor economically reasonable. PC 10 at 1, 2. The Board summarizes
ArcelorMittal’s comment in the following subsections of the opinion.
Technical Feasibility
ArcelorMittal notes that, while the Agency’s TSD lists ten steel industry emission units
applying NO
x
controls, “none of these units are similar to tunnel furnaces.” PC 10 at 2-3, citing
TSD, Appendices at 21-22. ArcelorMittal proceeds to address three broad categories of NO
x
controls. First, ArcelorMittal acknowledges that, while add-on controls may provide the highest
level of NO
x
reduction, they typically require exhaust streams with little or no variation in
characteristics such as temperature and oxygen content. PC 10 at 3. ArcelorMittal argues that,
“[o]utside of these ranges, the technologies are either ineffective or greatly compromised,
sometimes resulting in the creation of additional emissions or new air pollutants.”
Id
.
ArcelorMittal concludes that, considering the reduced oxygen content of the tunnel furnace and
other factors, “add-on NO
x
controls are not feasible for retrofit.”
Id
. at 3-4. Second, addressing
process controls, ArcelorMittal claims that, “[s]ince ULNBs are already used in the tunnel
furnace, the application of the other burner and FGR [flue gas recirculation] options would not
result in a reduction of NO
x
emissions.”
Id
. at 4. Addressing pre-combustion controls,
ArcelorMittal argues that, because it already relies on pipeline grade natural gas, “no other fuel
sources for this type of operation are known to further reduce the formation of NO
x
.”
Id
.
10
ArcelorMittal further argues that the Bloom Engineering Series 1430 ULNBs now in use
at its facility are “technology that is typically considered to represent RACT.” PC 10 at 5.
ArcelorMittal states that, while it explored installation of next-generation ULNBs with vendors,
it has concluded that “a burner upgrade for the tunnel furnace is infeasible” based on factors
including the effect on operation of the tunnel furnace and the impact on product quality.
Id
.
Economic Reasonableness
ArcelorMittal notes that the Agency provided a range for the cost effectiveness of NO
x
emission reduction of $2,500 - 3,000 per ton of emissions reduced. PC 10 at 5, citing Tr.1 at
165-66, 173-74; Tr.4 at 75. ArcelorMittal responded by developing an analysis of the cost
effectiveness of two burner models. PC 10 at 5;
see id
., Exh. A (ArcelorMittal Riverdale Tunnel
Furnace NO
x
RACT Analysis Estimated Cost Effectiveness for Burner Change). The first
indicated an actual emissions reduction of 25 tons per year and estimated a cost effectiveness of
$22,895 per ton of NO
x
removed. PC 10 at 6;
see id
., Exh. A. The second indicated an actual
emissions reduction of 29 tons per year and estimated a cost effectiveness of $39,472 per ton of
NO
x
removed. PC 10 at 6;
see id
., Exh. A. ArcelorMittal suggests that actual costs may be
much higher, as these figures include only materials and labor and do not reflect the production
downtime for the conversion process. PC 10 at 6.
ArcelorMittal also expresses concern with the effect of a burner upgrade on the operation
of the tunnel furnace. PC 10 at 7. Because of the nature of that operation and a lack of
redundancy, ArcelorMittal states that “the tunnel furnace must operate optimally at all times.”
Id
. at 8. ArcelorMittal further states that “altering the burners or heat system can have [a]
significant effect on the slab quality.”
Id
. at 7. ArcelorMittal suggests that such an effect would
undermine its investment in developing unique products.
See id
. at 8.
Summary
ArcelorMittal notes that, based on monitoring data from 2006-2008, the Agency intends
to request that USEPA redesignate Chicago as attaining the 1997 8-hour ozone NAAQS. PC 10
at 2, 9. ArcelorMittal thus argues that “NO
x
RACT should not be implemented if the Chicago
area achieves attainment.”
Id
. at 9. ArcelorMittal requests that the Agency “not develop and the
Board not adopt NO
x
RACT rules that further burden manufacturers as another means of
‘leapfrogging’ into other SIP initiatives that have longer timelines (
e.g.
, PM
2.5
or 2008 ozone
standard SIP rules) without allowing ‘on the book’ controls to take hold to further improve
ambient air quality.”
Id.
ArcelorMittal concludes by requesting that, if the Agency considers its tunnel furnace to
be subject to the proposed rule, the Agency “allow a case-by-case determination for the
applicability of this rule to the tunnel furnace.” PC 10 at 10. ArcelorMittal proposes that this
determination might include a specific definition or a separate category with a corresponding
emissions limit.
Id
. As an alternative, ArcelorMittal seeks the Agency’s concurrence in seeking
an adjusted standard.
Id
., citing Tr.1 at 128.
11
U.S. Steel (PC 12)
U.S. Steel states that the proposed rulemaking would impact boilers, slab reheat furnaces,
and galvanizing lines at its Granite City Works (GCW) facility in Granite City. PC 12 at 1-2,
citing Exh. 10 at 5. U.S. Steel reports that, after a series of discussions, it has reached agreement
with the Agency on determining NO
x
emission limits for Boilers 11 and 12 and slab furnaces 1
through 4. PC 12 at 2. Accordingly, U.S. Steel states that it “supports the Agency’s proposed
amendments to the rule.”
Id
. at 2.
However, U.S. Steel states that it seeks to clarify its concerns regarding its use of
desulfurized coke oven gas (COG). PC 12 at 2. First, U.S. Steel addresses IEPA’s proposal that
calculations for determining NO
x
limits during the averaging period will not include periods
when the COG desulfurization unit is shut down for maintenance, so long as certain conditions
are met.
Id
. at 3;
see
Prop. at 37-41 (proposed new Section 217.158). These conditions include
advance notice of shutdown and a limit on the number of shutdown days. PC 12 at 3. U.S. Steel
states that, while the IEPA’s proposal works for planned maintenance, it does not adequately
protect U.S. Steel from problems arising from unplanned outages or upsets.
Id.
Second, U.S. Steel stresses that it has not completed construction of its COG
desulfurization unit. PC 12 at 3. U.S. Steel also stresses that the proposed emissions limitations
are based on desulfurized COG having an
estimated
concentration of hydrogen cyanide of 130
ppm or less.
Id
. (emphasis in original). U.S. Steel thus states that future rulemakings may be
necessary to revise this figure after it completes construction of the COG desulfurization unit.
Id
. US Steel concludes its comment by stating that, while it wishes to continue discussing the
proposed Section 217.158 with the Agency, it “finds the Agency’s proposal acceptable for its
units at GCW.” PC 12 at 4.
ConocoPhillips (PC 14)
ConocoPhillips states that the Agency’s proposed NO
x
RACT limits apply to sources
“including many of the boilers and process heaters” at its Wood River Refinery (Refinery). PC
14 at 1. ConocoPhillips refers to Mr. Dunn’s testimony on its behalf that the proposal would
require large costs “to install certain controls on the affected boilers and process heaters.”
Id
. at
1-2, citing Exh. 9 at 6-12. ConocoPhillips also emphasizes Mr. Dunn’s conclusion that “the cost
per ton of NO
x
removed is well beyond the costs per ton that the Agency used to determine NO
x
RACT.” PC 14 at 2, citing Exh. 9 at 6-12.
Conoco Phillips states that it has met several times with the Agency to discuss and
“resolve several issues related to the implementation of the proposed rule at the Refinery.” PC
14 at 2. ConocoPhillips further states that it has “has reached an agreement with the Agency on
the majority of the issues raised by this rulemaking that impact the Refinery.”
Id
.
ConocoPhillips expresses its support for the Agency’s proposal, with the exception of the issues
summarized in the following two paragraphs.
Id
. ConocoPhillips pledges to continue working
with the Agency to resolve these remaining issues.
Id
.
12
First, ConocoPhillips notes that the Agency’s proposal “requires boilers and process
heaters over 100MMbtu/hr to utilize [Continuous Emissions Monitoring Systems] CEMS to
monitor and record NO
x
emissions.” PC 14 at 2, citing Exh. 9 at 14;
see
Prop. at 32-34
(proposed new Section 217.157(a)). ConocoPhillips states that “installation of CEMS at the
Refinery for compliance with the Agency’s rule will cost an estimated $12,600,000.” PC 14 at 3,
citing Exh. 9 at 15. ConocoPhillips claims that many of its process heaters “do not have stacks
designed for easy installation” of CEMS. PC 14 at 2, citing Exh. 9 at 15. Consequently,
ConocoPhillips “requests that the Agency and Board consider limiting CEMS installation
requirements to only those units greater than 250 MMBtu/hr.” PC 14 at 3.
Second, ConocoPhillips states that, with regard to emission controls, it requires additional
flexibility “in circumstances where, during planning and implementation of control projects,
ConocoPhillips determines that the cost per ton of NO
x
controlled is $15,000 or more,
i.e.
, the
cost significantly exceeds reasonably available control technology.” PC 14 at 3. At that cost
threshold, ConocoPhillips asserts that it “must have the ability to present a revised control
strategy to the Agency and/or the Board.”
Id
. ConocoPhillips states that it “welcomes the
Agency’s comments on this issue and will provide proposed regulatory language for Agency and
Board consideration at a later date.”
Id
.
Concluding its comment, ConocoPhillips states that it “supports the Agency’s proposed
amendments to the rule.” PC 14 at 3. ConocoPhillips further states, however, that it “intends to
continue discussions with the Agency on CEMS and control strategy flexibility.”
Id
.
IERG (PC 13)
IERG notes that the Agency’s Statement of Reasons filed on May 9, 2008, indicated that
the initial rulemaking proposal intended to satisfy requirements under the federal Clean Air Act
that Illinois submit a State Implementation Plan including NO
x
RACT for major stationary
sources in nonattainment areas for both ozone and PM
2.5
. PC 13 at 2, citing Statement at 5-8,
Kaleel Pre-filed Test. at 1-2, Tr.1 at 91. IERG also notes it own position in testimony pre-filed
for the second hearing “that the proposal went beyond what is required to satisfy the RACT
obligation.” PC 13 at 3, citing Exh. 6 at 3, 5-15, 16-19. IERG presented alternative emission
limits that it describes as consistent with its position on reasonably available control
technologies. PC 13 at 3, 4-5, citing Exh. 6 at 22-23.
IERG maintains the position that its own proposed emission limits “constitute NO
x
RACT for the current ozone and PM
2.5
standards.” PC 13 at 3. Nonetheless, IERG
acknowledges that the rationale for the Agency’s proposed rules “has evolved.”
Id
. Specifically,
IERG notes that the Agency on January 30, 2009, filed a motion to amend its proposal.
Id
.;
see
generally
Mot. Amend. IERG states that Mr. Kaleel’s testimony on behalf of the Agency
“described the new ozone and PM
2.5
standards, and stated that the emissions reductions from the
proposal would help to meet those new standards, as well as help satisfy the NO
x
RACT
requirement for SIPs submitted for those standards.” PC 13 at 4, citing Kaleel Pre-filed Test. 2
at 3-4, Tr.4 at 16-20. Consequently, IERG expresses the understanding that “the proposal is not
intended only to satisfy the federal requirement for having NO
x
RACT for ozone and PM
2.5
nonattainment areas, and avoid the imposition of sanctions, but is also intended to meet the new
13
federal standards for ozone and PM
2.5
. Further, IERG understands it is intended to satisfy the
corresponding new RACT requirements.” PC 13 at 4. IERG claims that “having a NO
x
RACT
rule in place for future standards will enable industries operating in the nonattainment areas to
better plan for the future, knowing what will be required of them.”
Id
. at 2.
IERG states that it “is prepared to offer its support for the proposal, as it pertains to
satisfaction of the NO
x
RACT requirements for nonattainment areas for both the current and new
ozone and PM
2.5
standards, and to attainment of the new standards.” PC 13 at 9. IERG further
states that its “initial concerns, regarding the proposal as applied to the affected units in the
nonattainment areas, have by and large been addressed during the ongoing rulemaking process.”
Id.
at 1. However, IERG raises three issues with which it remains concerned: the averaging
provisions, the compliance date, and including types of units that are not located in the
nonattainment areas.
Id
. at 1, 9. The Board summarizes IERG’s comments on these three
concerns below. Noting the Agency’s motion for expedited review, which the Board granted on
April 2, 2009, IERG asks that the Board address these concerns in proceeding to first notice.
Id
.
at 1, 9.
Averaging Provisions
IERG states that it supports the concept of demonstrating compliance with the Agency’s
proposed rule through an emissions averaging plan. PC 13 at 5. IERG states that the proposed
Section 217.258(a) allows averaging for emission units subject to Subparts D, E, F, G, H, M, and
Q.
Id
.;
see
Prop. at 37, Statement at 27-29. IERG notes that Subpart Q, addressing stationary
internal combustion engines and turbines, also includes an averaging provision at Section
217.390. PC 13 at 5-6;
see
35 Ill. Adm. Code 217.390, Section 27 Proposed Rules for Nitrogen
Oxide (NO
x
) Emissions from Stationary Internal Combustion Engines and Turbines:
Amendments to 35 Ill. Adm. Code Parts 211 and 217, R07-19 (proposing amendments to
Subpart Q). IERG argues that “the averaging provisions of Sections 217.158 and 217.390 should
be substantively the same, and for clarity should be contained in Section 217.158 (Emission
Averaging Plan) of Subpart C (NO
x
General Requirements).” PC 13 at 6.
Based on its position in both R07-19 and in this proceeding, IERG requests that the
Board adopt specific emissions averaging language in Section 217.158(a)(1)(C): “[t]he new unit
or units must be used for the same purpose having substantially equivalent or less process
capacity, or the new unit or units must be permitted for less NO
x
emissions on an annual basis
than the actual NO
x
emissions of the unit or units that are replaced.” PC 13 at 6. Noting that the
Agency’s proposal allows new units to participate in averaging when they are “used for the same
purpose,” IERG suggests that its proposed language is clearer and will allow facilities the
flexibility to meet their operational needs, increase energy efficiency, and minimize emissions.”
Id
. IERG also argues that new units may be subject to programs such as New Source
Performance Standards and New Source Review, which would provide significant environmental
protection.
Id
., at 6-7.
IERG also argues “that a more appropriate baseline for limiting new units for use in an
averaging plan is January 1, 2010.” PC 13 at 7. IERG notes that the Agency’s proposed baseline
of commencing commercial operation on or before “January 1, 2002 was selected because it was
14
the base year for the inventory.”
Id
.;
see
Prop. at 37 (proposed Section 217.158(a)(1)(A)). IERG
expresses the understanding that the base year does not affect the strategy necessary to satisfy the
NO
x
RACT requirement. PC 13 at 7. IERG thus argues that “the date chosen as the cutoff for
emission averaging should allow the use of all the units that were constructed prior to the
existence of this proposed rule,” but could reasonably restrict the use of units constructed after
adoption of the rule.
Id
.
Compliance Date
Although noting that the Agency’s amended proposal includes a compliance date of
January 1, 2012, IERG continues to prefer a compliance date of January 1, 2014, “as it would
provide additional time for affected entities to plan and secure financing for any projects
necessitated by these amendments.” PC 13 at 7,
see
Tr.2 at 50, Mot. Amend at 3.
Types of Units Not in Nonattainment Areas
IERG states that it has questioned why the Agency’s proposal includes types of units that
are not now located in the nonattainment areas. PC 13 at 8, citing IERG Questions at 4, Tr.1 at
57-64. IERG notes Mr. Kaleel’s statement “that the units were included because the engineering
work and cost analysis for those units had been performed.”
Id
., citing Tr.1 at 62. IERG also
notes Mr. Kaleel’s statement that the proposed rule would provide guidance to those units if
nonattainment areas expanded to include them. PC 13 at 8, citing Tr.1 at 62. IERG stresses Mr.
Kaleel’s acknowledgement that such an expansion would require a future rulemaking. PC 13 at
8,
see
Tr.1 at 61.
IERG argues that these units should be removed from the present rulemaking proposal
and addressed in a future proposal in the event that additional regulation becomes necessary. PC
13 at 8. IERG further argues that “new units of these types, should they at some future point be
operated in the nonattainment area, would be subject to much more stringent new source
standards.”
Id
. Stressing that Part 217 would apply to such units only through a new
rulemaking, IERG argues that a future rulemaking is the proper mechanism to subject them to
those requirements.
Id.
Agency (PC 11)
The Agency states that, in the course of this rulemaking, it has negotiated a number of
issues with interested participants. PC 11 at 1. The Agency further states that those negotiations
culminated in the Agency’s January 30, 2009, motion to amend its proposal. The Agency notes
that, during the third hearing on February 3, 2009, representatives of both Midwest Generation
and Saint-Gobain expressed support for that motion.
Id.
; Tr.4 at 14-15, 130. The Board notes
that, in an order dated February 19, 2009, it granted the Agency’s motion to amend. In the
Matter of: Nitrogen Oxides Emissions from Various Source Categories: Amendments to 35 Ill.
Adm. Code Parts 211 and 217, R08-19, slip op. at 2 (Feb. 19, 2009).
The Agency reports that, since the third hearing, it “has continued to engage in
negotiations with interested parties on remaining unsolved issues.” PC 11 at 2. The Agency
15
further reports that “[s]uch negotiations have led to the further revision of certain provisions” and
the filing of a second Agency motion to amend its rulemaking proposal.
Id
. The Agency argues
that “the proposed amendments have addressed all substantive comments submitted during this
rulemaking” and requests that the Board proceed to first notice as expeditiously as possible.
Id
.,
citing 5 ILCS 100/1
et seq
. (2006) (Illinois Administrative Procedure Act).
The Board summarizes the Agency’s post-hearing comments in the following
subsections.
Finding of Illinois’ Failure to Make Required State Implementation Plan Submissions
The Agency states that USEPA has found that Illinois failed to make a RACT submission
required by the CAA for its two moderate nonattainment areas. PC 11 at 2-3, citing 74 Fed. Reg.
15416 (Mar. 24, 2008). The Agency further states that Illinois may face federal sanctions as
early as September 2009 if it does not submit all of the required elements of Illinois’ SIP as
required under Section 179(a) of the CAA and 40 CFR 52.31.
Id
. at 3-4. The Agency notes that,
to avoid imposition of these federal sanctions, it filed with the Board on March 19, 2009, a
motion for expedited review.
Id
. at 4-5. The Board notes that, in an order dated April 2, 2009, it
granted that motion. In the Matter of: Nitrogen Oxides Emissions from Various Source
Categories: Amendments to 35 Ill. Adm. Code Parts 211 and 217, R08-19, slip op. at 4 (Apr. 2,
2009).
Clean Air Act Requirements
The Agency states that, under Section 172(c)(1) of the CAA, “states with nonattainment
areas are required to submit, in part, SIPs that provide for the adoption of RACM for stationary
sources in all nonattainment areas as expeditiously as practicable.” PC 11 at 6, citing 42 U.S.C.
§ 7502(c)(1). The Agency characterizes RACT as a “subset” of RACM. PC 11 at 6. The
Agency states that RACT is defined as “the lowest emission limitation that a particular source
can meet by applying a control technique that is reasonably available considering technological
and economic feasibility.”
Id
., citing 44 Fed. Reg. 53762 (Sept. 17, 1979). The Agency claims
that, under Section 182(b)(2) of the CAA, states must adopt RACT rules for all areas designated
nonattainment for ozone and classified as moderate or above. PC 11 at 6, citing 42 U.S.C. §
7511a(b)(2). The Agency further claims that, “under Section 182(f) of the CAA, an overlapping
requirement in each state in which all or part of a ‘moderate’ area is located is the adoption of
RACT for major NO
x
sources.” PC 11 at 7-8, citing 42 U.S.C. § 7511a(f). The Agency
concludes that, taken together, these provisions “establish the requirements for Illinois to submit
NO
x
RACT regulations for all major stationary sources of NO
x
in PM
2.5
nonattainment areas and
ozone nonattainment areas classified as moderate and above.” PC 11 at 8, citing 72 Fed. Reg.
20586 (Apr. 25, 2007) (Clean Air Fine Particle Implementation Rule; Final Rule); 70 Fed. Reg.
71612 (Nov. 29, 2005) (Final Rule to Implement the 8-Hour Ozone National Ambient Air
Quality Standard; Final Rule).
Recent Developments Related to This Rulemaking
16
The Agency states that on March 9, 2009, it submitted to USEPA as required a
recommendation “that portions of the Chicago and Metro East metropolitan areas be designated
as nonattainment for the revised 8-hour ozone NAAQS.” PC 11 at 8. The Agency further states
that “CAA requirements regarding implementation of RACT in ozone nonattainment areas will
again be triggered for the areas so designated for the 2008 ozone standard.”
Id
.
The Agency notes that, on February 24, 2009, the United States Court of Appeals for the
District of Columbia remanded the annual air quality standard for fine particulate matter to
USEPA and ordered USEPA to reconsider both its primary and secondary standard for fine
particulate matter. PC 11 at 9, citing Am. Farm Bureau Fed’n. v. EPA, 2009 WL 437050 (D.C.
Cir. 2009). The Agency argues that current administration is likely to strengthen these standards.
PC 11 at 9. The Agency notes developments relating to review of CAIR and the consequences
for Illinois rulemaking that may ensue.
See id
. at 9-10. In addition, the Agency notes USEPA’s
2008 designation of nonattainment areas for the 24-hour PM
2.5
air quality standard established in
2006.
Id
. at 10. The Agency emphasizes that it has requested that USEPA amend those
designations based on 2008 monitoring data.
Id
. at 10-11.
The Agency “acknowledges that recent developments regarding the ozone and PM
2.5
NAAQS provide a complicated landscape for addressing regulatory requirements.” PC 11 at 11.
The Agency notes that these standards have become tighter and expects that “they will be
tightened further.”
Id
. The Agency argues that “Illinois must therefore continue to seek
reasonable emission reduction measures to address the NAAQS, which in the Illinois EPA’s
opinion, argues strongly for the adoption of this proposal.”
Id
.
Discussions with Interested Participants
IERG.
The Agency notes IERG’s position that the Agency’s proposal “is too stringent
to be considered RACT, is not reasonable or cost effective, and that the rule may not be
necessary.” PC 11 at 11-12. The Agency also notes IERG’s suggestions that Illinois rely instead
on existing CAIR and NO
x
SIP Call rules for EGUs and non-EGUs to satisfy the RACT
requirement.
Id
. at 12. The Agency expresses strong disagreement with IERG’s position.
Id
.
Regarding the stringency and reasonableness of its proposal, the Agency argues that it
has provided extensive support for the technical and economic feasibility of its proposed
emissions limits. PC 11 at 12-14;
see generally
TSD. The Agency further argues that it has
addressed the concerns of regulated entities by proposing to extend compliance deadlines. PC 11
at 12;
see
Mot. Amend 1 at 2.
Regarding the necessity of its proposal, the Agency does not agree that Illinois can rely
on a federal trading program to meet local nonattainment area requirements. PC 11 at 15. The
Agency argues that “[t]he United States Court of Appeals, in its decision on the CAIR rule
clearly indicated that a regional trading program should not be relied upon to address local
nonattainment problems, and nonattainment problems due to transport between adjoining states.
Id
, citing North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). The Agency further argues that
“[t]he court determined that CAIR is not adequate and remanded CAIR to USEPA.” PC 11 at
17
15. The Agency surmises that, in revising CAIR, USEPA is not likely to address local
nonattainment problems through a trading program.
Id
.
The Agency also asserts that the NO
x
SIP Call rules are an insufficient substitute for the
NO
x
RACT requirements. PC 11 at 16-17. The Agency points to a pending case in which the
Natural Resources Defense Council challenges USEPA’s waiver of RACT requirements for all
sources covered by the NOx SIP Call. PC # 11 at 15-16, citing NRDC v. EPA, No. 06-1045,
2007 WL 836786 (D.C. Cir.). Next, the Agency argues that “[t]he NO
x
SIP call, as adopted in
Subpart U of Part 217, does not adequately address major NO
x
emission sources in Illinois’
nonattainment areas.” PC 11 at 16. Specifically, the Agency claims that the NOx SIP call only
addresses industrial boilers with a capacity greater than 250 mmBtu/hr. PC 11 at 16.
The Agency also emphasizes that the implementation of NO
x
RACT is crucial to air
quality, as NO
x
is a precursor to the formation of both ozone and PM
2.5
. PC 11 at 17. The
Agency also argues that the implementation of NO
x
RACT in Illinois is crucial to improving
ozone conditions in downwind states, particularly in western Michigan.
Id
. at 17-18. Further,
the Agency argues that, once USEPA finalizes designations under the more stringent 2008 ozone
standards, the Chicago and Metro-East areas in Illinois will likely be designated as
nonattainment.
Id
. at 18. The Agency also expects that the Metro-East area will be designated
as non-attainment under the 2006 standards for PM
2.5
.
Id
. at 18-19. Also, the Agency claims
that Illinois will likely face more stringent PM
2.5
standards in the future. PC 11 at 19, citing Am.
Farm Bureau Fed’n. v. EPA, 2009 WL 437050 (D.C. Cir. 2009) (remanding USEPA decision to
maintain annual PM
2.5
standard). The Agency argues that a more stringent emission standard
means that Illinois will require control measures to reduce emissions of precursors such as NO
x
.
PC 11 at 19.
Finally, the Agency does not concur in IERG’s request to omit emission standards for
cement kilns and aluminum melting furnaces, neither of which currently operates in
nonattainment areas. PC 11 at 19. Although the Agency concedes that new source standards are
generally more stringent than RACT, it also states that new source applicants frequently seek
alternatives to those requirements.
Id
. at 20. The Agency also argues that units may seek to
relocate in the nonattainment areas, and that the proposed standards “will provide a floor for
future emission sources that may seek to locate in these areas.”
Id
.
ArcelorMittal.
The Agency states that it proposes to amend the NO
x
emission limit for
recuperative reheat furnaces to respond to comments from ArcelorMittal and U.S. Steel,
although it notes that ArcelorMittal has not agreed to the proposed amendment. PC 11 at 20.
The Agency disagrees with ArcelorMittal’s position that the proposal should not apply to
ArcelorMittal’s Riverdale facility because the facility is not a reheat furnace.
Id
. The Agency
also argues that a specific definition of “reheat furnace” in the rules is not necessary, because
ArcelorMittal’s description of the furnace is consistent with the description provided in the TSD.
Id
. at 20-21, citing TSD at 93.
The Agency also claims that, despite the “tunnel” design of ArcelorMittal’s reheat
furnace, ULNBs can be used at the Riverdale facility. PC 11 at 21. The Agency also concludes
that ArcelorMittal’s current technology is not an “advanced NOx control technology.”
Id
.
18
Nonetheless, based on “a survey of NO
x
emission limits for similar furnaces constructed in other
states in recent years,” the Agency states that it proposes to amend the emission limit for
recuperative reheat furnaces burning natural gas from 0.05 lb/mmBtu to 0.09 lb/mmBtu.
Id
.
ConocoPhillips.
First, on the issue of replacement units in averaging plans, the Agency
agrees with ConocoPhillips that a single heater, BEU-HM3, should be considered a “replacement
heater” for its BEU-HM1 and BUE-HM2 heaters, which are scheduled to be shut down in 2009.
PC 11 at 21-22. The Agency agrees that “the replacement heater is used for the same purpose
and has a substantially equivalent process capacity of the units that are being replaced.”
Id
. at
22. Second, the Agency expresses agreement that the proposed definition of the term “process
heater” does not include ConocoPhillips’ Steam Methane Reformer (SMR) located at its Wood
River Refinery.
Id
. The Agency agrees that the SMR does not “indirectly transfer heat to a
process fluid or a heat transfer medium other than water.”
Id
. Third, responding to
ConocoPhillips’ arguments regarding the cost of installing CEMS on all affected units would be
more costly than necessary, the Agency proposed to allow predictive emission monitoring
system as an alternative to CEMS.
Id
.
United States Steel Corporation.
The Agency states that “[a]n ancillary benefit of U.S.
Steel’s coke oven gas desulfurization unit is that in addition to removing sulfur compounds from
the coke oven gas, it also removes hydrogen cyanide, which reduces fuel NO
x
in coke oven gas.”
PC 11 at 23. The Agency states that U.S. Steel has provided 130 parts per million as “its best
estimate as to the level of hydrogen cyanide that remains in the coke oven gas after the coke
oven gas passes through the desulfurization unit.”
Id
. The Agency states that it derived
specified emissions limits from this estimate and that its second motion to amend the proposal
includes language addressing U.S. Steel.
Id
. US Steel and the IEPA recognize the possibility
that future rulemaking may be necessary to adjust emissions limits.
Id
.
DISCUSSION OF UNRESOLVED ISSUES
In both the first and second motions to amend its rulemaking proposal, the Agency
indicates that it has negotiated with interested participants and agreed to revise certain provisions
in order to memorialize agreements with them.
See generally
Mot. Amend 1 at 1-2, Mot. Amend
2 at 1-5. These amendments address most of the issues raised by the participants during the
hearing process. However, post-hearing comments demonstrate that the Agency has not reached
agreements on all issues raised in the course of this proceeding. The Board will briefly discuss
the unresolved issues in the following sections. The Board then provides a detailed section-by-
section discussion of the proposed rules following the Board’s findings on economic
reasonableness and technical feasibility.
Unit Types Not in Nonattainment Areas
IERG questions why the Agency’s proposal includes types of units that are not now
located in the nonattainment areas. PC 13 at 8, citing IERG Questions at 4, Tr.1 at 57-64. IERG
argues that these units should instead be addressed in a future rulemaking proposal in the event
that additional regulation becomes necessary. PC 13 at 8;
see also
Exh. 6 at 19-24 (Kolaz
testimony).
19
The Agency has not concurred with IERG’s request to omit these emission standards. PC
11 at 19. The Agency argues that the proposed rule would guide those units if nonattainment
areas expand to include them. PC 13 at 8, citing Tr.1 at 62. The Agency also argues that,
although new source standards are generally more stringent than RACT, new source applicants
frequently seek alternatives to those standards.
Id
. at 19-20. The Agency claims that emission
units may seek to relocate in the nonattainment areas and that the proposed standards “will
provide a floor for future emission sources that may seek to locate in these areas.”
Id
.
The Board agrees with the Agency that the proposed emission standards provide an
alternative to the new source standards and serve as benchmark for future emission sources that
may be located in the nonattainment areas. The Board will proceed to first notice below with the
Agency’s proposal, as amended by the Agency’s two motions to amend, including provisions
relating to cement kilns and aluminum furnaces.
CEMS Threshold
ConocoPhillips notes that the Agency’s proposal requires boilers and process heaters
over 100 MMBtu/hr to use CEMS to monitor and record NO
x
emissions. PC 14 at 2, PC 5 at 5;
see
Prop. at 32-33. ConocoPhillips estimates that installation of CEMS at its Wood River
refinery would cost approximately $12.6 million. Exh. 9 at 14-15 (Dunn testimony), PC 14 at 3.
While ConocoPhillips agrees with the Agency’s proposal to extend the deadline for installation
of CEMS, it argues that “CEMS should be limited to those units greater than 250 MMBtu/hr.”
Exh. 9 at 15;
see
Motion Amend 1 at 5, Mot. Amend 2 at 7-8.
The Board notes that the Agency has not sought to amend the proposed Section 217.157
to raise the threshold for installing CEMS.
See
Mot. Amend 1, Mot. Amend 2. However, the
Agency proposed to amend Section 217.157 to allow the use of predictive emission monitoring
system (PEMS) as an alternative to CEMS for owners or operators of certain emission units who
are not otherwise required by any other statute, regulation or enforceable order to install CEMS
on an emission unit. The Board believes that the proposed alternative monitoring requirements
address ConocoPhillips’ concerns. The Board will proceed to first notice below with the
Agency’s proposal, as amended by the two motions to amend.
Replacement Units
In its post-hearing comments, IERG expresses support for the concept of an emissions
averaging plan but offers alternative language regarding the inclusion of replacement units in
such plans. Exh. 13 at 5-6;
see
Prop. at 37 (proposed subsection 217.158(a)(1)(C)). IERG also
proposes that “a more appropriate baseline for limiting new units for use in an averaging plan is
January 1, 2010.”
Id
. at 7;
see
ExxonMobil Answers at 5-6.
The Board notes that the second motion to amend the Agency’s proposal seeks to add to
the proposed Section 217.158(a)(1)(C) language similar to that offered by IERG in its post-
hearing comment.
See
Mot. Amend 2 at 8-9. The Board believes that the Agency’s proposed
20
amendment reflects changes proposed by IERG. Therefore, the Board will proceed to first notice
below with the Agency’s proposal, as amended by the two motions to amend.
Case-by-Case RACT Determination
ConocoPhillips argues that it requires flexibility when, in planning and implementing
controls, it discovers that the cost of NO
x
removal “significantly exceeds reasonably available
control technology.” PC 14 at 3. ConocoPhillips claims that, in making such a discovery
regarding costs, “it must have the ability to present a revised control strategy to the Agency
and/or the Board.”
Id
. Conoco Phillips states that it will provide proposed language for
consideration and welcomes the Agency’s comments.
Id
.;
see also
PC 10 at 10 (ArcelorMittal
post-hearing comment regarding case-by-case determination of applicability). However,
particularly in the absence of that proposal and any Agency comment on it, the Board will
proceed to first notice below with the Agency’s proposal, as amended by the two motions to
amend.
Emission Limits
In its post-hearing comment, IERG restates its position that “the originally proposed
emission limits are more stringent than is necessary to satisfy the requirement to have NO
x
RACT in place in nonattainment areas for the current ozone and PM
2.5
standards.” PC 13 at 4.
IERG reproduces alternative emission limits that it had originally proposed in testimony on the
part of Mr. Kolaz.
Id.
at 5, citing Exh. 6 (Exh.1);
see also
PC 11 at 11-15 (Agency support for
limitations). The Board notes that the Agency provides a detailed explanation as to why the
Agency’s proposal is RACT for NO
x
and why it is not appropriate to rely upon existing CAIR
and NO
x
SIP Call rules for EGUs and non-EGUs, as argued by IERG, to meet the RACT
requirement. PC 11 at 11-20. Further, the proposed amendments address IERG’s concerns
regarding the proposed compliance time requirements by delaying the compliance deadlines for
most emission units until January 1, 2012.
In addition, as noted by IERG, the Agency states that the proposed NO
x
RACT rule may
be likely satisfy the NO
x
RACT requirement for the new ozone and PM
2.5
standards and help in
attainment of the those standards. As noted below, the Board finds that the proposed emission
limits are technically feasible and economically reasonable. Therefore, the Board agrees with
the Agency that the proposed emission limits are RACT for NO
x
. The Board will proceed to first
notice below with the Agency’s proposal, as amended by the two motions to amend.
ECONOMIC REASONABLENESS AND TECHNICAL FEASIBILTY
The Board notes that the Agency has negotiated with interested participants and agreed to
revise certain provisions in order to memorialize agreements with them.
See generally
Mot.
Amend 1 at 1-2, Mot. Amend 2 at 1-5. These amendments have addressed issues including, but
not limited to, compliance deadlines, deadlines for installing CEMS, and emission limitations.
Id
. Having granted the Agency’s two motions to amend the proposal, and having reviewed the
record in this proceeding, the Board finds that the Agency’s proposal, as amended, is
technologically feasible and economically reasonable.
21
The Board proceeds below with its section-by-section discussion of its first-notice
proposal.
SUMMARY OF BOARD’S FIRST-NOTICE PROPOSAL
Part 211: Definitions and General Provisions
The Agency proposes to add twelve new definitions to the existing Part 211. Statement
at 13;
see
Prop. at 13-15;
see generally
35 Ill. Adm. Code 211. The Board summarizes each of
the proposed new definitions below.
Section 211.665: Auxiliary Boiler
In its proposal, the Agency seeks to add a definition of the term “auxiliary boiler,” which
is necessitated by the proposed Subparts C and D. Statement at 14. In its entirety, the proposed
definition states that “‘[a]uxiliary boiler’ means, for the purpose of Part 217, a boiler that is
operated only when the main boiler or boilers at a source are not in service and is used either to
maintain building heat or to assist in the startup of the main boiler or boilers. This term does not
include emergency or standby units and load shaving units.” Prop. at 13 (proposed new Section
211.665).
Section 211.995: Circulating Fluidized Bed Combustor
In its proposal, the Agency seeks to add a definition of the term “circulating fluidized bed
combustor,” which is necessitated by the proposed Subpart D. Statement at 14. In its entirety,
the proposed definition states that “‘[c]irculating fluidized bed combustor’ means, for purposes
of Part 217, a fluidized bed combustor in which the majority of the fluidized bed material is
carried out of the primary combustion zone and is transported back to the primary zone through a
recirculation loop.” Prop. at 14 (proposed new Section 211.995).
Section 211.1315: Combustion Tuning
In its proposal, the Agency seeks to add a definition of the term “combustion tuning,”
which is necessitated by Subparts D and E. Statement at 14. In its entirety, the proposed
definition states that “‘[c]ombustion tuning’ means, for purposes of Subpart 217, review and
adjustment of a combustion process to maintain combustion efficiency of an emission unit, as
performed in accordance with procedures provided by the manufacturer or by a trained
technician.” Prop. at 14 (proposed new Section 211.1315).
Section 211.1435: Container Glass
In its proposal the Agency seeks to add a definition of the term “container glass,” which
is necessitated by Subpart F. Statement at 14. In its entirety, the proposed definition states that
“‘[c]ontainer glass’ means, for purposes of Part 217, glass made of soda-lime recipe, clear or
22
colored, which is pressed or blown, or both, into bottles, jars, ampoules, and other products listed
in Standard Industrial Classification 3221.” Prop. at 14 (proposed new Section 211.1435).
Section 211.2355: Flare
In its proposal, the Agency seeks to add a definition of the term “flare.” Prop. at 14. The
Agency states that the proposed definition is necessary “because flares are not subject to the NO
x
general requirements under Subpart C.”
Id
. In its entirety, the proposed definition states that
“‘[f]lare’ means an open combustor without enclosure or shroud.” Prop. at 14 (proposed new
Section 211.2355).
Section 211.2357: Flat Glass
In its proposal, the Agency seeks to add a definition of the term “flat glass,” which is
necessitated by Subpart F. Statement at 14. In its entirety, the proposed definition states that
“‘[f]lat glass’ means, for purposes of Part 217, glass made of soda-lime recipe and produced into
continuous flat sheets and other products listed in Standard Industrial Classification 3211.”
Prop. at 14 (proposed new Section 211.2357).
Section 211.2625: Glass Melting Furnace
In its proposal, the Agency seeks to add a definition of the term “glass melting furnace,”
which is necessary for applicability under Subpart F. Statement at 14. In its entirety, the
proposed definition states that “‘[g]lass melting furnace’ means, for purposes of Part 217, a unit
comprising a refractory vessel in which raw materials are charged, melted at high temperature,
refined and conditioned to produce molten glass.” Prop. at 14-15 (proposed new Section
211.2625).
In its pre-hearing comment filed January 20, 2009, Saint-Gobain suggested amending this
proposed definition to state that “‘[g]lass melting furnace’ means, for purposes of Part 217, a unit
comprising a refractory vessel in which raw materials are charged and melted at high
temperature to produce molten glass.” PC 4 at 1. The Agency incorporated this
recommendation in its first motion to amend its proposal. Mot. Amend 1 at 2.
Section 211.3100: Industrial Boiler
In its proposal, the Agency seeks to add a definition of the term “industrial boiler,” which
is necessary for applicability under Subpart D. Statement at 15. In its entirety, the proposed
definition provides that
‘[i]ndustrial boiler’ means, for purposes of Part 217, an enclosed vessel in which
water is heated and circulated either as hot water or as steam for heating or for
power, or both. The term does not include boilers serving a generator that has a
nameplate capacity greater than 25 MWe and produces electricity for sale, and
cogeneration units, as that term is defined in Section 225.130 of Part 225, if such
23
boilers or cogeneration units are subject to the CAIR NO
x
Trading Programs
under Subpart D or E of Part 225. Prop. at 15 (proposed new Section 211.3100).
In a question filed for the first hearing on October 14, 2008, Midwest Generation
asked whether, in terms of definitions or use, the Agency intended in its proposed rule to
distinguish between industrial boilers, fossil fuel-fired boilers, and EGUs. MG Questions
at 1. In response, the Agency provided the following distinction: “EGU boilers are used
primarily to generate electricity to sell on the electricity grid. Industrial boilers are used
primarily to generate power (steam or electricity) for use at the source. Both types of
boilers may use fossil fuels, coal, oil, or gas.” MG Answers at 1.
In a question filed for the first hearing on October 14, 2008, IERG inquired
whether the Agency intended to include in the definition of “industrial boiler” either
“cogeneration units and/or heat recovery steam generators that capture waste heat from turbines
or engines.” IERG Questions at 4;
see
Prop. at 41-44 (proposed Subpart D). The Agency
responded simply “[y]es.” IERG Answers at 6. The Agency stated, however, that it had not
“performed any analysis to determine the technical feasibility and cost for cogeneration units
and/or heat recovery steam generators to comply with its proposed rule.”
Id.; see
Tr.1 at 66.
In another question filed for the first hearing on October 14, 2008, IERG inquired
whether the Agency intended to include in the definition of “industrial boiler” or “process
heater” those “gas-fired chillers that provide cooling for either processes or occupied spaces.”
IERG Questions at 4;
see
Prop. at 41-47 (proposed Subparts D and E). The Agency responded
by stating that, “[i]f refrigerant is heated [in]directly by gas heating, it is a process heater.”
IERG Answers at 6;
see infra
at 27 (addressing proposed definition of “process heater”);
see also
Tr.1 at 68-69 (clarifying Agency response). The Agency further stated that, although it had not
“performed any analysis to determine the technical feasibility and cost for such gas-fired chillers
to comply with its proposed rule,” it “believes that the technical feasibility and cost for gas-fired
chillers should be similar to process heaters and industrial boilers.” IERG Answers at 6-7,
see
Tr.1 at 67-68.
In a question filed for the first hearing on October 14, 2008, Midwest Generation first
stated that
[a]pplicability of Subpart M and the nonapplicability of Subpart D are premised
upon the applicability of the Part 225, Subparts C, D, and E (“the Illinois CAIR”)
to electric generating units (“EGUs”). However, the federal rule underlying the
Illinois CAIR has been overturned (assuming the D.C. Circuit Court issues the
mandate for its decision in appeal of the rule), thus invalidating the Illinois CAIR.
Therefore, it appears that EGUs, which the Agency apparently intended to cover
in Subpart M of this rulemaking, are covered by Subpart D. MG Questions at 2.
Midwest Generation then asked whether the Agency proposed to amend its language in Subpart
M. MG Answers at 2;
see
Prop. at 51-52 (proposed Subpart M). Although the Agency stated
that it disagreed “with the underlying premise of this question,” it indicated that it was
24
“amenable to amending” this definition of “industrial boiler” as described in response to a
subsequent question. MG Answers at 2;
see
Tr.1 at 190-92 (addressing status of federal rule).
In that subsequent question, Midwest Generation first stated that, “[b]ased upon the
proposed applicability language in Subpart M, Section 217.340, [and] assuming the D.C. Circuit
Court issues the mandate implementing its decision in the appeal of the CAIR, EGUs would be
subject to the provisions of Subpart D.” MG Questions at 3. Midwest Generation consequently
asked whether the Agency would consider amending its proposal to include the following
definition:
‘[i]ndustrial boiler’ means, for purposes of Part 217, an enclosed vessel in which
water is heated and circulated either as hot water or as steam for heating or for
power, or both. The term does not include boilers serving a generator that has a
nameplate capacity greater than 25 MWe and produces electricity for sale, and
cogeneration units, as that term is defined in Section 225.130 of Part 225, if such
boilers or cogeneration units are subject to the CAIR NO
x
Trading Programs
under Subpart D or E of Part 225.
Id
.
Responding to Midwest Generation, the Agency stated that it was “amenable” to amending its
proposed definition in the following fashion:
‘[i]ndustrial boiler’ means, for purposes of Part 217, an enclosed vessel in which
water is heated and circulated either as hot water or as steam for heating or for
power, or both. The term does not include boilers serving a generator that has a
nameplate capacity greater than 25 MWe and produces electricity for sale, and
cogeneration units, as that term is defined in Section 225.130 of Part 225, if such
boilers or cogeneration units are subject to
meet the applicability criteria under
Subpart M of Part 217the CAIR NO
x
Trading Programs under Subpart D or E of
Part 225. MG Answers at 4-6.
During the first hearing on October 14, 2008, IERG posed the following question to the
Agency:
[i]f a heat recovery steam generator recovering heat from the exhaust of, A,
process, B, turbine, or C, engine, is considered a boiler for proposed – for this
proposed rule, then does the Agency intend to define the boiler’s rated heat input
capacity as a direct heat input to the heat recovery steam generator from
combustion of fuel in the heat recovery steam generator – for example, from a
duct burner – or does it intend to also include the heat input from the upstream
process in the rated capacity? Tr.1 at 65.
Responding in writing to this question, the Agency first stated that it had reviewed USEPA
regulations regarding turbines from which exhaust is captured in a heat recovery steam
generator. PC 1 at 1, citing 40 C.F.R. 60, Subparts GG, KKKK. The Agency stated that it had
decided “to treat a combustion turbine and heat recovery steam generator as a single unit.” PC 1
25
at 1. The Agency claims that this simplifies testing and monitoring NO
x
emissions.
Id
. The
Agency elaborated that
[t]he supplemental heat input of the duct burner/heat recovery steam generator
will be added to the heat input of the turbine. The combined heat input will be
subject to the applicable NO
x
emission limit for turbines under Subpart Q of Part
217. Therefore, the NO
x
emissions will be tested/monitored after the exhaust
from the heat recovery steam generator and shall comply with the NO
x
emission
limit for a turbine. However, the heat input of the duct burner/heat recovery
steam generator shall not be added to the heat input of the turbine to increase the
rated capacity of the turbine.
Id.
at 1-2.
The Agency accordingly proposed to amend the definition of “industrial boiler” by, among other
change, excluding “a heat recovery steam generator that captures waste heat from a combustion
turbine. . . . “
Id
. at 2.
In its first motion to amend its rulemaking proposal, the Agency recommended that the
Board “[a]mend Section 217.3100 by to reflect the provisions as previously agreed to between
the Illinois EPA and Midwest Generation as reflected in the Illinois EPA’s Answers to Midwest
Generation’s Questions for Agency Witnesses, filed September 30, 2008, and the October 14,
2008, hearing.” Mot. Amend 1 at 2;
see
MG Questions at 3, MG Answers at 4-6. In those
answers, the Agency had proposed to amend this definition to provide that
‘[i]ndustrial boiler’ means, for purposes of Part 217, an enclosed vessel in which
water is heated and circulated either as hot water or as steam for heating or for
power, or both. This term does not include boilers serving a generator that has a
nameplate capacity greater than 25MWe and produces electricity for sale, and
cogeneration units, as that term is defined in Section 225.120 of Part 225, if such
boilers or cogeneration units are subject to meet the applicability criteria under
Subpart M of Part 217 the CAIR NO
x
Trading Programs under Subpart D or E of
Part 225. MG Answers at 6;
but see
PC 1 at 2 (proposing to exclude from
definition heat recovery steam generators capturing waste heat from combustion
turbines).
In its post-hearing comments, Midwest Generation states that,
[w]ith the amendments proposed to the Board by the Agency in its Motion to
Amend Rulemaking Proposal ("Agency's Motion") filed January 30, 2009,
Midwest Generation generally supports the Agency's proposal as it applies to
electric generating units ("EGUs"). The proposed amendments incorporate by
reference provisions agreed to between the Agency and Midwest Generation as
part of the Agency's Answers to Midwest Generation's Questions for Agency
Witnesses ("Agency's Answers"), which were filed before this Board on
September 30, 2008. PC 9 at 1-2 (noting Agency’s amended proposed definition
of “industrial boiler”);
see
Mot. Amend 1 at 2;
see also
Tr.1 at 199-200.
26
In its second motion to amend its rulemaking proposal, the Agency recommended that the
Board accept the following amendment to this definition:
‘[i]ndustrial boiler’ means, for purposes of Part 217, an enclosed vessel in which
water is heated and circulated either as hot water or as steam for heating or for
power, or both. The term does not include a heat recovery steam generator that
captures waste heat from a combustion turbine and boilers serving a generator that
has a nameplate capacity greater than 25 MWe and produces electricity for sale, if
such boilers meet the applicability criteria under Subpart M of Part 217. Mot.
Amend 2 at 6.
The Agency states that this proposed amendment excludes from the definition “a heat recovery
steam generator that captures waste heat from a combustion turbine.” Mot. Amend 2 at 5. The
Agency further states that it proposed this amendment in post-hearing comments filed on
November 5, 2008, but inadvertently excluded it from the first motion to amend.
Id
. at 5, 6;
see
PC 1 at 1-2, citing Tr.1 at 65.
Section 211.3355: Lime Kiln
In its proposal, the Agency seeks to add a definition of the term “lime kiln,” which is
necessitated by Subpart G. Statement at 15. In its entirety, the proposed definition states that
“‘[l]ime kiln’ means, for purposes of Part 217, an enclosed combustion device used to calcine
lime mud, which consists primarily of calcium carbonate, into calcium oxide.” Prop. at 15
(proposed new Section 211.3355).
Section 211.3475: Load Shaving Unit
In its proposal, the Agency seeks to add a definition of the term “load shaving unit,”
which is included in the proposed definition of the term “auxiliary boiler.” Statement at 15. In
its entirety, the proposed definition states that “‘[l]oad shaving unit’ means, for purposes of Part
217, a device used to generate electricity for sale or use during high electric demand days,
including but not limited to stationary reciprocating internal combustion engines or turbines.”
Prop. at 15 (proposed new Section 211.3475).
In a question filed for the first hearing on October 14, 2008, Midwest Generation asked
the Agency whether the definition of “load shaving unit” includes a peaker power plant. MG
Questions at 2. The Agency responded simply “[y]es.” MG Answers at 2.
Section 211.4280: Other Glass
In its proposal, the Agency seeks to add a definition of the term “other glass,” which is
necessitated by Subpart F. Statement at 15. In its entirety, the proposed definition states that
“‘[o]ther glass’ means, for purposes of Part 217, glass that is neither container glass, as that term
is defined in Section 211.1435, nor flat glass, as that term is defined in Section 211.2357.” Prop.
at 15 (proposed new Section 211.4280).
27
Section 211.5195: Process Heater
In its proposal, the Agency seeks to add a definition of the term “process heater,” which
is necessitated by Subpart E. Statement at 15. In its entirety, the proposed definition states that
“‘[p]rocess heater’ means, for purposes of Part 217, an enclosed combustion device that burns
gaseous or liquid fuels only and that indirectly transfers heat to a process fluid or a heat transfer
medium other than water. This term does not include pipeline heaters and storage tank heaters
that are primarily meant to maintain fluids at a certain temperature or viscosity.” Prop. at 15-16
(proposed new Section 211.5195).
In a question filed for the first hearing on October 14, 2008, IERG inquired
whether the Agency intended to include in the definition of “industrial boiler” or “process
heater” those “gas-fired chillers that provide cooling for either processes or occupied spaces.”
IERG Questions at 4;
see
Prop. at 41-47 (proposed Subparts D and E). The Agency responded
by stating that, “[i]f refrigerant is heated [in]directly by gas heating, it is a process heater.”
IERG Answers at 6;
see
Tr.1 at 68-69 (clarifying Agency response). The Agency further stated
that, although it had not “performed any analysis to determine the technical feasibility and cost
for such gas-fired chillers to comply with its proposed rule,” it “believes that the technical
feasibility and cost for gas-fired chillers should be similar to process heaters and industrial
boilers.” IERG Answers at 6-7,
see
Tr.1 at 67-68.
Part 217: Nitrogen Oxides Emissions
Subpart A: General Provisions
Section 217.100: Scope and Organization.
Existing Section 217.100 sets forth the
scope and organization of Part 217. 35 Ill. Adm. Code 217.100. In its proposal, the Agency
seeks only to “amend subsection (b) of this Section to state that permits for sources subject to
Part 217 may be required under Section 39.5 of the Act, in addition to 35 Ill. Adm. Code Part
201.” Statement at 15;
see
Prop. at 22;
see also
415 ILCS 5/39.5 (2006) (Clean Air Act Permit
Program).
Section 217.104: Incorporations by Reference.
Existing Section 217.104 incorporates
by reference various specified materials. 35 Ill. Adm. Code 217.104. In its proposal, the Agency
seeks “to add test methods under 40 C.F.R. Part 60 and [USEPA] Alternative Control
Techniques Documents.” Statement at 16;
see
Prop. at 22-23.
Subpart B: New Fuel Combustion Emission Sources
Section 217.121: New Emission Sources.
Existing Section 217.121 addresses NO
x
emissions from new sources. 35 Ill. Adm. Code 217.121. In its proposal, the Agency seeks “to
repeal this Section.” Statement at 16;
see
Prop. at 23-24;
see also
Tr.1 at 187.
Subpart B: Existing Fuel Combustion Emission Units
28
Section 217.141: Existing Emission Units in Major Metropolitan Areas.
Section
217.141 now regulates existing emission sources in major metropolitan areas. 35 Ill. Adm. Code
217.141. The Agency’s proposal first seeks “to amend this Section by changing the term
‘source’ to ‘unit.’” Statement at 16;
see
Prop. at 25-26. The Agency also seeks to add language
in a new subsection (d)(2) providing “that the Section does not apply to emission units that are
subject to the emissions limitations of Subpart D, E, F, G, H, M, or Q of Part 217.” Statement at
16;
see
Prop. at 26.
During the first hearing on October 14, 2008, counsel for Midwest Generation questioned
whether Section 217.141 would be necessary if the Board adopts this proposed rule. Tr.1 at 189.
The Agency responded that the Board originally promulgated this language in 1972 as Rule 207
and applied it to both new and existing sources. PC 1 at 4, citing In the Matter of: Emissions
Standards, R71-23. The Agency states that
[t]he NO
x
limitations under Section 217.141 apply to any existing fuel
combustion emission source with an actual heat input equal to or greater than 73.2
MW (250 mmbtu/hr), located in the Chicago or St. Louis (Illinois) major
metropolitan areas. Currently, sources meeting the heat input criteria and located
in these areas are subject to these NO
x
limitations. Accordingly, these limitations
appear in sources’ permits. PC 1 at 4.
Subpart C: NO
x
General Requirements
Section 217.150: Applicability.
In its original proposal, the Agency sought to add a
new Section 217.150 addressing the applicability of the proposed Subparts C, D, E, F, G, H, and
M of Part 217. Statement at 16;
see
Prop. at 26-27.
The proposed subsection (a)(1) provides that Subparts D, E, F, G, H, and M apply to all
sources that are located in the two areas designated as nonattainment for the 8-hour ozone and
PM
2.5
standards and that emit or have the potential to emit NO
x
in an amount equal to or greater
than 100 tons per year. Statement at 10-11, 16;
see
Prop. at 26. The proposed subsection (a)(2)
provides that Subparts D, E, F, G, H, and M also “apply to any industrial boiler, process heater,
glass melting furnace, cement kiln, lime kiln, iron and steel reheat, annealing, or galvanizing
furnace, aluminum reverberatory or crucible furnace, or fossil fuel-fired stationary boiler at such
sources [described in subsection (a)(1)] that emits NO
x
in an amount equal to or greater than 15
tons per year and equal to or greater than five tons per ozone season.” Statement at 10-11, 16-
17;
see
Prop. at 26, Gupta Pre-filed Test. at 2.
Noting that the proposed regulations would apply to both existing and new units, the
Agency states that the existing units that would become subject to the regulations include the
following: “80 industrial boilers, 84 process heaters, four glass melting furnaces, two lime kilns,
six furnaces used in iron and steel making, and 20 fossil fuel-fired stationary boilers.” Statement
at 10;
see
TSD at 130-31 (describing affected sources). These 196 sources emitted 44,625 tons
of NO
x
in 2005, and the Agency projects that its proposal would reduce those emissions by
20,666 tons or 46.3%. TSD at 133 (Table 10-1), Gupta Pre-filed Test. at 3.
29
In a question filed for the first hearing on October 14, 2008, Midwest Generation noted
that the proposed subsection (a)(2) employs the term “emits” in determining applicability. MG
Questions at 1. Midwest Generation asked how the Agency would determine “whether a unit
emits, as opposed to having the potential to emit, at the threshold levels.”
Id
. The Agency
responded that, “[i]n general, the Illinois EPA intends to rely on Annual Emission Reports
submitted by owners/operators of emission sources.” MG Answers at 2;
see
Tr.1 at 184-86.
In the second motion to amend its rulemaking proposal, the Agency sought to add a new
subsection (a)(3) providing in its entirety that “[f]or purposes of this Section, ‘potential to emit’
means the quantity of NO
x
that potentially could be emitted by a stationary source before add-on
controls based on the design capacity or maximum production capacity of the source and 8,760
hours per year or the quantity of NO
x
that potentially could be emitted by a stationary source as
established in a federally enforceable permit.” Mot. Amend 2 at 6. The Agency states that it
added this definition in response to comments by USEPA.
Id
. at 2.
In another question filed for the first hearing, Midwest Generation noted that Section
217.150(a) provides that “[t]he provisions of this Subpart and Subparts D, E, F, G, H, and M
apply to . . . [a]ll sources. . . .” MG Questions at 2;
see
Prop. at 26. Midwest Generation asks
whether the Agency intends “that all of these subparts actually apply to all sources in the
specified geographic areas.” MG Questions at 2-3. Specifically, Midwest Generation asks
whether the Agency instead intends “that only one subpart will apply to a unit or units at
threshold sources, as determined by the characteristics of the unit.”
Id
. at 3. The Agency
responds by stating that its “intent that each respective Subpart apply to sources that meet the
applicability criteria and individual emission units at such sources that meet the applicability
criteria,
i.e.
, the provisions of a respective Subpart apply to the extent a source includes emission
units of the type covered under the Subpart.” MG Answers at 3.
In another question filed for the first hearing, Midwest Generation claims that “[t]he ‘all
industrial boilers’ language in Section 217.160(a) and similar language in the other subparts
could be construed to expand the scope of Section 217.150(a)(2), which refers to ‘any industrial
boiler [and other types of emission units] that emits NO
x
in an amount equal to or greater than 15
tons per year and equal to or greater than five tons per ozone season.” MG Questions at 2;
see
Prop. at 41-42 (proposed Section 217.160(a)). Midwest Generation questions whether the
Agency intends “to expand the applicability of the rule in this way.” MG Questions at 2. The
Agency responds by expressing the intent “that each Subpart apply to all of the affected emission
units at an affected source,
e.g.
, ‘any’ emission unit that meets the applicability criteria.” MG
Answers at 3.
The Agency also proposes a new subsection (b) providing that, if a source ceases to fulfill
the emissions criteria of subsection (a) of this Section, the requirements of Subparts D, E, F, G,
H, or M of Part 217 continue to apply to any emission unit that was ever subject to the provisions
of Subpart D, E, F, G, H, or M of Part 217. Statement at 17;
see
Prop. at 26. The proposed
subsection (c) provides that “the provisions of Subpart C do not apply to afterburners, flares, and
incinerators.” Statement at 17;
see
Prop. at 27.
In addition, the Agency’s proposed subsection (d) provides that,
30
where a construction permit, for which the application was submitted to the
Agency prior to the adoption of Subpart C, is issued that relies on decreases in
emissions of NO
x
from existing emission units for purposes of netting or emission
offsets, such NO
x
decreases remain creditable notwithstanding any requirements
that may apply to the existing emission units pursuant to Subpart C and Subpart
D, E, F, G, H, or M of Part 217. Statement at 17;
see
Prop. at 27.
In the first motion to amend its rulemaking proposal, the Agency sought to add a
subsection (e) providing in its entirety that “[t]he owner or operator of an emission unit that is
subject to the Subpart or Subpart D, E, F, G, H, or M of this Part must operate such unit in a
manner consistent with good air pollution control practice to minimize NO
x
emissions.” Mot.
Amend 1 at 3. The Agency had originally included this language in the proposed subsection
217.152(b) regarding the compliance date. Prop. at 27;
see
Tr.1 at 196-98 (suggesting relocation
under applicability provisions).
Section 217.152: Compliance Date.
The Agency seeks to add a new section regarding
the compliance date for its proposed rule. Statement at 17;
see
Prop. at 27. The proposed
subsection (a) originally provided “that compliance with the requirements of Subparts D, E, F, G,
H, and M by an owner or operator of an emission unit that it subject to any one of those subparts
is required beginning May 1, 2010.” Statement at 17;
see
Prop. at 27.
Proposed subsection (b) originally provided “that the first annual compliance period is
May 1, 2010, through April 30, 2011, and then on a calendar years basis thereafter.” Statement
at 17;
see
Prop. at 27. Subsection (b) also originally provided that “the owner or operator of an
emission unit that is subject to Subpart D, E, F, G, H, or M must operate such unit in a manner
consistent with good air pollution control practice to minimize NO
x
emissions.” Statement at 17;
see
Prop. at 27.
In a question filed for the first hearing on October 14, 2008, Midwest Generation asked
how the second sentence of subsection (b), regarding air pollution control practices, relates to the
proposed compliance date. MG Questions at 3. Responding, the Agency simply stated that
“[t]here is no relation.” MG Answers at 3;
see
Tr.1 at 196-98 (suggesting relocation under
applicability provisions). In post-hearing comments, the Agency agreed “that it may be more
appropriate to place this sentence in another section. . . . PC 1 at 4.
In comments filed for the second hearing beginning December 9, 2008, Saint-Gobain
argued that “a narrow exception should be made to the May 1, 2010 compliance date for entities
that enter into an enforceable agreement with IEPA to install control technology that can achieve
NO
x
emission rates significantly below the 5.0 lbs/ton limit pursuant to an enforceable schedule
extending beyond 2010.” PC 4 at 1. Saint-Gobain states that it “is currently in the process of
negotiating such an agreement with IEPA.
Id
. Saint-Gobain specifically proposed that Section
217.152 include a new subsection providing in its entirety that,
[n]otwithstanding subsections (a), (b), and (c) of this Section, compliance with the
requirements of Subpart F of this Part by an owner or operator of an emission unit
31
subject to Subpart F of this Part shall be extended until December 31, 2014, if
such units are required to meet emissions limitations for NO
x
, as measured using a
continuous emissions monitoring system, and included within a legally
enforceable order on or before December 31, 2009, whereby such emissions
limitations are less than 30 percent of the emissions limitations set forth under
Section 217.204 of Subpart F of this Part.
Id
. at 2.
Saint-Gobain supports its proposal by stating that it
cannot afford to install the technology required to meet an interim limit of 5.0
lbs/ton for the period between the compliance date under Section 217.204 and the
anticipated schedule for installation of the alternative technology at the end of
2014, and thus the opportunity for substantially greater long-term emission
reductions may be lost if a limited exemption from the May 1, 2010 compliance
date is not adopted.
Id
. at 1.
Saint-Gobain also argues that early installation of CEMS would require significantly greater
expense than later installation with the alternative technology and “would serve no compliance
purpose.”
Id
. at 2.
Participants doubted that sources could achieve compliance by the Agency’s proposed
compliance deadline and proposed alternative compliance schedules.
E.g.
, Exh. 5 at 15-16
(IERG). Exh. 6 at 12-15 (IERG), Exh. 9 at 3-6 (ConocoPhillips), Exh. 10 at 7-8 (U.S. Steel). In
the first motion to amend its rulemaking proposal, the Agency proposed to amend subsection (a)
to provide in its entirety that “[c]ompliance with the requirements of Subparts D, E, F, G, H, and
M by an owner or operator of an emission unit that is subject to Subpart D, E, F, G, H, or M is
required beginning January 1, 2012.” Mot. Amend 1 at 2, 3.
The first motion to amend also sought to amend subsection (b) to provide in its entirety
that
[n]otwithstanding subsections (a) of this Section, compliance with the
requirements of Subpart F of this Part by an owner or operator of an emission unit
subject to Subpart F of this Part shall be extended until December 31, 2014, if
such units are required to meet emissions limitations for NO
x
, as measured using a
continuous emissions monitoring system, and included within a legally
enforceable order on or before December 31, 2009, whereby such emissions
limitations are less than 30 percent of the emissions limitations set forth under
Section 217.204 of Subpart F of this Part. Mot. Amend 2 at 2, 3.
In the second motion to amend its proposal, the Agency sought to add a subsection (c)
providing in its entirety that,
[n]otwithstanding subsection (a) of this Section, the owner or operator of emission
units subject to Subpart D or E of this Part and located at a petroleum refinery
must comply with the requirements of this Subpart and Subpart D or E of this
32
Part, as applicable, for those emission units beginning January 1, 2012, except
that the owner or operator of emission units listed in Appendix H must comply
with the requirements of this Subpart, including the option of demonstrating
compliance with the applicable Subpart through an emissions averaging plan
under Section 217.158 of this Subpart, and Subpart D or E of this Part, as
applicable, for the listed emission units beginning on the dates set forth in
Appendix H. With Agency approval, the owner or operator of emission units
listed in Appendix H may elect to comply with the requirements of this Subpart
and Subpart D or E of this Part, as applicable, by reducing the emissions of
emission units other than those listed in Appendix H, provided that the emissions
limitations of such other emission units are equal to or more stringent than the
applicable emissions limitations set forth in Subpart D or E of this Part, as
applicable, by the dates set forth in Appendix H. Mot. Amend 2 at 2, 6-7;
see
Mot. Amend 2 at 13-14 (proposed Appendix H).
Section 217.154: Performance Testing.
The Agency seeks to add a new section
regarding performance testing requirements for units subject to Subparts D, E, F, G, or H.
Statement at 18-19;
see
Prop. at 27-28. The proposed subsection (a) provides “that such testing
for emission units constructed on or before December 1, 2009, and subject to one of those
subparts must be conducted in accordance with Section 217.157.” Statement at 18;
see
Prop. at
27. Subsection (a) also provides an exception from this requirement for owners and operators
demonstrating compliance through CEMS. Statement at 18;
see
Prop. at 27.
Proposed subsection (b) provides that “performance testing of NO
x
emissions for
emission units constructed or modified after December 1, 2009, and subject to one of those
subparts must be conducted within 60 days of achieving maximum operating rate but no later
than 180 days after initial startup of the new or modified emission units, in accordance with
Section 217.157.” Statement at 18;
see
Prop. at 27. Subsection (b) also provides an exception
for owners and operators demonstrating compliance through CEMS. Statement at 18;
see
Prop.
at 28.
In a question filed for the first hearing on October 14, 2008, IERG noted that subsection
(a) and (b) “refer to the date of emission unit construction or modification” and asked the
Agency to clarify the meaning of the terms “constructed on or before” and “construction or
modification occurs after.” IERG Questions at 16-17. Specifically, IERG asked whether the
Agency refers to “the beginning of construction, the completion of construction, [or] the date of
issuance of a construction permit?”
Id
.
In its response, the Agency first noted that definition in Parts 201 and 211 apply to Part
217. IERG Answers at 9;
see
35 Ill. Adm. Code 201, 211, 217.103. The Agency further noted
that Section 201.102 defines “construction” as “commencement of on-site fabrication, erection
or installation of an emission source or of air pollution control equipment.” IERG Answers at 9,
citing 35 Ill. Adm. Code 201.102. The Agency also notes that it defines “modification” as
any physical change in, or change in the method of operations, of an emission
source or of air pollution control equipment which increases the amount of any
33
specified air contaminant emitted by such source or equipment or which results in
the emission of any specified air contaminant not previously emitted. It shall be
presumed that an increase in the use of raw materials, the time of operation or the
rate of production will change the amount of any specified air contaminant
emitted. Notwithstanding any other provisions of this definition, for purposes of
permits issued pursuant to Subpart D, the Illinois Environmental Agency
(Agency) may specify conditions under which an emission source or air pollution
control equipment may be operated without causing a modification as herein
defined, and normal cyclical variations, before the date operating permits are
required, shall not be considered modifications. IERG Answers at 9, citing 35 Ill.
Adm. Code 201.102.
The Agency suggests that these definitions determine what constitutes the beginning or the
completion of construction. IERG Answers at 9.
In the first motion to amend its proposal, the Agency sought to replace subsection (a)
with the following language:
[p]erformance testing of NO
x
emissions for emission units constructed on or
before July 1, 2011, and subject to Subpart D, E, F, G, or H of this Part must be
conducted in accordance with Section 217.157 of this Subpart. This subsection
does not apply to owners and operators of emission units demonstrating
compliance through a continuous emissions monitoring system. Mot. Amend 1 at
3.
Also in the first motion to amend, the Agency sought to replace subsection (b)
with the following language:
[p]erformance testing of NO
x
emissions for emission units for which construction
or modification occurs after July1, 2011, and that are subject to Subpart D, E, F,
G, or H of this Part must be conducted within 60 days of achieving maximum
operating rate but no later than 180 days after initial startup of the new or
modified emission unit, in accordance with Section 217.157 of this Subpart. This
subsection does not apply to owners and operators of emission units
demonstrating compliance through a continuous emissions monitoring system.
Mot. Amend 1 at 3.
Proposed subsection (c) provides that notification of initial startup of a unit subject to
subsection (b) “must be provided to the Agency no later than 30 days after initial startup.”
Statement at 18;
see
Prop. at 28. Proposed subsection (d) provides that the owner or operator of
a unit subject to subsection (a) or (b) “must notify the Agency of the scheduled date for the
performance testing at least 30 days in writing before such date and five days before such date.”
Statement at 18;
see
Prop. at 28.
Proposed subsection (e) provides that, “if demonstrating compliance through a emissions
averaging plan, at least 30 days before changing the method of compliance, the owner or
34
operator of an emission unit must submit a written notification to the Agency describing the new
method of compliance, the reason for the change in the method of compliance, and the scheduled
date for the compliance demonstration testing, if required.” Statement at 18-19;
see
Prop. at 28.
Subsection (e) also provides that an owner or operator changing the method of compliance “must
submit to the Agency a revised compliance certification that meets the requirements of Section
217.155.” Statement at 19;
see
Prop. at 28.
Section 217.155: Initial Compliance Certification.
The Agency seeks to add a new
section regarding initial compliance certification for units subject to Subpart D, E, F, G, H, or M.
Statement at 19-20:
see
Prop. at 28-29. As originally proposed, subsection (a) provides that, by
May 1, 2010, the owner or operator of a unit subject to Subpart D, E, F, G, H, or M who does not
demonstrate compliance with CEMS “must certify to the Agency that the emission unit will be in
compliance with the applicable emissions limitation of Subpart D, E, F, G, or H of Part 217
beginning May 1, 2010.” Statement at 19;
see
Prop. at 28. The subsection also provides that
“certification must include the results of the performance testing performed in accordance with
Sections 217.154(a) and (b) of Subpart C and the calculations necessary to demonstrate that the
subject emission unit will be in initial compliance.” Statement at 19;
see
Prop. at 28.
In the first motion to amend its rulemaking proposal, the Agency sought to replace
subsection (a) with the following language:
[b]y the applicable compliance date set forth under Section 217.152 of this
Subpart, an owner or operator of an emission unit subject to Subpart D, E, F, G,
or H of this Part who is not demonstrating compliance through the use of a
continuous emissions monitoring system must certify to the Agency that the
emission unit will be in compliance with the applicable emissions limitation of
Subpart D, E, F, G, or H of this Part beginning on such applicable compliance
date. The performance testing certification must include the results of the
performance testing performed in accordance with Sections 217.154(a) and (b) of
this Subpart and the calculations necessary to demonstrate that the subject
emission unit will be in initial compliance. Mot. Amend 1 at 4.
As originally proposed, subsection (b) provides that, by May 1, 2010, the owner or
operator of a unit subject to Subpart D, E, F, G, H, or M who is demonstrating compliance with
CEMS “must certify to the Agency that the affected emission units will be in compliance with
the applicable emissions limitation of Subpart D, E, F, G, or H of Part 217 beginning May 1,
2010.” Statement at 19;
see
Prop. at 28. The subsection also provides that “[s]uch compliance
certification must include a certification of the installation and operation of a continuous
emissions monitoring system required under Sections 217.157 of Subpart C and the monitoring
data necessary to demonstrate that the subject emission unit will be in initial compliance.”
Statement at 19-20;
see
Prop. at 28-29.
In the first motion to amend its rulemaking proposal, the Agency sought to replace
subsection (b) with the following language:
35
By the applicable compliance date set forth under Section 217.152 of this Subpart,
an owner or operator of an emission unit subject to Subpart D, E, F, G, H, or M of
this Part who is demonstrating compliance through the use of a continuous
emissions monitoring system must certify to the Agency that the affected
emission units will be in compliance with the applicable emissions limitation of
Subpart D, E, F, G, H, or M of this Part beginning on such applicable compliance
date. The compliance certification must include a certification of the installation
and operation of a continuous emissions monitoring system required under
Section 217.157 of this Subpart and the monitoring data necessary to demonstrate
that the subject emission unit will be in initial compliance. Mot. Amend 1 at 4;
see also
PC 2 at 1 (proposing extension of compliance deadline for CEMS).
Section 217.156: Recordkeeping and Reporting.
The Agency seeks to add a new
section regarding recordkeeping and reporting by owners or operators of sources subject to
Subpart D, E, F, G, H, or M. Statement at 20-23:
see
Prop. at 29-32. The proposed subsection
(a) provides that such owners or operators “must keep and maintain all records used to
demonstrate initial compliance and ongoing compliance with the requirements of these
Subparts.” Statement at 20;
see
Prop. at 29. The subsection also provides that, “except as
otherwise provided under those Subparts, copies of such records must be submitted by the owner
or operator of the source to the Agency within 30 days after receipt of a written request by the
Agency, and such records must be kept at the source and maintained for at least five years and
must be available for inspection and copying by the Agency.” Statement at 20;
see
Prop. at 29
(proposed subsections (a)(1) and (a)(2)).
Proposed subsection (b) provides that the owner or operator of a unit subject to Subpart
D, E, F, G, H, or M must maintain records, including eleven specific items, demonstrating
compliance with the applicable subpart. Statement at 20-21;
see
Prop. at 29-30. Specifically,
subsection (b)(8) requires that records include “[a] log of all maintenance and inspections related
to the unit’s air pollution control equipment for NO
x
that it performed on the unit.” Prop. at 30;
see
Statement at 20-21. Also, subsection (b)(9) requires that records include “[a] log for the NO
x
monitoring device, if present, including periods when not in service and maintenance and
inspection activities that are performed on the device.” Prop. at 30;
see
Statement at 21.
In a question filed for the first hearing on October 14, 2008, Midwest Generation asked
whether “the recordkeeping systems that sources already have in place comprise the ‘logs’
required at Sections 217.156(b)(8) and (9), assuming all of the information required by the rule is
included?” MG Questions at 2. The Agency responded that they do comprise the required logs,
“as long as all of the required information under the rule is included.” MG Answers at 3.
Proposed subsection (c) provides in its entirety that “[t]he owner or operator of an
industrial boiler subject to Subpart D of this Part must maintain records in order to demonstrate
compliance with the combustion tuning requirements under Section 217.166 of this Part.” Prop.
at 30;
see
Statement at 21. Proposed subsection (d) provides in its entirety that “[t]he owner or
operator of a process heater subject to Subpart E of this Part must maintain records in order to
demonstrate compliance with the combustion tuning requirements under Section 217.186 of this
Part.” Prop. at 30;
see
Statement at 21. Proposed subsection (e) provides in its entirety that
36
“[t]he owner or operator of an emission unit subject to Subpart D, E, F, G, H, or M of this Part
must maintain records in order to demonstrate compliance with the testing and monitoring
requirements under Section 217.157 of this Subpart.” Prop. at 30;
see
Statement at 21.
Proposed subsection (f) provides that an owner or operator of a unit subject to Subparts
D, E, F, G, or H must provide four specific submissions with respect to performance testing
under Section 217.157(a)(4) and (b)(2). Prop. at 30-31;
see
Statement at 21-22. In the second
motion to amend its rulemaking proposal, the Agency sought to amend subsection (f) to provide
that recordkeeping and reporting, as they pertain to performance testing, applies “to all
performance testing conducted under Section 217.157 and not just certain testing as under the
original proposal.” Mot. Amend 2 at 2;
see
Prop. at 30-31.
Proposed subsection (g) provides that “the owner or operator of an emission unit subject
to Subpart D, E, F, G, H, or M must notify the Agency of any exceedances of an applicable
emissions limitation of Subpart D, E, F, G, H, or M by sending the applicable report with an
explanation of the causes of such exceedances to the Agency within 30 days following the end of
the applicable compliance period in which the emissions limitation was not met.” Statement at
22;
see
Prop. at 31. In a question filed for the first hearing on October 14, 2008, Midwest
Generation asked what constitutes the “applicable compliance period.” MG Questions at 2. The
Agency responded that that period is “[t]he annual or ozone season compliance period.” MG
Answers at 3.
Proposed subsection (h) provides that, “within 30 days of a written request by the
Agency, the owner or operator of an emission unit that is exempt from the requirements of
Subpart D, E, F, G, H, or M must submit records that document that the emission unit is exempt
from those requirements to the Agency.” Statement at 22;
see
Prop. at 31. Proposed subsection
(i) provides that an owner or operator complying through an emissions averaging plan must
submit by March 1 following the applicable calendar year a report demonstrating four specific
items. Prop. at 31;
see
Statement at 22. Proposed subsection (j) provides that an owner or
operator complying through the use of CEMS must submit to the Agency within 30 days after
the end of each calendar quarter a report including two specified items of information. Prop. at
32;
see
Statement at 23.
Proposed subsection (k) provides that “the owner or operator of an emission unit subject
to Subpart M must comply with the compliance certification and recordkeeping and reporting
requirements in accordance with 40 C.F.R. 96, or an alternate procedure approved by the Agency
and USEPA.” Statement at 23;
see
Prop. at 32. In a question filed for the first hearing on
October 14, 2008, Midwest Generation asked whether subsection (k) “supersede[s] the other
recordkeeping and reporting requirements of Section 217.156?” MG Questions at 2.
Responding, the Agency stated that its “intent is that electric generating units subject to Subpart
M comply with the compliance certifications, recordkeeping, and reporting requirements
pursuant to 40 C.F.R. 96, in conjunction with the other recordkeeping and reporting requirements
under Section 217.156, to the extent the requirements are not duplicative.” MG Answers at 4.
Section 217.157: Testing and Monitoring.
The Agency seeks to add a new section
regarding testing and monitoring by owners or operators of sources subject to Subpart D, E, F, G,
37
H, or M. Statement at 20-27:
see
Prop. at 32-37. The proposed subsection (a) “includes the
provisions applicable to owners and operators of industrial boilers subject to Subpart D and
process heaters subject to Subpart E.” Statement at 23;
see
Prop. at 32-34.
Proposed subsection (a)(1) provides that “the owner or operator of an industrial boiler
subject to Subpart D with a rated heat input capacity greater than 250 mmBtu/hr must install,
calibrate, maintain, and operate a continuous emissions monitoring system on the emission unit
for the measurement of NO
x
emissions discharged into the atmosphere in accordance with 40
C.F.R. Part 75.” Statement at 23;
see
Prop. at 32.
Proposed subsection (a)(2) provides that
the owner or operator of an industrial boiler subject to Subpart D with a rated heat
input capacity greater than 100 mmBtu/hr but less than or equal to 250 mmBtu/hr
must install, calibrate, maintain, and operate a continuous emissions monitoring
system on the emission unit for the measurement of NO
x
emissions discharged
into the atmosphere in accordance with 40 C.F.R. Part 60, Subpart A, and
Appendix B, Performance Specifications 2 and 3, and Appendix F, Quality
Assurance Procedures. Statement at 24;
see
Prop. at 32-33.
Proposed subsection (a)(3) provides that
the owner or operator of a process heater subject to Subpart E with a rated heat
input capacity greater than 100 mmBtu/hr must install, calibrate, maintain, and
operate a continuous emissions monitoring system on the emission unit for the
measurement of NO
x
emissions discharged into the atmosphere in accordance
with 40 C.F.R. Part 60, Subpart A, and Appendix B, Performance Specifications 2
and 3, and Appendix F, Quality Assurance Procedures. Statement at 24;
see
Prop.
at 33.
In testimony filed on behalf of ConocoPhillips for the second hearing on December 9,
2008, Mr. Dunn noted that the Agency’s proposal requiring installation of CEMS on any
industrial boiler or process heater over 100 mmBtu/hr would result in total estimated costs of
$12 million. Exh. 9 a t 14-15. Mr. Dunn recommended that the Agency limit CEMS
requirements to units greater than 250 mmBtu/hr.
Id
. at 15. He also expressed the view that
“annual performance testing is sufficient for process heaters that are included in an averaging
plan.”
Id
. In post-hearing comments, ConocoPhillips noted that these issues remain
outstanding concerns with the Agency. PC 14 at 2-3.
Proposed subsection (a)(4) provides that, “if demonstrating compliance through an
emissions averaging plan, the owner or operator of an industrial boiler subject to Subpart D, or a
process heater subject to Subpart E, with a rated heat input capacity less than or equal to 100
mmBtu/hr and not demonstrating compliance through a continuous emission monitoring system
must have an initial performance test.” Statement at 24;
see
Prop. at 33. Proposed subsection
(a)(4)(A) establishes the timing for the required subsequent performance tests. Statement at 24;
see
Prop. at 33. Proposed subsection (a)(4)(B) originally established other requirements for
38
these tests. Statement at 24;
see
Prop. at 33-34. In the first motion to amend its rulemaking
proposal, the Agency proposed to replace that language with the following:
[t]he owner or operator of an industrial boiler or process heater must have a
performance test conducted using 40 CFR Part 60, Subpart A, and Appendix A,
Method 1, 2, 3, 4, 7E, or 19, as incorporated by reference in Section 217.104 of
this Part, or other alternative USEPA methods approved by the Agency. Each
performance test must consist of three separate runs, each lasting a minimum of
60 minutes. NO
x
emissions must be measured while the industrial boiler is
operating at maximum operating capacity or while the process heater is operating
at normal maximum load. If the industrial boiler or process heater has combusted
more than one type of fuel in the prior year, a separate performance test is
required for each fuel. If a combination of fuels is typically used, a performance
test may be conducted with Agency approval on such combination of fuels
typically used. Except as provided under subsection (e) of this Section, this
subsection (a)(4)(B) of this Section does not apply if such owner or operator is
demonstrating compliance with an emissions limitation through a continuous
emissions monitoring system under subsection (a)(1), (a)(2), (a)(3), or (a)(5)) of
this Section. Mot. Amend 1 at 4-5.
Proposed subsection (a)(5) provides that, instead of complying with subsection (a)(4),
(a)(4)(A), and (a)(4)(B), “an owner or operator of an industrial boiler subject to Subpart D of this
Part, or a process heater subject to Subpart E of this Part, with a rated heat input capacity less
than or equal to 100 mmBtu/hr may install and operate a continuous emissions monitoring
system that meets the applicable requirements of 40 C.F.R. Part 60, Subpart A, and Appendix B,
Performance Specifications 2 and 3, and Appendix F, Quality Assurance Procedures.” Statement
at 25;
see
Prop. at 34. The proposed subsection further provides that the CEMS “must be used to
demonstrate compliance with the applicable emissions limitation or emissions averaging plan on
an ozone season and annual basis.” Statement at 25;
see
Prop. at 34.
Proposed subsection (a)(6) provides that, notwithstanding subsection (a)(2), the owner or
operator of an auxiliary boiler subject to Subpart D “with a rated heat input capacity less than or
equal to 250 mmBtu/hr and a capacity factor of less than or equal to 20% is not required to
install, calibrate, maintain, and operate a continuous emissions monitoring system on such boiler
for the measurement of NO
x
emissions discharged into the atmosphere, but must comply with the
performance test requirements under subsections (a)(4), (a)(4)(A), and (a)(4)(B) of this Section.”
Statement at 25;
see
Prop; at 34.
The proposed subsection (b) includes provisions applicable to owners and operators of
glass melting furnaces subject to Subpart F, cement and lime kilns subject to Subpart G, iron and
steel reheat, annealing, or galvanizing furnaces subject to Subpart H, and aluminum
reverberatory and crucible furnaces subject to Subpart H. Statement at 25;
see
Prop. at 34.
Proposed subsection (b)(1) provides that
an owner or operator of such an emission unit that has the potential to emit NO
x
in
an amount equal to or greater than one ton per day must install, calibrate,
39
maintain, and operate a continuous emissions monitoring system on each such
emission unit for the measurement of NO
x
emissions discharged into the
atmosphere in accordance with 40 C.F.R. Part 60, Subpart A, and Appendix B,
Performance Specifications 2 and 3, and Appendix F, Quality Assurance
Procedures. Statement at 25-26;
see
Prop. at 34-35.
Proposed subsection (b)(2) provides that “an owner or operator of a glass melting
furnace, cement kiln or lime kiln, iron and steel reheat, annealing, or galvanizing furnace, or
aluminum reverberatory and crucible furnace that has the potential to emit NO
x
in an amount less
than one ton per day must have an initial performance test conducted” pursuant to subsection
(b)(4) and Section 217.154. Statement at 26;
see
Prop. at 35. Proposed subsection (b)(3)
establishes the timing for the required subsequent performance tests. Statement at 26;
see
Prop.
at 35.
Proposed subsection (b)(4) originally established methods and requirements for those
performance tests. Statement at 26;
see
Prop. at 36. In comments filed on January 20, 2009,
Saint-Gobain proposed to amend that language by adding a sentence providing that, if a unit
demonstrates compliance with NO
x
limitations by CEMS under subsection (b)(1), then this
subsection (b)(4) does not apply. PC 4 at 1. In the first motion to amend its rulemaking
proposal, the Agency proposed to replace that language with the following:
The owner or operator of a glass melting furnace, cement kiln, or lime kiln must
have a performance test conducted using 40 CFR Part 60, Subpart A, and
Appendix A, Methods 1. 2, 3, 4, and 7E, as incorporated by reference in Section
217.104 of this Part, or other alternative USEPA methods approved by the
Agency. The owner or operator of an iron and steel reheat, annealing, or
galvanizing furnace, or aluminum reverberatory or crucible furnace must have a
performance test conducted using 40 CFR Part 60, Subpart A, and Appendix A,
Method 1, 2, 3, 4, 7E, or 19, as incorporated by reference in Section 217.104 of
this Part, or other alternative USEPA methods approved by the Agency. Each
performance test must consist of three separate runs, each lasting a minimum of
60 minutes. NO
x
emissions must be measured while the glass melting furnace,
cement kiln, lime kiln, iron and steel reheat, annealing, or galvanizing furnace, or
aluminum reverberatory or crucible furnace is operating at maximum operating
capacity. If the glass melting furnace, cement kiln, lime kiln, iron and steel
reheat, annealing, or galvanizing furnace, or aluminum reverberatory or crucible
furnace has combusted more than one type of fuel in the prior year, a separate
performance test is required for each fuel. Except as provided under subsection
(e) of this Section, this subsection (b)(4) of this Section does not apply if such
owner or operator is demonstrating compliance with an emissions limitation
through a continuous emissions monitoring system under subsection (b)(1) or
(b)(5) of this Section. Mot. Amend 1 at 5;
see infra
at 41 (noting proposed
addition of subsection (e));
see also
PC 4 at 1 (Saint-Gobain pre-hearing
proposal).
40
Proposed subsection (b)(5) provides that, instead of complying with subsections (b)(2),
(b)(3), and (b)(4),
an owner or operator of a glass melting furnace, cement kiln or lime kiln, iron and
steel reheat, annealing, or galvanizing furnace, or aluminum reverberatory and
crucible furnace that has the potential to emit NO
x
in an amount less than one ton
per day may install and operate a continuous emissions operating system on such
emission unit that meets the applicable requirements of 40 C.F.R. Part 60, Subpart
A, and Appendix B, Performance Specifications 2 and 3, and Appendix F, Quality
Assurance Procedures. Statement at 26;
see
Prop. at 36.
The proposed subsection also provides that the CEMS “must be used to demonstrate compliance
with the applicable emissions limitation or emissions averaging plan on an ozone season and
annual basis.” Statement at 26;
see
Prop. at 36.
Proposed subsection (c) provides in its entirety that “[t]he owner or operator of a fossil
fuel-fired stationary boiler subject to Subpart M of this Part must install, calibrate, maintain, and
operate a continuous emissions monitoring system on such emission unit for the measurement of
NO
x
emissions discharged into the atmosphere in accordance with 40 C.F.R. Part 96, Subpart
H.” Prop. at 36;
see
Statement at 27.
Proposed subsection (d) provides in its entirety that,
[i]f two or more emission units subject to Subpart D, E, F, G, H, M, or Q of this
Part are served by a common stack and the owner or operator of such emission
units is operating a continuous emissions monitoring system, the owner or
operator may, with written approval from the Agency, utilize a single continuous
emissions monitoring system for the combination of emission units subject to
Subpart D, E, F, G, H, M, or Q of this Part that share the common stack, provided
such emission units are subject to an emissions averaging plan under this Part.
Prop. at 37;
see
Statement at 27.
In the first motion to amend its rulemaking proposal, the Agency proposed to add a
subsection (e) to extend the deadline for the installation of CEMS. Mot. Amend 1 at 5;
see
Exh.
6 at 21 (urging additional time for installation), Exh. 9 (supporting three-year extension for
installation). In the second motion to amend, the Agency proposed to amend subsection (e) to
allow additional time for installation of CEMS. Mot. Amend 2 at 2, 7-8. The Agency also
proposed to add a subsection (f) allowing “for a predictive emission monitoring system, in
accordance with 40 C.F.R. Part 60, Subpart A, and Appendix B, Performance Specification 16,
as an alternative to the CEMS requirements for the owners or operators of certain emission units
who are not otherwise required by any other statute, regulation, or enforceable order to install a
CEMS on an emission unit.” Mot. Amend 2 at 2-3, 7-8.
Section 217.158: Emissions Averaging Plans.
The Agency seeks to add a new section
regarding emissions averaging plans. Statement at 27-29:
see
Prop. at 37-41. Generally,
“[s]ources may aggregate and then average the NO
x
emissions from units at the same location in
41
Illinois to comply with the emissions limitations. . . .” Kaleel Pre-filed Test. at 3. Specifically,
proposed subsection (a) provides that, “[n]otwithstanding any other emissions averaging plan
provisions under this Part, an owner or operator of a source with certain emission units subject to
Subpart D, E, F, G, H, or M of this Part, or subject to Subpart Q of this Part that are located in
either one of the areas set forth under Section 217.150(a)(1)(A) or (B) of this Subpart, may
demonstrate compliance with the applicable Subpart through an emissions averaging plan.”
Prop. at 37;
see
Statement at 27.
The proposed subsection also provides that “[a]n emissions averaging plan can only
address emission units that are located at one source and each unit may only be covered by one
emissions averaging plan.” Prop. at 37;
see
Statement at 27, Tr.1 at 180. In a question filed for
the first hearing on October 14, 2008, Midwest Generation asked whether the Agency intended
to preclude “a unit that is in an averaging plan under this rule from participating in averaging
plans under other rules and
vice versa.
” MG Questions at 1. The Agency responded that it
intends “that an emission unit be included in only one seasonal and one annual averaging plan.
Units affected by Subpart Q (Engine Rule) can be included in an averaging plan with units
affected by this proposal.” MG Answers at 2;
see
Tr.1 at 181. Finally, the proposed subsection
also provides that “[s]uch emission units at the source are affected units and are subject to the
requirements of this Section.” Prop. at 37;
see
Statement at 27.
Proposed subsection (a)(1) describes units that may be included in an emissions
averaging plan. Statement at 27;
see
Prop. at 37. First, under subsection (a)(1)(A), a plan may
include “[u]nits that commenced operation on or before January 1, 2002.” Prop. at 37;
see
Statement at 27. In a question filed for the first hearing on October 14, 2008, ExxonMobil asked
how the Agency set that date as a cutoff. ExxonMobil Questions at 4-5;
see
IERG Questions at
4. The Agency responded that “USEPA has established 2002 as the base year for planning
purposes for implementation of the ozone and PM
2.5
NAAQS established in 1997. States are
required to demonstrate continued progress towards attainment beginning in that year. The
Illinois EPA is seeking emission reductions from emission units that were in existence in 2002.”
ExxonMobil Answers at 5. The Agency acknowledged that new units may, under various
requirements, “have installed NO
x
control measures that are equal to or more stringent than the
proposed emission limitations here.”
Id
. at 6. The Agency states, however, that “[i]f such units
were included in an averaging plan with units that existed in 2002, then the existing units may
not need to reduce emissions. This is counter to the objective of achieving Reasonable Further
Progress between 2002 and the attainment year, 2010.
Id
.;
see
IERG Answers at 8.
Under proposed subsection (a)(1)(B), a plan may include “[u]nits that the owner or
operator may claim as exempt under Subpart D, E, F, G, H, or M, as applicable, but does not
claim as exempt.” Statement at 27-28;
see
Prop. at 37. The proposed subsection also provides
that, “[f]or 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 emissions limitations, and testing, monitoring,
recordkeeping, and reporting requirements.” Prop. at 37.
Under proposed subsection (a)(1)(C), a plan may include “[u]nits that commence
operation after January 1, 2002, if the unit replaces a unit that commenced operation on or before
January 1, 2002, or it replaces a unit that replaced a unit that commenced operation on or before
42
January 1, 2002. The new unit must be used for the same purpose as the replacement unit.”
Prop. at 37;
see
Statement at 28. In response to a question by IERG filed for the first hearing, the
Agency stated that, “[f]or the purpose of emissions averaging under this proposal, a replacement
unit must be
essentially
the same as the unit it replaces.” IERG Answers at 8 (emphasis added);
see
Tr.1 at 80-83. In the second motion to amend its rulemaking proposal, the Agency proposed
to replace its original language with a new subsection (a)(1)(C) clarifying the replacement units
that may be included in an averaging plan. The Agency explained that
[t]he new unit must be used for the same purpose and have substantially
equivalent or less process capacity or be permitted for less NO
x
emissions on an
annual basis than the actual NO
x
emissions of the unit or units that are replaced.
In addition, within 90 days after permanently shutting down a unit that is
replaced, the owner or operator of such unit must submit a written request to
withdraw or amend the applicable permit to reflect that the unit is no longer in
service before the replacement unit may be included in the emissions averaging
plan” Mot. Amend 2 at 3, 8-9.
Proposed subsection (a)(2) describes units that may not be included in an emissions
averaging plan. Statement at 27;
see
Prop. at 37. First, under proposed subsection (a)(2)(A), a
plan may not include “[u]nits that commence operation after January 1, 2002, except as provided
by subsection (a)(1)(C) of this Section.” Prop. at 38;
see
Statement at 28,
supra
(discussing
subsection (a)(1)(C)). Under proposed subsection (a)(2)(B), a plan may not include “[u]nits that
the owner or operator is claiming are exempt pursuant to Section 217.162, 217.182, 217.202,
217.222, 217.242, or 217.432 of this Part, as applicable.” Prop. at 38;
see
Statement at 28. Also,
under proposed subsection (a)(2)(C), the Agency originally proposed that plans may not include
“[u]nits that are required to meet emission limits for NO
x
as provided for in an enforceable order,
unless such order specifically provides for operation pursuant to an emissions averaging plan.”
Prop. at 28;
see
Statement at 28. In the second motion to amend its rulemaking proposal, the
Agency proposed to amend this subsection to provide that plans may not include
Units that are required to meet emission limits or control requirements for NO
x
as provided for in an enforceable order, unless such order allows for emissions
averaging. Nothing in this subparagraph (C) is intended to prohibit a petroleum
refinery from including industrial boilers or process heaters, or both, in an
emissions averaging plan where an enforceable order does not prohibit the
reductions made under such order from also being used for compliance with any
rules or regulations designed to address regional haze or the non-attainment
status of any area. Mot. Amend 2 at 3, 9.
Proposed subsection (b) provides that
an owner or operator must submit an emissions averaging plan to the Agency by
May 1, 2010, and such plan must include, but is not limited to, the list of affected
units included in the plan by unit identification number and a sample calculation
demonstrating compliance using the methodology provided in subsection (f) of
43
this Section for the ozone season (May 1 through September 30) and calendar
year (January 1 through December 31). Statement at 28;
see
Prop. at 38.
In the first motion to amend its rulemaking proposal, the Agency sought to extend the deadline to
submit an averaging plan to the Agency to January 1, 2012. Mot. Amend 1 at 6. In a question
filed for the first hearing on October 14, 2008, Midwest Generation asked whether a source may
decide after the deadline for submitting a plan that it wishes to perform averaging. MG
Questions at 3. The Agency responded that “[a]veraging plans can be amended once per year at
the discretion of the owner/operator.” MG Answers at 4. The Agency elaborated that a unit that
had not submitted an averaging plan before the initial deadline can be included in averaging at a
later date.
Id
.
Subsection (c), as originally proposed by the Agency, provided in its entirety that “[a]n
owner or operator may amend an emission plan only once per calendar year. Such 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.” Prop. at 38;
see
Statement at 28. In the
first motion to amend its rulemaking proposal, the Agency proposed to amend this subsection by
changing the May 1 submission deadlines to January 1. Mot. Amend 1 at 6.
Proposed subsection (d) provides that, notwithstanding subsection (c),
if a unit that is listed in an emissions averaging plan is taken out of service, the
owner or operator must submit to the Agency, within 30 days of such occurrence,
an updated emissions averaging plan; or if a unit that is exempt from the
requirements of Subpart D, E, F, G, H, or M, as applicable, no longer qualifies for
an exemption, the owner or operator may amend its existing averaging plan to
include such unit within 30 days of the unit no longer qualifying for the
exemption. Statement at 28-29;
see
Prop. at 38-39.
Proposed subsection (e) provides that the owner or operator must demonstrate
compliance for both the ozone season and the calendar year by using the methodology and the
units included in the most recent averaging plan submitted to the Agency, “the higher of the
monitoring data or test data determined pursuant to Section 217.157,” and “the actual hours of
operation for the applicable averaging plan period.” Statement at 29;
see
Prop. at 39. The
subsection also provides that the owner or operator must “submit to the Agency by March 1
following each calendar year, a compliance report containing the information required by
Section 217.156(i).” Statement at 29;
see
Prop. at 39.
Proposed subsection (f) “provides that 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.”
Statement at 29;
see
Prop. at 39. The proposed subsection also includes the equation with which
to determine compliance. Prop. at 39-41.
Proposed subsection (g) provides that
44
the owner or operator of an emission unit subject to Subpart Q of this Part that is
located in either one of the areas set forth under Section 217.150(a)(1)(A) or (B)
of this Subpart that is complying through an emissions averaging plan under this
Section must comply with the applicable provisions for determining actual and
allowable emissions under Section 217.290 of Subpart Q, the testing and
monitoring requirements under Section 217.394 of Subpart Q, and the
recordkeeping and reporting requirements under Section 217.396 of Subpart Q.
Statement at 29;
see
Prop. at 41.
In the second motion to amend its rulemaking proposal, the Agency sought to add a
subsection (h). Mot. Amend 2 at 3-4, 9. That proposed new subsection provides in its entirety
that
[t]he owner or operator of an emission unit located at a petroleum refinery who is
demonstrating compliance with an applicable Subpart through an emissions
averaging plan under this Section may exclude from the calculation demonstrating
compliance those time periods when an emission unit included in the emissions
averaging plan is shut down for a maintenance turnaround, provided that such
owner or operator notify the Agency in writing at least 30 days in advance of the
shutdown of the emission unit for the maintenance turnaround and the shutdown
of the emission unit does not exceed 45 days per ozone season or calendar year
and NO
x
pollution control equipment, if any, continues to operate on all other
emission units operating during the maintenance turnaround. Mot. Amend 2 at 9.
Also in the second motion to amend its rulemaking proposal, the Agency sought to add a
subsection (i). Mot. Amend 2 at 4, 9. That proposed new subsection provides in its entirety that
[t]he owner or operator of an emission unit that combusts a combination of coke
oven gas and other gaseous fuels and located at a source that manufactures iron
and steel who is demonstrating compliance with an applicable Subpart through
an emissions averaging plan under this Section may exclude from the calculation
demonstrating compliance those time periods when the coke oven gas
desulfurization unit included in the emissions averaging plan is shut down for
maintenance, provided that such owner or operator notify the Agency in writing
at least 30 days in advance of the shutdown of the coke oven gas desulfurization
unit for maintenance and such shutdown does not exceed 35 days per ozone
season or calendar year and NO
x
pollution control equipment, if any, continues
to operate on all other emission units operating during the maintenance period.
Mot. Amend 2 at 9.
Subpart D: Industrial Boilers
Section 217.160: Applicability.
The Agency seeks to add a new section addressing
applicability of its proposal to industrial boilers. Prop. at 41-42. Proposed subsection (a)
provides that “the provisions of Subparts C and D apply to all industrial boilers located at
45
sources subject to Subpart D pursuant to Section 217.150.” Statement at 30;
see
Prop. at 42;
see
also supra
at 28-30 (addressing applicability of general requirements). The Agency states that
there are 12 industrial boilers subject to the NO
x
SIP Call affected by this proposal and an
additional 68 industrial boilers less than 250 mmBtu that are not subject to the NO
x
SIP Call.
TSD at 130, Statement at 10;
see
MG Answers at 8.
In a question filed for the first hearing on October 14, 2008, Midwest Generation claims
that “[t]he ‘all industrial boilers’ language in Section 217.160(a) and similar language in the
other subparts could be construed to expand the scope of Section 217.150(a)(2), which refers to
‘any industrial boiler [and other types of emission units] that emits NO
x
in an amount equal to or
greater than 15 tons per year and equal to or greater than five tons per ozone season.” MG
Questions at 2;
see
Prop. at 41-42. Midwest Generation questions whether the Agency intends
“to expand the applicability of the rule in this way.” MG Questions at 2. The Agency responds
by expressing the intent “that each Subpart apply to all of the affected emission units at an
affected source,
e.g.
, ‘any’ emission unit that meets the applicability criteria.” MG Answers at 3.
Proposed subsection (b) provides that “the provisions of Subpart D do not apply to
boilers serving a generator that has a nameplate capacity of 25 MWe or less and produces
electricity for sale, and cogeneration units, as that term is defined in Section 225.130 of Part 225,
if such boilers or cogeneration units are subject to the CAIR NO
x
Trading Programs under
Subpart D or E of Part 225.” Statement at 30;
see
Prop. at 42.
In a question filed for the first hearing on October 14, 2008, Midwest Generation stated
that, “[b]ased upon the proposed applicability language in Subpart M, Section 217.340, [and]
assuming the D.C. Circuit Court issues the mandate implementing its decision in the appeal of
the CAIR, EGUs would be subject to the provisions of Subpart D.” MG Questions at 3-4.
Midwest Generation consequently asked whether the Agency would consider amending
subsection (b) as follows: “[t]he provisions of this Subpart do not apply to boilers serving a
generator that has a nameplate capacity greater than 25 MWe and produces electricity for sale,
and cogeneration units, as that term is defined in Section 225.230 of Part 225, if such boilers or
cogeneration units are subject to the CAIR NO
x
Trading Programs under Subpart D or E of Part
225.”
Id.
at 4.
Responding to Midwest Generation, the Agency stated that it was “amenable” to
amending its proposed definition in the following fashion: “[t]he provisions of this Subpart do
not apply to boilers serving a generator that has a nameplate capacity greater than 25 MWe and
produces electricity for sale, and cogeneration units, as that term is defined in Section 225.130 of
Part 225, if such boilers or cogeneration units are subject to meet the applicability criteria under
Subpart M of Part 217 the CAIR NO
x
Trading Programs under Subpart D or E of Part 225. MG
Answers at 4-6.
In its first motion to amend its rulemaking proposal, the Agency recommended that the
Board “[a]mend Section 217.160 by amending subsection (b) to reflect the provisions as
previously agreed to between the Illinois EPA and Midwest Generation as reflected in the Illinois
EPA’s Answers to Midwest Generation’s Questions for Agency Witnesses, filed September 30,
46
2008, and the October 14, 2008, hearing.” Mot. Amend 1 at 6;
see
MG Question at 3-4, MG
Answers at 4-6.
In its post-hearing comments, Midwest Generation states that,
[w]ith the amendments proposed to the Board by the Agency in its Motion to
Amend Rulemaking Proposal ("Agency's Motion") filed January 30, 2009,
Midwest Generation generally supports the Agency's proposal as it applies to
electric generating units ("EGUs"). The proposed amendments incorporate by
reference provisions agreed to between the Agency and Midwest Generation as
part of the Agency's Answers to Midwest Generation's Questions for Agency
Witnesses ("Agency's Answers"), which were filed before this Board on
September 30, 2008. PC 9 at 1-2 (noting Agency’s proposed amendment of
Section 217.160);
see
Mot. Amend 1 at 6, Tr.1 at 199-200.
Proposed subsection (c) provides that “the provisions of Subpart D do not apply to
fluidized catalytic cracking units, their regenerator and associated CO boiler or boilers and CO
furnace or furnaces where present, that commenced operation prior to January 1, 2008, if such
units are located at a petroleum refinery and such units are required to meet emission limits for
NO
x
as provided for in an enforceable order.” Statement at 30-31;
see
Prop. at 42.
In the first motion to amend its rulemaking proposal, the Agency sought to amend
subsection (c) to provide that
[t]he provisions of this Subpart do not apply to fluidized catalytic cracking units,
their regenerator and associated CO boiler or boilers and CO furnace or furnaces
where present, that commenced operation prior to January 1, 2008, if such units
are located at a petroleum refinery and such units are required to meet emission
limits or control requirements for NO
x
as provided for in an enforceable order.
Mot. Amend 1 at 6
In the second motion to amend, the Agency proposed to remove the January 1, 2008, date for
commencement of operation “in the non-applicability provisions pertaining to certain fluidized
bed catalytic cracking units located at a petroleum refinery.” Mot. Amend 2 at 5, 9-10.
Section 217.162: Exemptions.
The Agency proposes to add a new section addressing
exemptions, which provides in its entirety that, “[n]otwithstanding Section 217.160 of this
Subpart, the provisions of this Subpart do not apply to an industrial boiler operating under a
federally enforceable limit of NO
x
emissions from such boiler to less than 15 tons per year and
less than five tons per ozone season.” Prop. at 42;
see
Statement at 31, Kaleel Pre-filed Test. at
3.
Section 217.164: Emissions Limitations.
The Agency proposes to add a new section
addressing emission limitations from industrial boilers. Statement at 31; Prop. at 42-43;
see
generally
TSD at 5-44 (Industrial Boilers and Electric Generating Unit Boilers). Originally, the
Agency proposed that, “[o]n and after May 1, 2010, no person shall cause or allow emissions of
47
NO
x
into the atmosphere from any industrial boiler to exceed the limitations set forth under this
Section.” Statement at 31;
see
Prop. at 42-43. The Agency proposed specific limitations or
requirements based first on the unit’s fuel and then on its rated heat input capacity. Prop. at 42-
43 (proposed subsections (a) through (d)). The Agency also proposed that “[c]ompliance must
be demonstrated with the applicable emissions limitations on an ozone season and annual basis.”
Prop. at 42;
see
Statement at 31.
In a question filed for the first hearing on October 14, 2008, Midwest Generation asked
the Agency to state the “basis for establishing a rate of 0.008 lb/mmBtu rate for gas-fired
industrial boilers greater than 100 mmBtu.” MG Questions at 3. The Agency responded that its
TSD establishes this basis. MG Answers at 4, citing TSD at 43 (Table 2-17a: Cost Effectiveness
Data for Natural Gas-Fired ICI Boilers).
In testimony on behalf of U.S. Steel for the second hearing, Mr. Siebenberger stated that
the Agency’s proposed emission limit of 0.08 lbs/MMBtu for industrial boilers greater than 100
MMBtu/hr relying on natural gas or other gaseous fuels does not take into account the “unique
characteristics” of specific U.S. Steel boilers. Exh. 10 at 6. Those unique characteristics
“include the combustion of a varying fuel mix of desulfurized or non-desulfurized coke oven gas
in combination with blast furnace gas and natural gas.”
Id
. U.S Steel proposed alternate
emissions limits both for its Boilers 11 and 12 and for its reheat furnaces.
Id
. at 6, 7;
see
Tr.1 at
102-03 (addressing Agency consideration of coke oven gas fuel).
In testimony filed on behalf of IERG for the second hearing, Mr. Kolaz argues that the
difference in emissions between the Agency’s original proposal and IERG’s alternate proposal is
“relatively small.” Exh. 6 at 22. Mr. Kolaz further argues that IERG’s proposed emission limit
of 0.12 lbs/mmBtu for industrial boilers greater than 100 MMBtu/hr relying on natural gas or
other gaseous fuels is “more practically achievable.”
Id
. at 23;
see id
. at Exhs. 1, 2. Mr. Kolaz
also questions the Agency’s proposed compliance date on grounds including the practical ability
of sources to implement these requirements.
Id.
at 12-15.
In testimony filed on behalf of ConocoPhillips for the second hearing, Mr. Dunn stated
that the Agency’s proposed emission limit of 0.08 lb/MMBtu for industrial boilers greater than
100 MMBtu/hr relying on natural gas or other gaseous fuels is “overly stringent.” Exh. 9 at 6.
ConocoPhillips recommends an emission limit of 0.12 lb/MMBtu, as recommended by IERG.
Id
. at 9. ConocoPhillips further argues that the Agency’s compliance deadline is “not
achievable.”
Id
.
In post-hearing comments filed January 20, 2009, ConocoPhillips again addressed the
emission limitation of 0.08 lb/mmBtu for gas-fired boilers greater than 100 mmBtu/hr. PC 5 at
3-4. ConocoPhillips argues that the proposed limit “is overly stringent for typical industrial
boilers when burning refinery fuel gas” and “does not adequately consider the economic
consequences” of installing the controls that comply with it.
Id
. at 3-4.
In the first motion to amend its rulemaking proposal, the Agency proposed to amend the
first sentence of Section 217.164 by extending the compliance deadline to January 1, 2012. Mot.
Amend 1 at 6. In the second motion to amend, the Agency proposed to change the emissions
48
limitation for an industrial boiler, circulating fluidized bed combustor, with a rated heat input
capacity greater than 100 mmBtu/hr from 0.10 lb/mmBtu to 0.12 lb/mmBtu. Mot. Amend 2 at 4.
The Agency states that, “[d]uring discussions with affected parties, emissions information from
an existing source with such a unit was provided to Illinois EPA, and such information
necessitated a modification of the emissions limitation.”
Id
. at 4, 10. Also in the second motion
to amend, the Agency proposed to add in a new subsection (e) a formula establishing “an
emissions limitation to be calculated for an industrial boiler combusting a combination of natural
gas, coke oven gas, and blast furnace gas under Subpart D.”
Id
. at 4, 11.
Section 217.165: Combination of Fuels.
The Agency proposes to add a new section
addressing combination of fuels, which provides in its entirety that “[t]he owner or operator of an
industrial boiler subject to this Subpart and operated with any combination of fuels must comply
with a heat input weighted average emissions limitation to demonstrate compliance with Section
217.164 of this Subpart.” Prop. at 43;
see
Statement at 31;
see also supra
at 47-48 (discussing
proposed Section 217.164).
Section 217.166: Methods and Procedures for Combustion Tuning.
The Agency
proposes to add a new section addressing combustion tuning. Prop. at 44. The proposed section
first provides that “the owner or operator of an industrial boiler subject to the combustion tuning
requirements of Section 217.164 must have combustion tuning performed at least annually.”
Statement at 31;
see
Prop. at 44. It also provides that “the combustion tuning must be performed
by an employee of the owner or operator or a contractor who has successfully completed a
training course on the combustion tuning of boilers firing the fuel or fuels that are fired in the
boiler.” Statement at 31;
see
Prop. at 44. Finally, the proposed section also seeks to require that
the owner or operator maintain combustion tuning records containing five specific items and
make those records available to the Agency upon request. Statement at 31-32;
see
Prop. at 44
(proposed subsections (1) through (5)).
Subpart E: Process Heaters
Section 217.180: Applicability.
The Agency proposes to add a section addressing
applicability and providing in its entirety that “[t]he provisions of Subpart C of this Part and this
Subpart apply to all process heaters located at sources subject to this Subpart pursuant to Section
217.150 of this Part.” Prop. at 44;
see
Statement at 32,
supra
at 28-30 (discussing Section
217.150);
see generally
TSD at 46-65 (Process Heaters).
In a question filed for the first hearing on October 14, 2008, Midwest Generation
suggests that the “all process heaters” language in Section 217.160(a) could be construed to
expand the scope of Section 217.150(a)(2), which refers to “any . . . process heater . . . that emits
NO
x
in an amount equal to or greater than 15 tons per year and equal to or greater than five tons
per ozone season.” MG Questions at 2;
see
Prop. at 26 (proposed Section 217.150(a)(2)).
Midwest Generation questions whether the Agency intends “to expand the applicability of the
rule in this way.” MG Questions at 2. The Agency responds by expressing the intent “that each
Subpart apply to all of the affected emission units at an affected source,
e.g.
, ‘any’ emission unit
that meets the applicability criteria.” MG Answers at 3.
49
Section 217.182: Exemptions.
The Agency proposes to add a section addressing
exemptions and providing in its entirety that, “[n]otwithstanding Section 217.180 of this Section,
the provisions of this Subpart do not apply to a process heater operating under a federally
enforceable limit of NO
x
emissions from such heater to less than 15 tons per year and less than
five tons per ozone season.” Prop. at 45;
see
Statement at 33, Kaleel Pre-filed Test. at 3.
In testimony filed on behalf of IERG for the second hearing, Mr. Kolaz states that “most
of the process heaters affected by this rule are located at petroleum refineries,” which “cannot
make changes to their process heaters without planning the work to occur during maintenance
turnarounds.” Exh. 6. at 23. He further states that “it appears that the Agency used the emission
reductions from the USEPA refinery consent decrees for the attainment modeling conducted by
LADCO.”
Id
. at 24. He proposes that “the Agency consider the reductions from the federally
enforceable consent decrees to constitute RACT for these facilities.”
Id
. He identifies this
section as language that might be modified to effect this proposed amendment.
Id
.
Section 217.184: Emissions Limitations.
The Agency proposes to add a new section
addressing emission limitations from process heaters. Statement at 33; Prop. at 45-46;
see
generally
TSD at 46-65 (Process Heaters). Originally, the Agency proposed that, “[o]n and after
May 1, 2010, no person shall cause or allow emissions of NO
x
into the atmosphere from any
process heater” to exceed specified limitations. Prop. at 45;
see
Statement at 33. The Agency
proposed specific limitations or requirements based first on the unit’s fuel and then on its rated
heat input capacity in mmBtu/hr. Prop. at 45-46 (proposed subsections (a), (b), and (c)). The
Agency also proposed that “[c]ompliance must be demonstrated with the applicable emissions
limitations on an ozone season and annual basis.” Prop. at 45;
see
Statement at 33.
In testimony filed on behalf of ConocoPhillips for the second hearing, Mr. Dunn stated
that the Agency’s proposed emission limit of 0.07 lb/MMBtu for process heaters greater than
100 MMBtu/hr relying on gaseous fuels is “too stringent for typical process heaters” and requires
“control technology that is well beyond RACT.” Exh. 9 at 9. He further states that
ConocoPhillips “agrees with IERG’s suggestions that the NO
x
emission limit of process heaters
be set at 0.12 lb NO
x
/MMBtu.”
Id
. at 12. ConocoPhillips further argues that the Agency’s
compliance deadline is “not achievable.”
Id
.
In the first motion to amend its rulemaking proposal, the Agency proposed to amend the
first sentence of Section 217.184 by extending the compliance deadline to January 1, 2012. Mot.
Amend 1 at 7. In the second motion to amend, the Agency proposed to amend “the emissions
limitation for a process heater with a rated heat input capacity greater than 100 mmBtu/hr
combusting natural gas or other gaseous fuels” from 0.07 lb/mmBtu to 0.08 lb/mmBtu. Mot.
Amend 2 at 5, 11-12.
Section 217.185: Combination of Fuels.
The Agency proposes to add a new section
addressing combination of fuels, which provides in its entirety that “[t]he owner or operator of a
process heater subject to this Subpart and operated with any combination of fuels must comply
with a heat input weighted average emissions limitation to demonstrate compliance with Section
217.184 of this Subpart.” Prop. at 46;
see
Statement at 33;
see also supra
at 49-50 (discussing
proposed Section 217.184).
50
Section 217.186: Methods and Procedures for Combustion Tuning.
The Agency
proposes to add a new section addressing combustion tuning of process heaters. Prop. at 46-47.
The proposed section first provides that “the owner or operator of a process heater subject to the
combustion tuning requirements of Section 217.184 must have combustion tuning performed on
the heater at least annually.” Statement at 313
see
Prop. at 44. The proposed section also
provides that “[t]he combustion tuning must be performed by an employee of the owner or
operator or a contractor who has successfully completed a training course on the combustion
tuning of heaters firing the fuel or fuels that are fired in the heater.” Statement at 33;
see
Prop. at
46. Finally, the proposed section also seeks to require that the owner or operator maintain
combustion tuning records containing five specific items and make those records available to the
Agency upon request. Statement at 33-34;
see
Prop. at 46 (proposed subsections (1) through
(5)).
Subpart F: Glass Melting Furnaces
Section 217.200: Applicability.
The Agency proposes to add a section addressing
applicability and providing in its entirety that “[t]he provisions of Subpart C of this Part and this
Subpart apply to all glass melting furnaces located at sources subject to this Subpart pursuant to
Section 217.150 of this Part. Prop. at 47;
see
Statement at 34,
supra
at 28-30 (discussing Section
217.150);
see generally
TSD at 102-17 (Glass Melting Furnaces).
In a question filed for the first hearing on October 14, 2008, Midwest Generation
suggests that the “all glass melting furnaces” language in Section 217.200 could be construed to
expand the scope of Section 217.150(a)(2), which refers to “any . . . glass melting furnace . . .
that emits NO
x
in an amount equal to or greater than 15 tons per year and equal to or greater than
five tons per ozone season.” MG Questions at 2;
see
Prop. at 26 (proposed Section
217.150(a)(2)). Midwest Generation questions whether the Agency intends “to expand the
applicability of the rule in this way.” MG Questions at 2. The Agency responds by expressing
the intent “that each Subpart apply to all of the affected emission units at an affected source,
e.g.
,
‘any’ emission unit that meets the applicability criteria.” MG Answers at 3.
Section 217.202: Exemptions.
The Agency proposes to add a section addressing
exemptions and providing in its entirety that, “[n]otwithstanding Section 217.200 of this Section,
the provisions of this Subpart do not apply to a glass melting furnace operating under a federally
enforceable limit of NO
x
emissions from such furnace to less than 15 tons per year and less than
five tons per ozone season.” Prop. at 47;
see
Statement at 35, Kaleel Pre-filed Test. at 3.
In a post-hearing comment filed November 25, 2008, Saint-Gobain expressed the belief
that “a narrow exception should be made to the May 1, 2010 compliance date for entities that
enter into an enforceable agreement with IEPA to install control technology that can achieve
NO
x
emission rates significantly below the 5.0 lbs/ton limit pursuant to an enforceable schedule
extending beyond 2010. PC 2 at 1. As Saint-Gobain is negotiating such an agreement, it
proposes the following addition to this exemptions section:
51
[n]otwithstanding the compliance date set forth in Section 217.155(b) and
217.204, a compliance date of December 31 2014, shall apply when the owner or
operator of a container glass melting furnace subject to Subpart F has executed a
binding and enforceable agreement by December 31, 2009 with the State of
Illinois that requires compliance with a NO
x
limit that is less than 30 percent of
the emission limit in Section 217.204.
Id
.;
but see
Mot. Amend. 1 at 3
(incorporating substance of proposed language into Section 217.152(b)).
Section 217.204: Emissions Limitations.
The Agency proposes to add a new section
addressing emission limitations from glass melting furnaces. Statement at 35; Prop. at 47;
see
generally
TSD at 102-17 (Glass Melting Furnaces). Originally, the Agency proposed that, “[o]n
and after May 1, 2010, no person shall cause or allow emissions of NO
x
into the atmosphere
from any glass melting furnace” to exceed specified limitations. Prop. at 47;
see
Statement at 35.
The Agency proposed specific limitations based on the unit’s product type as container glass, flat
glass, or other glass. Prop. at 47 (proposed subsections (a), (b), and (c)). The Agency also
proposed that “[c]ompliance must be demonstrated with the emissions limitations on an ozone
season and annual basis.” Prop. at 47;
see
Statement at 35.
In a post-hearing comment filed November 25, 2008, Saint-Gobain expressed the belief
that “a narrow exception should be made to the May 1, 2010 compliance date for entities that
enter into an enforceable agreement with IEPA to install control technology that can achieve
NO
x
emission rates significantly below the 5.0 lbs/ton limit pursuant to an enforceable schedule
extending beyond 2010. PC 2 at 1. Noting that it is negotiating such an agreement, Saint-
Gobain argues that it “cannot afford to install the technology required to meet an interim limit of
5.0 lb/ton for the period between the compliance date under Section 217.204 and the anticipated
schedule for installation of alternative technology at the end of 2014.”
Id
.;
see
Tr.2 at 13-16
(addressing negotiation of consent decree). Saint-Gobain also refers to the cost of installing
CEMS devices.
See
PC 2 at 1-2.
In a pre-hearing comment filed January 20, 2009, Saint-Gobain proposed to add to
Section 217.202 language providing that “Section 217.204 shall not apply during glass furnace
startup (not to exceed 70 days) or idling (operation at less than 35% of furnace capacity).” PC 4
at 2. Saint-Gobain also proposed a formula with which to determine a NO
x
emission limit
applicable to those startup and idling periods.
See id
.
In the first motion to amend its rulemaking proposal, the Agency proposed to amend the
first sentence of Section 217.204 by extending the compliance deadline to January 1, 2012. Mot.
Amend 1 at 7. The Agency also proposed to add a subsection providing in part that “[t]he
emissions limitations under this Section do not apply during glass melting furnace startup (not to
exceed 70 days) or idling (operation at less than 35% of furnace capacity).”
Id
. The Agency’s
proposed new subsection also included a formula for determining NO
x
emissions limitations
during startup and idle periods.
Id
.
Subpart G: Cement and Lime Kilns
52
Section 217.220: Applicability.
The Agency proposes to add a section addressing
applicability to cement and lime kilns. Prop. at 48;
see
Statement at 35-36. Proposed subsection
(a) provides in its entirety that, “[n]otwithstanding Subpart T of this Part, the provisions of
Subpart C of this Part and this Subpart apply to all cement kilns located at sources subject to this
Subpart pursuant to Section 217.150 of this Part.” Prop. at 48;
see
Statement at 35-36;
supra
at
28-30 (discussing Section 217.150);
see generally
TSD at 66-85 (Cement Kilns). Proposed
subsection (b) provides in its entirety that “[t]he provisions of Subpart C of this Part and this
Subpart apply to all lime kilns located at sources subject to this Subpart pursuant to Section
217.150 of this Part. Prop. at 48;
see
Statement at 35-36;
see supra
at 28-30 (discussing Section
217.150);
see generally
TSD at 86-91 (Lime Kilns).
In a question filed for the first hearing on October 14, 2008, Midwest Generation
suggests that the “all cement kilns” and “all lime kilns” language in Section 217.220 could be
construed to expand the scope of Section 217.150(a)(2), which refers to “any . . . cement kiln [or]
lime kiln . . . that emits NO
x
in an amount equal to or greater than 15 tons per year and equal to
or greater than five tons per ozone season.” MG Questions at 2;
see
Prop. at 26 (proposed
Section 217.150(a)(2)). Midwest Generation questions whether the Agency intends “to expand
the applicability of the rule in this way.” MG Questions at 2. The Agency responds by
expressing the intent “that each Subpart apply to all of the affected emission units at an affected
source,
e.g.
, ‘any’ emission unit that meets the applicability criteria.” MG Answers at 3.
In another question filed for the first hearing on October 14, 2008, Midwest Generation
asked why, if there are no cement kilns in the nonattainment areas, cement kilns are included in
the rulemaking. MG Questions at 1;
see also
IERG Questions at 4. The Agency responded by
stating that “[t]here are no cement kilns in the current NAAs, although there is a cement kiln in
Massac County, which USEPA intends to designate as nonattainment for the 24-hour PM
2.5
NAAQS.” MG Answers at 2, citing
id
., Attachment 1 (USEPA review of air quality
designations);
see also
IERG Answers at 6, citing TSD at 66 (noting that none of eight Illinois
cement kilns are situated in nonattainment areas), Tr.1 at 57-62.
In his testimony on behalf of the Agency at the first hearing on October 14, 2008, Mr.
Kaleel noted that the Agency had initially drafted these proposed regulations to have statewide
applicability and that there are cement kilns situated in the state’s attainment areas. Tr. 1 at 61.
He also noted that, under the revised ozone and PM
2.5
standards, “there may be some
adjustments necessary to the non-attainment areas.”
Id
. Mr. Kaleel also argued that the Agency
has already performed the engineering and cost analysis in support of these proposed rules.
Id
. at
62. Although he acknowledged that a change in the boundaries of the nonattainment areas would
require changing the regulation, including cement kilns “would send a clear message to units that
potentially become non-attainment in the future that they would know what their target is, what it
is they have to meet.”
Id
.
In testimony filed on behalf of IERG for the second hearing on December 9, 2008, Mr.
Kolaz argued that, because no cement kilns exist in the nonattainment areas, cement kilns should
not be included in the Agency’s proposed regulations. Exh. 6 at 19, 24. He further argues that
“[a]ny new facility with such a unit in the applicable areas would be subject to controls stricter
than RACT.”
Id
. at 19. He also argues that, in the event that, “[i]f new nonattainment areas are
53
identified in Illinois, this proposed rule would need to be amended to incorporate those areas if
NO
x
reductions are deemed necessary and appropriate to address the air quality conditions.”
Id
.;
see
Tr.1 at 57-60.
Section 217.222: Exemptions.
The Agency proposes to add a section addressing
exemptions and providing in its entirety that, “[n]otwithstanding Section 217.220 of this Subpart,
the provisions of this Subpart do not apply to a cement kiln or lime kiln operating under a
federally enforceable limit of NO
x
emissions from such kiln to less than 15 tons per year and less
than five tons per ozone season.” Prop. at 48;
see
Statement at 36, Kaleel Pre-filed Test. at 3.
Section 217.224: Emissions Limitations.
The Agency proposes to add a new section
addressing emission limitations from cement kilns and lime kilns. Statement at 36; Prop. at 48-
49. Originally, the Agency proposed in subsection (a) that, “[o]n and after May 1, 2010, no
person shall cause or allow emissions of NO
x
into the atmosphere from any cement kiln” to
exceed specified limitations. Prop. at 48;
see
Statement at 36. The Agency proposed specific
limitations based on the unit’s type. Prop. at 48 (proposed subsections (a)(1) through (a)(4)).
The Agency also proposed in subsection (b) that, “[o]n and after May 1, 2010, no person shall
cause or allow emissions of NO
x
into the atmosphere from any lime kiln” to exceed specified
limitations. Prop. at 49;
see
Statement at 36. The Agency also proposed that “[c]ompliance
must be demonstrated with the emissions limitations on an ozone season and annual basis.”
Prop. at 48;
see
Statement at 36.
In the first motion to amend its rulemaking proposal, the Agency proposed to amend the
first sentence of subsections (a) and (b) by extending the compliance deadline to January 1,
2012. Mot. Amend 1 at 8.
Subpart H: Iron and Steel and Aluminum Manufacturing
Section 217.240: Applicability.
The Agency proposes to add a section addressing
applicability to cement and lime kilns. Prop. at 49;
see
Statement at 36-37. Proposed subsection
(a) provides in its entirety that, “[t]he provisions of Subpart C of this Part and this Subpart apply
to all reheat furnaces, annealing furnaces, and galvanizing furnaces used in iron and steel making
located at sources subject to this Subpart pursuant to Section 217.150 of this Part.” Prop. at 49;
see
Statement at 36-37;
supra
at 28-30 (discussing Section 217.150);
see generally
TSD at 92-
101 (Reheat, Annealing, and Galvanizing Furnaces at Iron/Steel plants). Proposed subsection (b)
provides in its entirety that “[t]he provisions of Subpart C of this Part and this Subpart apply to
all reverberatory furnaces and crucible furnaces used in aluminum melting located at sources
subject to this Subpart pursuant to Section 217.150 of this Part. Prop. at 49;
see
Statement at 36-
37;
see supra
at 28-30 (discussing Section 217.150);
see generally
TSD at 118-25 (Aluminum
Melting Furnaces).
In a question filed for the first hearing on October 14, 2008, Midwest Generation
suggests that the “all reheat furnaces, annealing furnaces, and galvanizing furnaces used in iron
and steel making” and “all aluminum reverberatory furnaces and crucible furnaces used in
aluminum melting” language in Section 217.240 could be construed to expand the scope of
Section 217.150(a)(2), which refers to “any . . . iron and steel reheat, annealing, or galvanizing
54
furnace, [or] aluminum reverberatory or crucible furnace . . . that emits NO
x
in an amount equal
to or greater than 15 tons per year and equal to or greater than five tons per ozone season.” MG
Questions at 2;
see
Prop. at 26 (proposed Section 217.150(a)(2)). Midwest Generation questions
whether the Agency intends “to expand the applicability of the rule in this way.” MG Questions
at 2. The Agency responds by expressing the intent “that each Subpart apply to all of the
affected emission units at an affected source,
e.g.
, ‘any’ emission unit that meets the applicability
criteria.” MG Answers at 3.
In another question filed for the first hearing on October 14, 2008, Midwest Generation
asked why, if there are no aluminum melting furnaces affected by the proposal, the rule includes
that sector. MG Questions at 1;
see also
IERG Questions at 4. The Agency responded by stating
that “[t]here is an aluminum melting furnace in the Chicago non-attainment area (NAA),
although it has not operated for several years. To the best of our knowledge, the emission unit
has not been torn down, so it is possible that the company, or a future owner, will seek to operate
the furnace in the future.” MG Answers at 1-2;
see
Tr.1 at 60-61;
see also
IERG Answers at 6.
In testimony filed on behalf of IERG for the second hearing on December 9, 2008, Mr.
Kolaz argued that, because no aluminum reverberatory or crucible furnaces exist in the
nonattainment areas, they should not be included in the Agency’s proposed regulations. Exh. 6
at 19, 24, citing Tr.1 at 60-61. He further argues that “[a]ny new facility with such a unit in the
applicable areas would be subject to controls stricter than RACT.” Exh. 6 at 19. He also argues
that, in the event that, “[i]f new nonattainment areas are identified in Illinois, this proposed rule
would need to be amended to incorporate those areas if NO
x
reductions are deemed necessary
and appropriate to address the air quality conditions.”
Id
.;
see
Tr.1 at 57-60.
Section 217.242: Exemptions.
The Agency proposes to add a section addressing
exemptions and providing in its entirety that, “[n]otwithstanding Section 217.240 of this Subpart,
the provisions of this Subpart do not apply to an iron and steel reheat furnace, annealing furnace,
or galvanizing furnace, or aluminum reverberatory furnace or crucible furnace operating under a
federally enforceable limit of NO
x
emissions from such furnace to less than 15 tons per year and
less than five tons per ozone season.” Prop. at 49;
see
Statement at 36, Kaleel Pre-filed Test. at
3.
Section 217.244: Emissions Limitations.
The Agency proposes to add a new section
addressing emission limitations for iron and steel and aluminum manufacturing. Statement at
36-37; Prop. at 50-51. Originally, the Agency proposed in subsection (a) that, “[o]n and after
May 1, 2010, no person shall cause or allow emissions of NO
x
into the atmosphere from any
reheat furnace, annealing furnace, or galvanizing furnace use in iron and steel making” to exceed
specified limitations. Prop. at 50;
see
Statement at 37. The Agency proposed specific emissions
limitations based on the unit’s type. Prop. at 50 (proposed subsections (a)(1) through (a)(9)).
The Agency also proposed in subsection (b) that, “[o]n and after May 1, 2010, no person shall
cause or allow emissions of NO
x
into the atmosphere from any reverberatory furnace or crucible
furnace used in aluminum melting” to exceed specified limitations. Prop. at 50;
see
Statement at
37. The Agency also proposed with regard to both subsections that “[c]ompliance must be
demonstrated with the emissions limitations on an ozone season and annual basis.” Prop. at 50;
see
Statement at 37.
55
In the first motion to amend its rulemaking proposal, the Agency proposed to amend the
first sentence of subsections (a) and (b) by extending the compliance deadline to January 1,
2012. Mot. Amend 1 at 8-9. In the second motion to amend the proposal, the Agency proposed
to change the emissions limitation for a recuperative reheat furnace combusting natural gas from
0.05 lb/mmBtu to 0.09 lb/mmBtu. Mot. Amend 2 at 5, 12. The Agency also proposed to add an
emissions limitation of 0.142 lb/mmBtu for a recuperative reheat furnace combusting a
combination of natural gas and coke oven gas.
Id
.
Subpart M: Electrical Generating Units
Section 217.340: Applicability.
The Agency proposes to add a section addressing
applicability to EGUs, which provides in its entirety that, “[n]otwithstanding Subpart V or W of
this Part, the provisions of Subpart C of this Part and this Subpart apply to all fossil fuel-fired
stationary boilers subject to the CAIR NO
x
Trading Programs under Subpart D or E of Part 225
located at sources subject to this Subpart pursuant to Section 217.150 of this Part.” Prop. at 51;
see
Statement at 37-38;
supra
at 28-30 (discussing Section 217.150);
see generally
TSD at 5-45
(Industrial Boilers and Electrical Generating Unit Boilers).
In a question filed for the first hearing on October 14, 2008, Midwest Generation
suggests that the “all fossil fuel-fired stationary boilers” language in Section 217.340 could be
construed to expand the scope of Section 217.150(a)(2), which refers to “any . . . fossil fuel-fired
stationary boiler . . . that emits NO
x
in an amount equal to or greater than 15 tons per year and
equal to or greater than five tons per ozone season.” MG Questions at 2;
see
Prop. at 26
(proposed Section 217.150(a)(2)). Midwest Generation questions whether the Agency intends
“to expand the applicability of the rule in this way.” MG Questions at 2. The Agency responds
by expressing the intent “that each Subpart apply to all of the affected emission units at an
affected source,
e.g.
, ‘any’ emission unit that meets the applicability criteria.” MG Answers at 3.
In another question filed for the first hearing, Midwest Generation noted that “[t]he TSD
claims there are a total of 18 EGUs subject to the rule, while the Statement of Reasons says there
are 20 ‘fossil fuel-fired stationary boilers’ subject to the rule.” MG Questions at 4. Midwest
Generation asks whether there are “fossil fuel-fired stationary boilers that are not EGUs that are
subject to the rule?”
Id
. The Agency responds that “there are 20 EGU boilers,” clarifying that
“there are two instances in which one unit is comprised of two boilers.” MG Answers at 8, citing
TSD at Appendices – 27 (Table E-1).
In another question filed for the first hearing, Midwest Generation stated that, “[b]ased
upon the proposed applicability language in Subpart M, Section 217.340, [and] assuming the
D.C. Circuit Court issues the mandate implementing its decision in the appeal of the CAIR,
EGUs would be subject to the provisions of Subpart D.” MG Questions at 3. Midwest
Generation consequently asked whether the Agency would consider amending this provision as
follows:
[n]otwithstanding Subpart V or W of this Part, the provisions of Subpart C of
this Part and this Subpart apply to al fossil fuel-fired stationary boilers subject to
56
the CAIR NO
x
Trading Programs under Subpart D or E of Part 225 any fossil
fuel-fired stationary boiler serving a generator that has a nameplate capacity
greater than 25 MWe and produces electricity for sale, excluding any units listed
in Appendix D of this Part, located at sources subject to this Subpart pursuant to
Section 217.150 of this Part.
Id
.
Responding to Midwest Generation, the Agency stated that it was “amenable” to
amending its proposed definition in the following fashion:
[n]otwithstanding Subpart V or W of this Part, the provisions of Subpart C of this
Part and this Subpart apply to all fossil fuel-fired stationary boilers subject to the
CAIR NO
x
Trading Programs under Subpart D or E of Part 225 any fossil fuel-
fired stationary boiler serving at any time a generator that has a nameplate
capacity greater than 25 MWe and produces electricity for sale, excluding any
units listed in Appendix D of this Part, located at sources subject to this Subpart
pursuant to Section 217.150 of this Part. MG Answers at 4-5;
see
Exh. 12 at 2-3
(Encouraging adoption of amended language).
In its first motion to amend its rulemaking proposal, the Agency recommended that the
Board “[a]mend Section 217.340 to reflect the provisions as previously agreed to between the
Illinois EPA and Midwest Generation as reflected in the Illinois EPA’s Answers to Midwest
Generation’s Questions for Agency Witnesses, filed September 30, 2008, and the October 14,
2008, hearing.” Mot. Amend 1 at 9;
see
MG Question at 3, MG Answers at 4-5.
In its post-hearing comments, Midwest Generation states that,
[w]ith the amendments proposed to the Board by the Agency in its Motion to
Amend Rulemaking Proposal ("Agency's Motion") filed January 30, 2009,
Midwest Generation generally supports the Agency's proposal as it applies to
electric generating units ("EGUs"). The proposed amendments incorporate by
reference provisions agreed to between the Agency and Midwest Generation as
part of the Agency's Answers to Midwest Generation's Questions for Agency
Witnesses ("Agency's Answers"), which were filed before this Board on
September 30, 2008. PC 9 at 1-2 (noting Agency’s proposed amendment of
Section 217.340);
see
Mot. Amend 1 at 9, Tr.1 at 199-200.
In testimony filed for the second hearing on December 9, 2008, Mr. Kolaz argues
that “the CAIR rule should be considered RACT for EGUs” and that “Subpart M is
unnecessary for purposes of achieving the Agency’s stated goals of achieving RACT
level reductions.” Exh. 6 at 25;
see
Tr.2 at 80-81. Midwest Generation concurred that
Subpart M “is not necessary and should be deleted from the rule.” Tr.3 at 58 (Miller
testimony).
Section 217.342: Exemptions.
The Agency proposes to add a section addressing
exemptions. The proposed subsection (a) provides in its entirety that, “[n]otwithstanding Section
217.340 of this Subpart, the provisions of this Subpart do not apply to a fossil fuel-fired
57
stationary boiler operating under a federally enforceable limit of NO
x
emissions from such boiler
to less than 15 tons per year and less than five tons per ozone season.” Prop. at 51;
see
Statement
at 38, Kaleel Pre-filed Test. at 3. Proposed subsection (b) provides in its entirety that,
“[n]owithstanding Section 217.340 of this Subpart, the provisions of this Subpart do not apply to
a coal-fired stationary boiler that commenced operation before January 1, 2008, that is
complying with the multi-pollutant standard under Section 225.233 of Part 225 or the combined
pollutant standards under Subpart F of Part 225.” Prop. at 51;
see
Statement at 38.
In a question filed for the first hearing on October 14, 2008, Midwest Generation stated
that, “[b]ased upon the proposed applicability language in Subpart M, Section 217.340, [and]
assuming the D.C. Circuit Court issues the mandate implementing its decision in the appeal of
the CAIR, EGUs would be subject to the provisions of Subpart D.” MG Questions at 3.
Midwest Generation consequently asked whether the Agency would consider amending
subsection (b) of this provision as follows: “[n]otwithstanding section 217.340 of this Subpart,
the provisions of this Subpart do not apply to a coal-fired stationary boiler that commenced
operation before January 1, 2008, that is complying with Part 225.Subpart B through the multi-
pollutant standard under Section 225.233 of Part 225 or the combined pollutant standards under
Subpart F of Part 225.”
Id
. Responding to Midwest Generation, the Agency stated that it was
“amenable” to amending subsection (b) in that fashion. MG Answers at 4-6.
In its post-hearing comments, Midwest Generation states that,
[w]ith the amendments proposed to the Board by the Agency in its Motion to
Amend Rulemaking Proposal ("Agency's Motion") filed January 30, 2009,
Midwest Generation generally supports the Agency's proposal as it applies to
electric generating units ("EGUs"). The proposed amendments incorporate by
reference provisions agreed to between the Agency and Midwest Generation as
part of the Agency's Answers to Midwest Generation's Questions for Agency
Witnesses ("Agency's Answers"), which were filed before this Board on
September 30, 2008. PC 9 at 1-2 (noting Agency’s proposed amendment of
Section 217.340);
see
Mot. Amend 1 at 10, Tr.1 at 199-200.
Section 217.344: Emissions Limitations.
The Agency proposes to add a new section
addressing emission limitations for EGUs. Statement at 38-39; Prop. at 51-52. Originally, the
Agency proposed that, “[o]n and after May 1, 2010, no person shall cause or allow emissions of
NO
x
into the atmosphere from any fossil fuel-fired stationary boiler” to exceed specified
limitations. Prop. at 50;
see
Statement at 37. The Agency proposed specific emissions
limitations based on the unit’s type. Prop. at 52 (proposed subsections (a), (b), and (c)). The
Agency also proposed that “[c]ompliance must be demonstrated with the emissions limitations
on an ozone season and annual basis.” Prop. at 51;
see
Statement at 39.
In the first motion to amend its rulemaking proposal, the Agency proposed to amend the
first sentence of Section 217.344 by extending the compliance deadline to January 1, 2012. Mot.
Amend 1 at 10. The Agency proposed to change the emissions limitation for a boiler
combusting solid fuel from 0.09 lb/mmBtu to 0.012 lb/mmBtu.
Id
.;
see
MG Answers at 6-8
(providing basis for determining 0.09 lb/mmBtu constitutes RACT)
58
Section 217.345: Combination of Fuels.
The Agency proposes to add a new section
addressing combination of fuels, which provides in its entirety that “[t]he owner or operator of a
fossil fuel-fired stationary boiler subject to this Subpart and operated with any combination of
fuels must comply with a heat input weighted average emissions limitation to demonstrate
compliance with Section 217.344 of this Subpart.” Prop. at 52;
see
Statement at 39.
Appendix H
In the second motion to amend its rulemaking proposal, the Agency proposes to add an
Appendix H “to set forth the compliance dates for certain emission units at petroleum refineries.”
Mot. Amend 2 at 5, 13-14.
ORDER
The Board directs the Clerk to cause first-notice publication of the following proposed
amendments to Parts 211 and 217 of the Board’s air pollution regulations in the
Illinois Register
.
Proposed additions to Parts 211 and 217 are underlined; proposed deletions appear stricken.
TITLE 35: ENVIRONMENTAL PROTECTION
SUBTITLE B: AIR POLLUTION
CHAPTER I: POLLUTION CONTROL BOARD
SUBCHAPTER c: EMISSION STANDARDS AND LIMITATIONS FOR
STATIONARY SOURCES
PART 211
DEFINITIONS AND GENERAL PROVISIONS
SUBPART A: GENERAL PROVISIONS
Section
211.101
Incorporations by Reference
211.102
Abbreviations and Conversion Factors
SUBPART B: DEFINITIONS
Section
211.121
Other Definitions
211.122
Definitions (Repealed)
211.130
Accelacota
211.150
Accumulator
211.170
Acid Gases
211.210
Actual Heat Input
211.230
Adhesive
211.240
Adhesion Promoter
211.250
Aeration
59
211.270
Aerosol Can Filling Line
211.290
Afterburner
211.310
Air Contaminant
211.330
Air Dried Coatings
211.350
Air Oxidation Process
211.370
Air Pollutant
211.390
Air Pollution
211.410
Air Pollution Control Equipment
211.430
Air Suspension Coater/Dryer
211.450
Airless Spray
211.470
Air Assisted Airless Spray
211.474
Alcohol
211.479
Allowance
211.484
Animal
211.485
Animal Pathological Waste
211.490
Annual Grain Through-Put
211.495
Anti-Glare/Safety Coating
211.510
Application Area
211.530
Architectural Coating
211.550
As Applied
211.560
As-Applied Fountain Solution
211.570
Asphalt
211.590
Asphalt Prime Coat
211.610
Automobile
211.630
Automobile or Light-Duty Truck Assembly Source or Automobile or Light-Duty
Truck Manufacturing Plant
211.650
Automobile or Light-Duty Truck Refinishing
211.660
Automotive/Transportation Plastic Parts
211.665
Auxiliary Boiler
211.670
Baked Coatings
211.680
Bakery Oven
211.685
Basecoat/Clearcoat System
211.690
Batch Loading
211.695
Batch Operation
211.696
Batch Process Train
211.710
Bead-Dipping
211.730
Binders
211.740
Brakehorsepower (rated-bhp)
211.750
British Thermal Unit
211.770
Brush or Wipe Coating
211.790
Bulk Gasoline Plant
211.810
Bulk Gasoline Terminal
211.820
Business Machine Plastic Parts
211.830
Can
211.850
Can Coating
211.870
Can Coating Line
60
211.890
Capture
211.910
Capture Device
211.930
Capture Efficiency
211.950
Capture System
211.953
Carbon Adsorber
211.955
Cement
211.960
Cement Kiln
211.970
Certified Investigation
211.980
Chemical Manufacturing Process Unit
211.990
Choke Loading
211.995
Circulating Fluidized Bed Combustor
211.1010
Clean Air Act
211.1050
Cleaning and Separating Operation
211.1070
Cleaning Materials
211.1090
Clear Coating
211.1110
Clear Topcoat
211.1120
Clinker
211.1130
Closed Purge System
211.1150
Closed Vent System
211.1170
Coal Refuse
211.1190
Coating
211.1210
Coating Applicator
211.1230
Coating Line
211.1250
Coating Plant
211.1270
Coil Coating
211.1290
Coil Coating Line
211.1310
Cold Cleaning
211.1312
Combined Cycle System
211.1315
Combustion Tuning
211.1316
Combustion Turbine
211.1320
Commence Commercial Operation
211.1324
Commence Operation
211.1328
Common Stack
211.1330
Complete Combustion
211.1350
Component
211.1370
Concrete Curing Compounds
211.1390
Concentrated Nitric Acid Manufacturing Process
211.1410
Condensate
211.1430
Condensible PM-10
211.1435
Container Glass
211.1465
Continuous Automatic Stoking
211.1467
Continuous Coater
211.1470
Continuous Process
211.1490
Control Device
211.1510
Control Device Efficiency
211.1515
Control Period
61
211.1520
Conventional Air Spray
211.1530
Conventional Soybean Crushing Source
211.1550
Conveyorized Degreasing
211.1570
Crude Oil
211.1590
Crude Oil Gathering
211.1610
Crushing
211.1630
Custody Transfer
211.1650
Cutback Asphalt
211.1670
Daily-Weighted Average VOM Content
211.1690
Day
211.1710
Degreaser
211.1730
Delivery Vessel
211.1740
Diesel Engine
211.1750
Dip Coating
211.1770
Distillate Fuel Oil
211.1780
Distillation Unit
211.1790
Drum
211.1810
Dry Cleaning Operation or Dry Cleaning Facility
211.1830
Dump-Pit Area
211.1850
Effective Grate Area
211.1870
Effluent Water Separator
211.1875
Elastomeric Materials
211.1880
Electromagnetic Interference/Radio Frequency Interference (EMI/RFI) Shielding
Coatings
211.1885
Electronic Component
211.1890
Electrostatic Bell or Disc Spray
211.1900
Electrostatic Prep Coat
211.1910
Electrostatic Spray
211.1920
Emergency or Standby Unit
211.1930
Emission Rate
211.1950
Emission Unit
211.1970
Enamel
211.1990
Enclose
211.2010
End Sealing Compound Coat
211.2030
Enhanced Under-the-Cup Fill
211.2050
Ethanol Blend Gasoline
211.2070
Excess Air
211.2080
Excess Emissions
211.2090
Excessive Release
211.2110
Existing Grain-Drying Operation (Repealed)
211.2130
Existing Grain-Handling Operation (Repealed)
211.2150
Exterior Base Coat
211.2170
Exterior End Coat
211.2190
External Floating Roof
211.2210
Extreme Performance Coating
211.2230
Fabric Coating
62
211.2250
Fabric Coating Line
211.2270
Federally Enforceable Limitations and Conditions
211.2285
Feed Mill
211.2290
Fermentation Time
211.2300
Fill
211.2310
Final Repair Coat
211.2330
Firebox
211.2350
Fixed-Roof Tank
211.2355
Flare
211.2357
Flat Glass
211.2360
Flexible Coating
211.2365
Flexible Operation Unit
211.2370
Flexographic Printing
211.2390
Flexographic Printing Line
211.2410
Floating Roof
211.2420
Fossil Fuel
211.2425
Fossil Fuel-Fired
211.2430
Fountain Solution
211.2450
Freeboard Height
211.2470
Fuel Combustion Emission Unit or Fuel Combustion Emission Source
211.2490
Fugitive Particulate Matter
211.2510
Full Operating Flowrate
211.2530
Gas Service
211.2550
Gas/Gas Method
211.2570
Gasoline
211.2590
Gasoline Dispensing Operation or Gasoline Dispensing Facility
211.2610
Gel Coat
211.2620
Generator
211.2625
Glass Melting Furnace
211.2630
Gloss Reducers
211.2650
Grain
211.2670
Grain-Drying Operation
211.2690
Grain-Handling and Conditioning Operation
211.2710
Grain-Handling Operation
211.2730
Green-Tire Spraying
211.2750
Green Tires
211.2770
Gross Heating Value
211.2790
Gross Vehicle Weight Rating
211.2810
Heated Airless Spray
211.2815
Heat Input
211.2820
Heat Input Rate
211.2830
Heatset
211.2850
Heatset Web Offset Lithographic Printing Line
211.2870
Heavy Liquid
211.2890
Heavy Metals
211.2910
Heavy Off-Highway Vehicle Products
63
211.2930
Heavy Off-Highway Vehicle Products Coating
211.2950
Heavy Off-Highway Vehicle Products Coating Line
211.2970
High Temperature Aluminum Coating
211.2990
High Volume Low Pressure (HVLP) Spray
211.3010
Hood
211.3030
Hot Well
211.3050
Housekeeping Practices
211.3070
Incinerator
211.3090
Indirect Heat Transfer
211.3100
Industrial Boiler
211.3110
Ink
211.3130
In-Process Tank
211.3150
In-Situ Sampling Systems
211.3170
Interior Body Spray Coat
211.3190
Internal-Floating Roof
211.3210
Internal Transferring Area
211.3230
Lacquers
211.3250
Large Appliance
211.3270
Large Appliance Coating
211.3290
Large Appliance Coating Line
211.3300
Lean-Burn Engine
211.3310
Light Liquid
211.3330
Light-Duty Truck
211.3350
Light Oil
211.3355
Lime Kiln
211.3370
Liquid/Gas Method
211.3390
Liquid-Mounted Seal
211.3410
Liquid Service
211.3430
Liquids Dripping
211.3450
Lithographic Printing Line
211.3470
Load-Out Area
211.3475
Load Shaving Unit
211.3480
Loading Event
211.3483
Long Dry Kiln
211.3485
Long Wet Kiln
211.3487
Low-NOx Burner
211.3490
Low Solvent Coating
211.3500
Lubricating Oil
211.3510
Magnet Wire
211.3530
Magnet Wire Coating
211.3550
Magnet Wire Coating Line
211.3570
Major Dump Pit
211.3590
Major Metropolitan Area (MMA)
211.3610
Major Population Area (MPA)
211.3620
Manually Operated Equipment
211.3630
Manufacturing Process
64
211.3650
Marine Terminal
211.3660
Marine Vessel
211.3670
Material Recovery Section
211.3690
Maximum Theoretical Emissions
211.3695
Maximum True Vapor Pressure
211.3710
Metal Furniture
211.3730
Metal Furniture Coating
211.3750
Metal Furniture Coating Line
211.3770
Metallic Shoe-Type Seal
211.3780
Mid-Kiln Firing
211.3790
Miscellaneous Fabricated Product Manufacturing Process
211.3810
Miscellaneous Formulation Manufacturing Process
211.3830
Miscellaneous Metal Parts and Products
211.3850
Miscellaneous Metal Parts and Products Coating
211.3870
Miscellaneous Metal Parts or Products Coating Line
211.3890
Miscellaneous Organic Chemical Manufacturing Process
211.3910
Mixing Operation
211.3915
Mobile Equipment
211.3930
Monitor
211.3950
Monomer
211.3960
Motor Vehicles
211.3965
Motor Vehicle Refinishing
211.3970
Multiple Package Coating
211.3980
Nameplate Capacity
211.3990
New Grain-Drying Operation (Repealed)
211.4010
New Grain-Handling Operation (Repealed)
211.4030
No Detectable Volatile Organic Material Emissions
211.4050
Non-Contact Process Water Cooling Tower
211.4055
Non-Flexible Coating
211.4065
Non-Heatset
211.4067
NOx Trading Program
211.4070
Offset
211.4090
One Hundred Percent Acid
211.4110
One-Turn Storage Space
211.4130
Opacity
211.4150
Opaque Stains
211.4170
Open Top Vapor Degreasing
211.4190
Open-Ended Valve
211.4210
Operator of a Gasoline Dispensing Operation or Operator of a Gasoline
Dispensing Facility
211.4230
Organic Compound
211.4250
Organic Material and Organic Materials
211.4260
Organic Solvent
211.4270
Organic Vapor
211.4280
Other Glass
211.4290
Oven
65
211.4310
Overall Control
211.4330
Overvarnish
211.4350
Owner of a Gasoline Dispensing Operation or Owner of a Gasoline Dispensing
Facility
211.4370
Owner or Operator
211.4390
Packaging Rotogravure Printing
211.4410
Packaging Rotogravure Printing Line
211.4430
Pail
211.4450
Paint Manufacturing Source or Paint Manufacturing Plant
211.4470
Paper Coating
211.4490
Paper Coating Line
211.4510
Particulate Matter
211.4530
Parts Per Million (Volume) or PPM (Vol)
211.4550
Person
211.4590
Petroleum
211.4610
Petroleum Liquid
211.4630
Petroleum Refinery
211.4650
Pharmaceutical
211.4670
Pharmaceutical Coating Operation
211.4690
Photochemically Reactive Material
211.4710
Pigmented Coatings
211.4730
Plant
211.4740
Plastic Part
211.4750
Plasticizers
211.4770
PM-10
211.4790
Pneumatic Rubber Tire Manufacture
211.4810
Polybasic Organic Acid Partial Oxidation Manufacturing Process
211.4830
Polyester Resin Material(s)
211.4850
Polyester Resin Products Manufacturing Process
211.4870
Polystyrene Plant
211.4890
Polystyrene Resin
211.4910
Portable Grain-Handling Equipment
211.4930
Portland Cement Manufacturing Process Emission Source
211.4950.1
Portland Cement Process or Portland Cement Manufacturing Plant
211.4960
Potential Electrical Output Capacity
211.4970
Potential to Emit
211.4990
Power Driven Fastener Coating
211.5010
Precoat
211.5015
Preheater Kiln
211.5020
Preheater/Precalciner Kiln
211.5030
Pressure Release
211.5050
Pressure Tank
211.5060
Pressure/Vacuum Relief Valve
211.5061
Pretreatment Wash Primer
211.5065
Primary Product
211.5070
Prime Coat
66
211.5080
Primer Sealer
211.5090
Primer Surfacer Coat
211.5110
Primer Surfacer Operation
211.5130
Primers
211.5150
Printing
211.5170
Printing Line
211.5185
Process Emission Source
211.5190
Process Emission Unit
211.5195
Process Heater
211.5210
Process Unit
211.5230
Process Unit Shutdown
211.5245
Process Vent
211.5250
Process Weight Rate
211.5270
Production Equipment Exhaust System
211.5310
Publication Rotogravure Printing Line
211.5330
Purged Process Fluid
211.5340
Rated Heat Input Capacity
211.5350
Reactor
211.5370
Reasonably Available Control Technology (RACT)
211.5390
Reclamation System
211.5410
Refiner
211.5430
Refinery Fuel Gas
211.5450
Refinery Fuel Gas System
211.5470
Refinery Unit or Refinery Process Unit
211.5480
Reflective Argent Coating
211.5490
Refrigerated Condenser
211.5500
Regulated Air Pollutant
211.5510
Reid Vapor Pressure
211.5530
Repair
211.5550
Repair Coat
211.5570
Repaired
211.5580
Repowering
211.5590
Residual Fuel Oil
211.5600
Resist Coat
211.5610
Restricted Area
211.5630
Retail Outlet
211.5640
Rich-Burn Engine
211.5650
Ringelmann Chart
211.5670
Roadway
211.5690
Roll Coater
211.5710
Roll Coating
211.5730
Roll Printer
211.5750
Roll Printing
211.5770
Rotogravure Printing
211.5790
Rotogravure Printing Line
211.5810
Safety Relief Valve
67
211.5830
Sandblasting
211.5850
Sanding Sealers
211.5870
Screening
211.5880
Screen Printing on Paper
211.5890
Sealer
211.5910
Semi-Transparent Stains
211.5930
Sensor
211.5950
Set of Safety Relief Valves
211.5970
Sheet Basecoat
211.5980
Sheet-Fed
211.5990
Shotblasting
211.6010
Side-Seam Spray Coat
211.6025
Single Unit Operation
211.6030
Smoke
211.6050
Smokeless Flare
211.6060
Soft Coat
211.6070
Solvent
211.6090
Solvent Cleaning
211.6110
Solvent Recovery System
211.6130
Source
211.6140
Specialty Coatings
211.6145
Specialty Coatings for Motor Vehicles
211.6150
Specialty High Gloss Catalyzed Coating
211.6170
Specialty Leather
211.6190
Specialty Soybean Crushing Source
211.6210
Splash Loading
211.6230
Stack
211.6250
Stain Coating
211.6270
Standard Conditions
211.6290
Standard Cubic Foot (scf)
211.6310
Start-Up
211.6330
Stationary Emission Source
211.6350
Stationary Emission Unit
211.6355
Stationary Gas Turbine
211.6360
Stationary Reciprocating Internal Combustion Engine
211.6370
Stationary Source
211.6390
Stationary Storage Tank
211.6400
Stencil Coat
211.6410
Storage Tank or Storage Vessel
211.6420
Strippable Spray Booth Coating
211.6430
Styrene Devolatilizer Unit
211.6450
Styrene Recovery Unit
211.6470
Submerged Loading Pipe
211.6490
Substrate
211.6510
Sulfuric Acid Mist
211.6530
Surface Condenser
68
211.6540
Surface Preparation Materials
211.6550
Synthetic Organic Chemical or Polymer Manufacturing Plant
211.6570
Tablet Coating Operation
211.6580
Texture Coat
211.6590
Thirty-Day Rolling Average
211.6610
Three-Piece Can
211.6620
Three or Four Stage Coating System
211.6630
Through-the-Valve Fill
211.6650
Tooling Resin
211.6670
Topcoat
211.6690
Topcoat Operation
211.6695
Topcoat System
211.6710
Touch-Up
211.6720
Touch-Up Coating
211.6730
Transfer Efficiency
211.6750
Tread End Cementing
211.6770
True Vapor Pressure
211.6790
Turnaround
211.6810
Two-Piece Can
211.6830
Under-the-Cup Fill
211.6850
Undertread Cementing
211.6860
Uniform Finish Blender
211.6870
Unregulated Safety Relief Valve
211.6880
Vacuum Metallizing
211.6890
Vacuum Producing System
211.6910
Vacuum Service
211.6930
Valves Not Externally Regulated
211.6950
Vapor Balance System
211.6970
Vapor Collection System
211.6990
Vapor Control System
211.7010
Vapor-Mounted Primary Seal
211.7030
Vapor Recovery System
211.7050
Vapor-Suppressed Polyester Resin
211.7070
Vinyl Coating
211.7090
Vinyl Coating Line
211.7110
Volatile Organic Liquid (VOL)
211.7130
Volatile Organic Material Content (VOMC)
211.7150
Volatile Organic Material (VOM) or Volatile Organic Compound (VOC)
211.7170
Volatile Petroleum Liquid
211.7190
Wash Coat
211.7200
Washoff Operations
211.7210
Wastewater (Oil/Water) Separator
211.7230
Weak Nitric Acid Manufacturing Process
211.7250
Web
211.7270
Wholesale Purchase - Consumer
211.7290
Wood Furniture
69
211.7310
Wood Furniture Coating
211.7330
Wood Furniture Coating Line
211.7350
Woodworking
211.7400
Yeast Percentage
Appendix A Rule into Section Table
Appendix B Section into Rule Table
AUTHORITY: Implementing Sections 9, 9.1, 9.9 and 10 and authorized by Sections 27 and 28
of the Environmental Protection Act [415 ILCS 5/9, 9.1, 9.9, 10, 27 and 28].
SOURCE: Adopted as Chapter 2: Air Pollution, Rule 201: Definitions, R71-23, 4 PCB 191,
filed and effective April 14, 1972; amended in R74-2 and R75-5, 32 PCB 295, at 3 Ill. Reg. 5, p.
777, effective February 3, 1979; amended in R78-3 and 4, 35 PCB 75 and 243, at 3 Ill. Reg. 30,
p. 124, effective July 28, 1979; amended in R80-5, at 7 Ill. Reg. 1244, effective January 21,
1983; codified at 7 Ill. Reg. 13590; amended in R82-1 (Docket A) at 10 Ill. Reg. 12624, effective
July 7, 1986; amended in R85-21(A) at 11 Ill. Reg. 11747, effective June 29, 1987; amended in
R86-34 at 11 Ill. Reg. 12267, effective July 10, 1987; amended in R86-39 at 11 Ill. Reg. 20804,
effective December 14, 1987; amended in R82-14 and R86-37 at 12 Ill. Reg. 787, effective
December 24, 1987; amended in R86-18 at 12 Ill. Reg. 7284, effective April 8, 1988; amended
in R86-10 at 12 Ill. Reg. 7621, effective April 11, 1988; amended in R88-23 at 13 Ill. Reg.
10862, effective June 27, 1989; amended in R89-8 at 13 Ill. Reg. 17457, effective January 1,
1990; amended in R89-16(A) at 14 Ill. Reg. 9141, effective May 23, 1990; amended in R88-
30(B) at 15 Ill. Reg. 5223, effective March 28, 1991; amended in R88-14 at 15 Ill. Reg. 7901,
effective May 14, 1991; amended in R91-10 at 15 Ill. Reg. 15564, effective October 11, 1991;
amended in R91-6 at 15 Ill. Reg. 15673, effective October 14, 1991; amended in R91-22 at 16
Ill. Reg. 7656, effective May 1, 1992; amended in R91-24 at 16 Ill. Reg. 13526, effective August
24, 1992; amended in R93-9 at 17 Ill. Reg. 16504, effective September 27, 1993; amended in
R93-11 at 17 Ill. Reg. 21471, effective December 7, 1993; amended in R93-14 at 18 Ill. Reg.
1253, effective January 18, 1994; amended in R94-12 at 18 Ill. Reg. 14962, effective September
21, 1994; amended in R94-14 at 18 Ill. Reg. 15744, effective October 17, 1994; amended in
R94-15 at 18 Ill. Reg. 16379, effective October 25, 1994; amended in R94-16 at 18 Ill. Reg.
16929, effective November 15, 1994; amended in R94-21, R94-31 and R94-32 at 19 Ill. Reg.
6823, effective May 9, 1995; amended in R94-33 at 19 Ill. Reg. 7344, effective May 22, 1995;
amended in R95-2 at 19 Ill. Reg. 11066, effective July 12, 1995; amended in R95-16 at 19 Ill.
Reg. 15176, effective October 19, 1995; amended in R96-5 at 20 Ill. Reg. 7590, effective May
22, 1996; amended in R96-16 at 21 Ill. Reg. 2641, effective February 7, 1997; amended in R97-
17 at 21 Ill. Reg. 6489, effective May 16, 1997; amended in R97-24 at 21 Ill. Reg. 7695,
effective June 9, 1997; amended in R96-17 at 21 Ill. Reg. 7856, effective June 17, 1997;
amended in R97-31 at 22 Ill. Reg. 3497, effective February 2, 1998; amended in R98-17 at 22 Ill.
Reg.11405, effective June 22, 1998; amended in R01-9 at 25 Ill. Reg. 128, effective December
26, 2000; amended in R01-11 at 25 Ill. Reg. 4597, effective March 15, 2001; amended in R01-17
at 25 Ill. Reg. 5900, effective April 17, 2001; amended in R05-16 at 29 Ill. Reg. 8181, effective
May 23, 2005; amended in R05-11 at 29 Ill. Reg.8892, effective June 13, 2005; amended in R04-
12/20 at 30 Ill. Reg. 9654, effective May 15, 2006; amended in R07-18 at 31 Ill. Reg. 14254,
70
effective September 25, 2007; amended in R08-19 at 33 Ill. Reg. ____, effective
_________________.
Section 211.665 Auxiliary Boiler
“Auxiliary boiler” means, for purposes of Part 217, a boiler that is operated only when the main
boiler or boilers at a source are not in service and is used either to maintain building heat or to
assist in the startup of the main boiler or boilers. This term does not include emergency or
standby units and load shaving units.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.995 Circulating Fluidized Bed Combustor
“Circulating fluidized bed combustor” means, for purposes of Part 217, a fluidized bed
combustor in which the majority of the fluidized bed material is carried out of the primary
combustion zone and is transported back to the primary zone through a recirculation loop.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.1315
Combustion Tuning
“Combustion tuning” means, for purposes of Part 217, review and adjustment of a combustion
process to maintain combustion efficiency of an emission unit, as performed in accordance with
procedures provided by the manufacturer or by a trained technician.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.1435 Container Glass
“Container glass” means, for purposes of Part 217, glass made of soda-lime recipe, clear or
colored, which is pressed or blown, or both, into bottles, jars, ampoules, and other products listed
in Standard Industrial Classification 3221.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.2355 Flare
“Flare” means an open combustor without enclosure or shroud.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.2357 Flat Glass
“Flat glass” means, for purposes of Part 217, glass made of soda-lime recipe and produced into
continuous flat sheets and other products listed in Standard Industrial Classification 3211.
71
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.2625 Glass Melting Furnace
“Glass melting furnace” means, for purposes of Part 217, a unit comprising a refractory vessel in
which raw materials are charged and melted at high temperature to produce molten glass.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.3100 Industrial Boiler
“Industrial boiler” means, for purposes of Part 217, an enclosed vessel in which water is heated
and circulated either as hot water or as steam for heating or for power, or both. This term does
not include a heat recovery steam generator that captures waste heat from a combustion turbine
and boilers serving a generator that has a nameplate capacity greater than 25 MWe and produces
electricity for sale, and cogeneration units, if such boilers meet the applicability criteria under
Subpart M of Part 217.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.3355 Lime Kiln
“Lime kiln” means, for purposes of Part 217, an enclosed combustion device used to calcine lime
mud, which consists primarily of calcium carbonate, into calcium oxide.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.3475 Load Shaving Unit
“Load shaving unit” means, for purposes of Part 217, a device used to generate electricity for
sale or use during high electric demand days, including but not limited to stationary reciprocating
internal combustion engines or turbines.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.4280 Other Glass
“Other glass” means, for purposes of Part 217, glass that is neither container glass, as that term is
defined in Section 211.1435, nor flat glass, as that term is defined in Section 211.2357.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 211.5195 Process Heater
72
“Process heater” means, for purposes of Part 217, an enclosed combustion device that burns
gaseous or liquid fuels only and that indirectly transfers heat to a process fluid or a heat transfer
medium other than water. This term does not include pipeline heaters and storage tank heaters
that are primarily meant to maintain fluids at a certain temperature or viscosity.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
TITLE 35: ENVIRONMENTAL PROTECTION
SUBTITLE B: AIR POLLUTION
CHAPTER I: POLLUTION CONTROL BOARD
SUBCHAPTER C: EMISSION STANDARDS AND LIMITATIONS FOR STATIONARY
SOURCES
PART 217
NITROGEN OXIDES EMISSIONS
SUBPART A: GENERAL PROVISIONS
Section
217.100
Scope and Organization
217.101
Measurement Methods
217.102
Abbreviations and Units
217.103
Definitions
217.104
Incorporations by Reference
SUBPART B: NEW FUEL COMBUSTION EMISSION SOURCES (Repealed)
Section
217.121
New Emission Sources (Repealed)
SUBPART BC: EXISTING FUEL COMBUSTION EMISSION UNITS SOURCES
Section
217.141
Existing Emission Units Sources in Major Metropolitan Areas
SUBPART C: NO
x
GENERAL REQUIREMENTS
Section
217.150
Applicability
217.152
Compliance Date
217.154
Performance Testing
217.155
Initial Compliance Certification
217.156
Recordkeeping and Reporting
217.157
Testing and Monitoring
217.158
Emissions Averaging Plans
SUBPART D: INDUSTRIAL BOILERS
73
Section
217.160
Applicability
217.162
Exemptions
217.164
Emissions Limitations
217.165
Combination of Fuels
217.166
Methods and Procedures for Combustion Tuning
SUBPART E: PROCESS HEATERS
Section
217.180
Applicability
217.182
Exemptions
217.184
Emissions Limitations
217.185
Combination of Fuels
217.186
Methods and Procedures for Combustion Tuning
SUBPART F: GLASS MELTING FURNANCES
Section
217.200
Applicability
217.202
Exemptions
217.204
Emissions Limitations
SUBPART G: CEMENT AND LIME KILNS
Section
217.220
Applicability
217.222
Exemptions
217.224
Emissions Limitations
SUBPART H: IRON AND STEEL AND ALUMINUM MANUFACTURING
Section
217.240
Applicability
217.242
Exemptions
217.244
Emissions Limitations
SUBPART K: PROCESS EMISSION SOURCES
Section
217.301
Industrial Processes
SUBPART M: ELECTRICAL GENERATING UNITS
Section
217.340
Applicability
217.342
Exemptions
74
217.344
Emissions Limitations
217.345
Combination of Fuels
SUBPART O: CHEMICAL MANUFACTURE
Section
217.381
Nitric Acid Manufacturing Processes
SUBPART Q: STATIONARY RECIPROCATING INTERNAL COMBUSTION
ENGINES AND TURBINES
Section
217.386
Applicability
217.388
Control and Maintenance Requirements
217.390
Emissions Averaging Plans
217.392
Compliance
217.394
Testing and Monitoring
217.396
Recordkeeping and Reporting
SUBPART T: CEMENT KILNS
Section
217.400
Applicability
217.402
Control Requirements
217.404
Testing
217.406
Monitoring
217.408
Reporting
217.410
Recordkeeping
SUBPART U: NOx CONTROL AND TRADING PROGRAM FOR
SPECIFIED NOx GENERATING UNITS
Section
217.450
Purpose
217.452
Severability
217.454
Applicability
217.456
Compliance Requirements
217.458
Permitting Requirements
217.460
Subpart U NOx Trading Budget
217.462
Methodology for Obtaining NOx Allocations
217.464
Methodology for Determining NOx Allowances from the New Source Set-Aside
217.466
NOx Allocations Procedure for Subpart U Budget Units
217.468
New Source Set-Asides for “New” Budget Units
217.470
Early Reduction Credits (ERCs) for Budget Units
217.472
Low-Emitter Requirements
217.474
Opt-In Units
217.476
Opt-In Process
217.478
Opt-In Budget Units: Withdrawal from NOx Trading Program
75
217.480
Opt-In Units: Change in Regulatory Status
217.482
Allowance Allocations to Opt-In Budget Units
SUBPART V: ELECTRIC POWER GENERATION
Section
217.521
Lake of Egypt Power Plant
217.700
Purpose
217.702
Severability
217.704
Applicability
217.706
Emission Limitations
217.708
NOx Averaging
217.710
Monitoring
217.712
Reporting and Recordkeeping
SUBPART W: NOx TRADING PROGRAM FOR ELECTRICAL
GENERATING UNITS
Section
217.750
Purpose
217.752
Severability
217.754
Applicability
217.756
Compliance Requirements
217.758
Permitting Requirements
217.760
NOx Trading Budget
217.762
Methodology for Calculating NOx Allocations for Budget Electrical
Generating Units (EGUs)
217.764
NOx Allocations for Budget EGUs
217.768
New Source Set-Asides for “New” Budget EGUs
217.770
Early Reduction Credits for Budget EGUs
217.774
Opt-In Units
217.776
Opt-In Process
217.778
Budget Opt-In Units: Withdrawal from NOx Trading Program
217.780
Opt-In Units: Change in Regulatory Status
217.782
Allowance Allocations to Budget Opt-In Units
SUBPART X: VOLUNTARY NOx EMISSIONS REDUCTION PROGRAM
Section
217.800
Purpose
217.805
Emission Unit Eligibility
217.810
Participation Requirements
217.815
NOx Emission Reductions and the Subpart X NOx Trading Budget
217.820
Baseline Emissions Determination
217 825
Calculation of Creditable NOx Emission Reductions
217.830
Limitations on NOx Emission Reductions
217.835
NOx Emission Reduction Proposal
76
217.840
Agency Action
217.845
Emissions Determination Methods
217.850
Emissions Monitoring
217.855
Reporting
217.860
Recordkeeping
217.865
Enforcement
Appendix A Rule into Section Table
Appendix B Section into Rule Table
Appendix C Compliance Dates
Appendix D Non-Electrical Generating Units
Appendix E Large Non-Electrical Generating Units
Appendix F Allowances for Electrical Generating Units
Appendix G Existing Reciprocating Internal Combustion Engines Affected by the NO
x
SIP
Call
Appendix H Compliance Dates for Certain Emissions Units at Petroleum Refineries
Authority: Implementing Sections 9.9 and 10 and authorized by Sections 27 and 28 of the
Environmental Protection Act [415 ILCS 5/9.9, 10, 27 and 28].
Source: Adopted as Chapter 2: Air Pollution, Rule 207: Nitrogen Oxides Emissions, R71-23, 4
PCB 191, April 13, 1972, filed and effective April 14, 1972; amended at 2 Ill. Reg. 17, p. 101,
effective April 13, 1978; codified at 7 Ill. Reg. 13609; amended in R01-9 at 25 Ill. Reg. 128,
effective December 26, 2000; amended in R01-11 at 25 Ill. Reg. 4597, effective March 15, 2001;
amended in R01-16 and R01-17 at 25 Ill. Reg. 5914, effective April 17, 2001; amended in R07-
18 at 31 Ill. Reg. 14254, effective September 25, 2007; amended in R08-19 at 33 Ill. Reg. ____,
effective _________________.
SUBPART A: GENERAL PROVISIONS
Section 217.100 Scope and Organization
a)
This Part sets standards and limitations for emission of oxides of nitrogen from
stationary sources.
b)
Permits for sources subject to this Part may be required pursuant to 35 Ill. Adm.
Code 201 or Section 39.5 of the Act.
c)
Notwithstanding the provisions of this Part the air quality standards contained in
35 Ill. Adm. Code 243 may not be violated.
d)
These rules have been grouped for convenience of the public; the scope of each is
determined by its language and history.
(Source: Amended at 33 Ill. Reg. _____, effective ______________)
77
Section 217.104 Incorporations by Reference
The following materials are incorporated by reference. These incorporations do not include any
later amendments or editions.
a)
The phenol disulfonic acid procedures, as published in 40 CFR 60, Appendix A,
Method 7 (2000);
b)
40 CFR 96, subparts B, D, G, and H (1999);
c)
40 CFR 96.1 through 96.3, 96.5 through 96.7, 96.50 through 96.54, 96.55 (a) &
(b), 96.56 and 96.57 (1999);
d)
40 CFR 60, 72, 75 & 76 (2006);
e)
Alternative Control Techniques Document -- NO
x
Emissions from Cement
Manufacturing, EPA-453/R-94-004, U. S. Environmental Protection Agency-
Office of Air Quality Planning and Standards, Research Triangle Park, N. C.
27711, March 1994;
f)
Section 11.6, Portland Cement Manufacturing, AP-42 Compilation of Air
Emission Factors, Volume 1: Stationary Point and Area Sources, U.S.
Environmental Protection Agency-Office of Air Quality Planning and Standards,
Research Triangle Park, N. C. 27711, revised January 1995;
g)
40 CFR 60.13 (2001);
h)
40 CFR 60, Appendix A, Methods 3A, 7, 7A, 7C, 7D, 7E, 19, and 20 (2000);
i)
ASTM D6522-00, Standard Test Method for Determination of Nitrogen Oxides,
Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-
Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters
Using Portable Analyzers (2000);
jk)
Standards of Performance for Stationary Combustion Turbines, 40 CFR 60,
Subpart KKKK, 60.4400 (2006); and
kl)
Compilation of Air Pollutant Emission Factors: AP-42, Volume I: Stationary
Point and Area Sources (2000), USEPA;.
l)
40 CFR 60, Appendix A, Methods 1, 2, 3, and 4 (2007);
m)
Alternative Control Techniques Document--NO
x
Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, EPA-453/R-94-022, U. S.
Environmental Protection Agency, Office of Air and Radiation, Office of Air
Quality Planning and Standards, Research Triangle Park, N. C. 27711, March
1994;
78
n)
Alternative Control Techniques Document--NO
x
Emissions from Process Heaters
(Revised), EPA-453/R-93-034, U. S. Environmental Protection Agency, Office of
Air and Radiation, Office of Air Quality Planning and Standards, Research
Triangle Park, N. C. 27711, September 1993;
o)
Alternative Control Techniques Document--NO
x
Emissions from Glass
Manufacturing, EPA-453/R-94-037, U. S. Environmental Protection Agency,
Office of Air and Radiation, Office of Air Quality Planning and Standards,
Research Triangle Park, N. C. 27711, June 1994; and
p)
Alternative Control Techniques Document--NO
x
Emissions from Iron and Steel
Mills, EPA-453/R-94-065, U. S. Environmental Protection Agency, Office of Air
and Radiation, Office of Air Quality Planning and Standards, Research Triangle
Park, N. C. 27711, September 1994.
(Source: Amended at 33 Ill. Reg. _____, effective ______________)
SUBPART B: NEW FUEL COMBUSTION EMISSION SOURCES (Repealed)
Section 217.121 New Emission Sources (Repealed)
No person shall cause or allow the emission of nitrogen oxides (NO
X
) into the atmosphere in any
one hour period from any new fuel combustion emission source with an actual heat input equal
to or greater than 73.2 MW (250 mmbtu/hr) to exceed the following standards and limitations:
a)
For gaseous fossil fuel firing, 0.310 kg/MW-hr (0.20 lbs/mmbtu) of actual heat
input;
b)
For liquid fossil fuel firing, 0.464 kg/MW-hr (0.30 lbs/mmbtu) of actual heat
input;
c)
For dual gaseous and liquid fossil fuel firing, 0.464 kg/MW-hr (0.30 lbs/mmbtu)
of actual heat input;
d)
For solid fossil fuel firing, 1.08 kg/MW-hr (0.7 lbs./mmbtu) of actual heat input;
e)
For fuel combustion emission sources burning simultaneously any combination of
solid, liquid and gaseous fossil fuels, an allowable emission rate shall be
determined by the following equation:
E = (AG + BL + CS) Q
Where:
E = Allowable nitrogen oxides emissions rate
Q = Actual heat input derived from all fossil fuels
G = Percent of actual heat input derived from gaseous fossil fuel
79
L = Percent of actual heat input derived from liquid fossil fuel
S = Percent of actual heat input derived from solid fossil fuel
G + L + S = 100.0
and, where A, B, C and appropriate metric and English units are determined from
the following table:
Metric
English
E
kg/hr
lbs/hr
Q
MW
mmbtu/hr
A
0.023
0.003
B
0.023
0.003
C
0.053
0.007
(Source: Repealed at 33 Ill. Reg. _____, effective ______________)
SUBPART B C: EXISTING FUEL COMBUSTION EMISSION UNITS SOURCES
Section 217.141 Existing Emission Units Sources in Major Metropolitan Areas
No person shall cause or allow the emission of nitrogen oxides into the atmosphere in any one
hour period from any existing fuel combustion emission unit source with an actual heat input
equal to or greater than 73.2 MW (250 mmbtu/hr), located in the Chicago or St. Louis (Illinois)
major metropolitan areas to exceed the following limitations:
a)
For gaseous and/or liquid fossil fuel firing, 0.46 kg/MW-hr (0.3 lbs/mmbtu) of
actual heat input;
b)
For solid fossil fuel firing, 1.39 kg/MW-hr (0.9 lbs/mmbtu) of actual heat input;
c)
For fuel combustion emission units sources burning simultaneously any
combination of solid, liquid and gaseous fuel, the allowable emission rate shall be
determined by the following equation:
E = (AG + BL + CS) Q
Where:
E = allowable nitrogen oxides emissions
Q = actual heat input
G = percent of actual heat input derived from gaseous fossil fuel
L = percent of actual heat input derived from liquid fossil fuel
S = percent of actual heat input derived from solid fossil fuel
G + L + S = 100.0
and, where A, B, C and appropriate metric and English units are determined from the
following table:
80
Metric
English
E
kg/hr
lbs/hr
Q
MW
mmbtu/hr
A
0.023
0.003
B
0.023
0.003
C
0.068
0.009
d)
Exceptions: This Section rule shall not apply to the following:
1)
Existing existing fuel combustion units sources which are either cyclone
fired boilers burning solid or liquid fuel, or horizontally opposed fired
boilers burning solid fuel ; or.
2)
Emission units that are subject to the emissions limitations of Subpart D,
E, F, G, H, M, or Q of this Part.
(Source: Amended at 33 Ill. Reg. _____, effective ______________)
SUBPART C: NO
x
GENERAL
REQUIREMENTS
Section 217.150 Applicability
a)
The provisions of this Subpart and Subparts D, E, F, G, H, and M of this Part
apply to the following:
1)
All sources that are located in either one of the following areas and that
emit or have the potential to emit NO
x
in an amount equal to or greater
than 100 tons per year:
A)
The area composed of the Chicago area counties of Cook, DuPage,
Kane, Lake, McHenry, and Will, the Townships of Aux Sable and
Goose Lake in Grundy County, and the Township of Oswego in
Kendall County; or
B)
The area composed of the Metro East area counties of Jersey,
Madison, Monroe, and St. Clair, and the Township of Baldwin in
Randolph County; and
2)
Any industrial boiler, process heater, glass melting furnace, cement kiln,
lime kiln, iron and steel reheat, annealing, or galvanizing furnace,
aluminum reverberatory or crucible furnace, or fossil fuel-fired stationary
boiler at such sources described in subsection (a)(1) of this Section that
emits NO
x
in an amount equal to or greater than 15 tons per year and equal
to or greater than five tons per ozone season.
81
3)
For purposes of this Section, “potential to emit” means the quantity of
NO
x
that potentially could be emitted by a stationary source before add-on
controls based on the design capacity or maximum production capacity of
the source and 8,760 hours per year or the quantity of NO
x
that potentially
could be emitted by a stationary source as established in a federally
enforceable permit.
b)
If a source ceases to fulfill the emissions criteria of subsection (a) of this Section,
the requirements of this Subpart and Subpart D, E, F, G, H, or M of this Part
continue to apply to any emission unit that was ever subject to the provisions of
Subpart D, E, F, G, H, or M of this Part.
c)
The provisions of this Subpart do not apply to afterburners, flares, and
incinerators.
d)
Where a construction permit, for which the application was submitted to the
Agency prior to the adoption of this Subpart, is issued that relies on decreases in
emissions of NO
x
from existing emission units for purposes of netting or emission
offsets, such NO
x
decreases remain creditable notwithstanding any requirements
that may apply to the existing emission units pursuant to this Subpart and Subpart
D, E, F, G, H, or M of this Part .
e)
The owner or operator of an emission unit that is subject to this Subpart and
Subpart D, E, F, G, H, or M of this Part must operate such unit in a manner
consistent with good air pollution control practice to minimize NO
x
emissions.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 217.152 Compliance Date
a)
Compliance with the requirements of Subparts D, E, F, G, H, and M by an owner
or operator of an emission unit that is subject to Subpart D, E, F, G, H, or M is
required beginning January 1, 2012.
b)
Notwithstanding subsection (a) of this Section, compliance with the requirements
of Subpart F of this Part by an owner or operator of an emission unit subject to
Subpart F of this Part shall be extended until December 31, 2014, if such units are
required to meet emissions limitations for NOx, as measured using a continuous
emissions monitoring system, and included within a legally enforceable order on
or before December 31, 2009, whereby such emissions limitations are less than 30
percent of the emissions limitations set forth under Section 217.204 of Subpart F
of this Part.
c)
Notwithstanding subsection (a) of this Section, the owner or operator of emission
units subject to Subpart D or E of this Part and located at a petroleum refinery
must comply with the requirements of this Subpart and Subpart D or E of this Part,
82
as applicable, for those emission units beginning January 1, 2012, except that the
owner or operator of emission units listed in Appendix H must comply with the
requirements of this Subpart, including the option of demonstrating compliance
with the applicable Subpart through an emissions averaging plan under Section
217.158 of this Subpart, and Subpart D or E of this Part, as applicable, for the
listed emission units beginning on the dates set forth in Appendix H. With Agency
approval, the owner or operator of emission units listed in Appendix H may elect
to comply with the requirements of this Subpart and Subpart D or E of this Part, as
applicable, by reducing the emissions of emission units other than those listed in
Appendix H, provided that the emissions limitations of such other emission units
are equal to or more stringent than the applicable emissions limitations set forth in
Subpart D or E of this Part, as applicable, by the dates set forth in Appendix H.
(Source: Added at 33 Ill. Reg. _____, effective ______________)
Section 217.154 Performance Testing
a)
Performance testing of NO
x
emissions for emission units constructed on or before
July 1, 2011, and subject to Subpart D, E, F, G, or H of this Part must be
conducted in accordance with Section 217.157 of this Subpart. This subsection
does not apply to owners and operators of emission units demonstrating
compliance through a continuous emissions monitoring system.
b)
Performance testing of NO
x
emissions for emission units for which construction
or modification occurs after July 1, 2011, and that are subject to Subpart D, E, F,
G, or H of this Part must be conducted within 60 days of achieving maximum
operating rate but no later than 180 days after initial startup of the new or
modified emission unit, in accordance with Section 217.157 of this Subpart. This
subsection does not apply to owners and operators of emission units
demonstrating compliance through a continuous emissions monitoring system.
c)
Notification of the initial startup of an emission unit subject to subsection (b) of
this Section must be provided to the Agency no later than 30 days after initial
startup.
d)
The owner or operator of an emission unit subject to subsection (a) or (b) of this
Section must notify the Agency of the scheduled date for the performance testing
at least 30 days in writing before such date and five days before such date.
e)
If demonstrating compliance through an emissions averaging plan, at least 30
days before changing the method of compliance, the owner or operator of an
emission unit must submit a written notification to the Agency describing the new
method of compliance, the reason for the change in the method of compliance,
and the scheduled date for performance testing, if required. Upon changing the
method of compliance, the owner or operator of an emission unit must submit to
83
the Agency a revised compliance certification that meets the requirements of
Section 217.155 of this Subpart.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.155 Initial Compliance Certification
a)
By the applicable compliance date set forth under Section 217.152 of this Subpart,
an owner or operator of an emission unit subject to Subpart D, E, F, G, or H of
this Part who is not demonstrating compliance through the use of a continuous
emissions monitoring system must certify to the Agency that the emission unit
will be in compliance with the applicable emissions limitation of Subpart D, E, F,
G, or H of this Part beginning on such applicable compliance date. The
performance testing certification must include the results of the performance
testing performed in accordance with Sections 217.154(a) and (b) of this Subpart
and the calculations necessary to demonstrate that the subject emission unit will
be in initial compliance.
b)
By the applicable compliance date set forth under Section 217.152 of this Subpart,
an owner or operator of an emission unit subject to Subpart D, E, F, G, H, or M of
this Part who is demonstrating compliance through the use of a continuous
emissions monitoring system must certify to the Agency that the affected emission
units will be in compliance with the applicable emissions limitation of Subpart D,
E, F, G, H, or M of this Part beginning on such applicable compliance date. The
compliance certification must include a certification of the installation and
operation of a continuous emissions monitoring system required under Section
217.157 of this Subpart and the monitoring data necessary to demonstrate that the
subject emission unit will be in initial compliance.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.156 Recordkeeping and Reporting
a)
The owner or operator of an emission unit subject to Subpart D, E, F, G, H, or M
of this Part must keep and maintain all records used to demonstrate initial
compliance and ongoing compliance with the requirements of those Subparts.
1)
Except as otherwise provided under this Subpart or Subpart D, E, F, G, H,
or M of this Part, copies of such records must be submitted by the owner
or operator of the source to the Agency within 30 days after receipt of a
written request by the Agency.
2)
Such records must be kept at the source and maintained for at least five
years and must be available for immediate inspection and copying by the
Agency.
84
b)
The owner or operator of an emission unit subject to Subpart D, E, F, G, H, or M
of this Part must maintain records that demonstrate compliance with the
requirements of Subpart D, E, F, G, H, or M, as applicable, that include the
following:
1)
Identification, type (e.g., gas-fired), and location of each unit.
2)
Calendar date of the record.
3)
Monthly, seasonal, and annual operating hours.
4)
Type and quantity of each fuel used monthly, seasonally, and annually.
5)
Product and material throughput, as applicable.
6)
Reports for all applicable emissions tests for NO
x
conducted on the unit,
including results.
7)
The date, time, and duration of any startup, shutdown, or malfunction in
the operation of any emission unit subject to Subpart D, E, F, G, H, or M
of this Part or any emissions monitoring equipment. The records must
include a description of the malfunction and corrective maintenance
activity.
8)
A log of all maintenance and inspections related to the unit’s air pollution
control equipment for NO
x
that is performed on the unit.
9)
A log for the NO
x
monitoring device, if present, including periods when
not in service and maintenance and inspection activities that are performed
on the device.
10)
Identification of time periods for which operating conditions and pollutant
data were not obtained by the continuous emissions monitoring system
including the reasons for not obtaining sufficient data and a description of
corrective actions taken.
11)
If complying with the emissions averaging plan provisions of Section
217.158 of this Subpart, copies of the calculations used to demonstrate
compliance with the ozone season and annual control period limitations,
noncompliance reports for the ozone season, and ozone and annual control
period compliance reports submitted to the Agency.
c)
The owner or operator of an industrial boiler subject to Subpart D of this Part
must maintain records in order to demonstrate compliance with the combustion
tuning requirements under Section 217.166 of this Part.
85
d)
The owner or operator of a process heater subject to Subpart E of this Part must
maintain records in order to demonstrate compliance with the combustion tuning
requirements under Section 217.186 of this Part.
e)
The owner or operator of an emission unit subject to Subpart D, E, F, G, H, or M
of this Part must maintain records in order to demonstrate compliance with the
testing and monitoring requirements under Section 217.157 of this Subpart.
f)
The owner or operator of an emission unit subject to Subpart D, E, F, G, or H of
this Part must provide the following information with respect to performance
testing pursuant to Section 217.157:
1)
Submit a testing protocol to the Agency at least 60 days prior to testing;
2)
Notify the Agency at least 30 days in writing prior to conducting
performance testing for NO
x
emissions and five days prior to such
testing;
3)
Not later than 60 days after the completion of the test, submit the results of
the test to the Agency; and
4)
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 test as
scheduled, the owner or operator of the unit must notify the Agency as
soon as practicable of the delay in the original test date, either by
providing at least seven days’ prior notice of the rescheduled date of the
test or by arranging a new test date with the Agency by mutual agreement.
g)
The owner or operator of an emission unit subject to Subpart D, E, F, G, H, or M
of this Part must notify the Agency of any exceedances of an applicable emissions
limitation of Subpart D, E, F, G, H, or M of this Part by sending the applicable
report with an explanation of the causes of such exceedances to the Agency
within 30 days following the end of the applicable compliance period in which the
emissions limitation was not met.
h)
Within 30 days of the receipt of a written request by the Agency, the owner or
operator of an emission unit that is exempt from the requirements of Subpart D, E,
F, G, H, or M of this Part must submit records that document that the emission
unit is exempt from those requirements to the Agency.
i)
If demonstrating compliance through an emissions averaging plan, by March 1
following the applicable calendar year, the owner or operator must submit to the
Agency a report that demonstrates the following:
1)
For all units that are part of the emissions averaging plan, the total mass of
allowable NOx emissions for the ozone season and for the annual control
86
period;
2)
The total mass of actual NOx emissions for the ozone season and annual
control period for each unit included in the averaging plan;
3)
The calculations that demonstrate that the total mass of actual NOx
emissions are less than the total mass of allowable NOx emissions using
equations in Section 217.158(f) of this Subpart; and
4)
The information required to determine the total mass of actual NOx
emissions.
j)
The owner or operator of an emission unit subject to the requirements of Section
217.157 of this Subpart and demonstrating compliance through the use of a
continuous emissions monitoring system must submit to the Agency a report
within 30 days after the end of each calendar quarter. This report must include
the following:
1)
Information identifying and explaining the times and dates when
continuous emissions monitoring for NO
x
was not in operation, other than
for purposes of calibrating or performing quality assurance or quality
control activities for the monitoring equipment; and
2)
An excess emissions and monitoring systems performance report in
accordance with the requirements of 40 CFR 60.7(c) and (d) and 60.13, or
40 CFR Part 75, or an alternate procedure approved by the Agency and
USEPA.
k)
The owner or operator of an emission unit subject to Subpart M of this Part must
comply with the compliance certification and recordkeeping and reporting
requirements in accordance with 40 CFR Part 96, or an alternate procedure
approved by the Agency and USEPA.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.157 Testing and Monitoring
a)
Industrial Boilers and Process Heaters
1)
The owner or operator of an industrial boiler subject to Subpart D of this
Part with a rated heat input capacity greater than 250 mmBtu/hr must
install, calibrate, maintain, and operate a continuous emissions monitoring
system on the emission unit for the measurement of NO
x
emissions
discharged into the atmosphere in accordance with 40 CFR Part 75, as
incorporated by reference in Section 217.104 of this Part.
87
2)
The owner or operator of an industrial boiler subject to Subpart D of this
Part with a rated heat input capacity greater than 100 mmBtu/hr but less
than or equal to 250 mmBtu/hr must install, calibrate, maintain, and
operate a continuous emissions monitoring system on such emission unit
for the measurement of NO
x
emissions discharged into the atmosphere in
accordance with 40 CFR Part 60, Subpart A, and Appendix B,
Performance Specifications 2 and 3, and Appendix F, Quality Assurance
Procedures, as incorporated by reference in Section 217.104 of this Part.
3)
The owner or operator of a process heater subject to Subpart E of this Part
with a rated heat input capacity greater than 100 mmBtu/hr must install,
calibrate, maintain, and operate a continuous emissions monitoring system
on the emission unit for the measurement of NO
x
emissions discharged
into the atmosphere must monitor emissions of NO
x
discharged into the
atmosphere in accordance with 40 CFR Part 60, Subpart A, and Appendix
B, Performance Specifications 2 and 3, and Appendix F, Quality
Assurance Procedures, as incorporated by reference in Section 217.104 of
this Part.
4)
If demonstrating compliance through an emissions averaging plan, the
owner or operator of an industrial boiler subject to Subpart D of this Part,
or a process heater subject to Subpart E of this Part, with a rated heat input
capacity less than or equal to 100 mmBtu/hr and not demonstrating
compliance through a continuous emissions monitoring system must have
an initial performance test conducted pursuant to subsection (a)(4)(B) of
this Section and Section 217.154 of this Subpart.
A)
An owner or operator of an industrial boiler or process heater must
have subsequent performance tests conducted pursuant to
subsection (a)(4)(B) of this Section at least once every five years.
When in the opinion of the Agency or USEPA, it is necessary to
conduct testing to demonstrate compliance with Section 217.164 or
217.184, as applicable, of this Part, the owner or operator of an
industrial boiler or process heater must, at his or her own expense,
have such test conducted in accordance with the applicable test
methods and procedures specified in this Section within 90 days of
receipt of a notice to test from the Agency or USEPA.
B)
The owner or operator of an industrial boiler or process heater
must have a performance test conducted using 40 CFR Part 60,
Subpart A, and Appendix A, Method 1, 2, 3, 4, 7E, or 19, as
incorporated by reference in Section 217.104 of this Part, or other
alternative USEPA methods approved by the Agency. Each
performance test must consist of three separate runs, each lasting a
minimum of 60 minutes. NO
x
emissions must be measured while
the industrial boiler is operating at maximum operating capacity or
88
while the process heater is operating at normal maximum load. If
the industrial boiler or process heater has combusted more than one
type of fuel in the prior year, a separate performance test is
required for each fuel. If a combination of fuels is typically used, a
performance test may be conducted with Agency approval on such
combination of fuels typically used. Except as provided under
subsection (e) of this Section, this subsection (a)(4)(B) of this
Section does not apply if such owner or operator is demonstrating
compliance with an emissions limitation through a continuous
emissions monitoring system under subsection (a)(1), (a)(2), (a)(3),
or (a)(5) of this Section.
5)
Instead of complying with the requirements of subsections (a)(4),
(a)(4)(A), and (a)(4)(B) of this Section, an owner or operator of an
industrial boiler subject to Subpart D of this Part, or a process heater
subject to Subpart E of this Part, with a rated heat input capacity less than
or equal to 100 mmBtu/hr may install and operate a continuous emissions
monitoring system on such emission unit in accordance with the
applicable requirements of 40 CFR Part 60, Subpart A, and Appendix B,
Performance Specifications 2 and 3, and Appendix F, Quality Assurance
Procedures, as incorporated by reference in Section 217.104 of this Part.
The continuous emissions monitoring system must be used to demonstrate
compliance with the applicable emissions limitation or emissions
averaging plan on an ozone season and annual basis.
6)
Notwithstanding subsection (a)(2) of this Section, the owner or operator of
an auxiliary boiler subject to Subpart D of this Part with a rated heat input
capacity less than or equal to 250 mmBtu/hr and a capacity factor of less
than or equal to 20% is not required to install, calibrate, maintain, and
operate a continuous emissions monitoring system on such boiler for the
measurement of NO
x
emissions discharged into the atmosphere, but must
comply with the performance test requirements under subsections (a)(4),
(a)(4)(A), and (a)(4)(B) of this Section.
b)
Glass Melting Furnaces; Cement Kilns; Lime Kilns; Iron and Steel Reheat,
Annealing, and Galvanizing Furnaces; and Aluminum Reverberatory and
Crucible Furnaces
1)
An owner or operator of a glass melting furnace subject to Subpart F of
this Part, cement kiln or lime kiln subject to Subpart G of this Part, iron
and steel reheat, annealing, or galvanizing furnace subject to Subpart H of
this Part, or aluminum reverberatory or crucible furnace subject to Subpart
H of this Part that has the potential to emit NO
x
in an amount equal to or
greater than one ton per day must install, calibrate, maintain, and operate a
continuous emissions monitoring system on such emission unit for the
measurement of NO
x
emissions discharged into the atmosphere in
89
accordance with 40 CFR Part 60, Subpart A, and Appendix B,
Performance Specifications 2 and 3, and Appendix F, Quality Assurance
Procedures, as incorporated by reference in Section 217.104 of this Part.
2)
An owner or operator of a glass melting furnace subject to Subpart F of
this Part, cement kiln or lime kiln subject to Subpart G of this Part, iron
and steel reheat, annealing, or galvanizing furnace subject to Subpart H of
this Part, or aluminum reverberatory or crucible furnace subject to Subpart
H of this Part that has the potential to emit NO
x
in an amount less than one
ton per day must have an initial performance test conducted pursuant to
subsection (b)(4) of this Section and Section 217.154 of this Subpart.
3)
An owner or operator of a glass melting furnace subject to Subpart F of
this Part, cement kiln or lime kiln subject to Subpart G of this Part, iron
and steel reheat, annealing, galvanizing furnace subject to Subpart H of
this Part, or aluminum reverberatory or crucible furnace subject to Subpart
H of this Part that has the potential to emit NO
x
in an amount less than one
ton per day must have subsequent performance tests conducted pursuant to
subsection (b)(4) of this Section as follows:
A)
For all glass melting furnaces subject to Subpart F of this Part,
cement kilns or lime kilns subject to Subpart G of this Part, iron
and steel reheat, annealing, or galvanizing furnace subject to
Subpart H of this Part, or aluminum reverberatory or crucible
furnaces subject to Subpart H of this Part, including all such units
included in an emissions averaging plan, at least once every five
years; and
B)
4)
The owner or operator of a glass melting furnace, cement kiln, or lime kiln
must have a performance test conducted using 40 CFR Part 60, Subpart A,
and Appendix A, Methods 1, 2, 3, 4, and 7E, as incorporated by reference
in Section 217.104 of this Part, or other alternative USEPA methods
approved by the Agency. The owner or operator of an iron and steel
reheat, annealing, or galvanizing furnace, or aluminum reverberatory or
crucible furnace must have a performance test conducted using 40 CFR
Part 60, Subpart A, and Appendix A, Method 1, 2, 3, 4, 7E, or 19, as
When in the opinion of the Agency or USEPA, it is necessary to
conduct testing to demonstrate compliance with Section 217.204,
217.224, or 217.244, of this Part, as applicable, the owner or
operator of a glass melting furnace, cement kiln, lime kiln, iron and
steel reheat, annealing, or galvanizing furnace, or aluminum
reverberatory or crucible furnace must, at his or her own expense,
have such test conducted in accordance with the applicable test
methods and procedures specified in this Section within 90 days of
receipt of a notice to test from the Agency or USEPA.
90
incorporated by reference in Section 217.104 of this Part, or other
alternative USEPA methods approved by the Agency. Each performance
test must consist of three separate runs, each lasting a minimum of 60
minutes. NO
x
emissions must be measured while the glass melting
furnace, cement kiln, lime kiln, iron and steel reheat, annealing, or
galvanizing furnace, or aluminum reverberatory or crucible furnace is
operating at maximum operating capacity. If the glass melting furnace,
cement kiln, lime kiln, iron and steel reheat, annealing, or galvanizing
furnace, or aluminum reverberatory or crucible furnace has combusted
more than one type of fuel in the prior year, a separate performance test is
required for each fuel. Except as provided under subsection (e) of this
Section, this subsection (b)(4) of this Section does not apply if such owner
or operator is demonstrating compliance with an emissions limitation
through a continuous emissions monitoring system under subsection (b)(1)
or (b)(5) of this Section.
5)
Instead of complying with the requirements of subsections (b)(2), (b)(3),
and (b)(4) of this Section, an owner or operator of a glass melting furnace
subject to Subpart F of this Part, cement kiln or lime kiln subject to
Subpart G of this Part, iron and steel reheat, annealing, or galvanizing
furnace subject to Subpart H of this Part, or aluminum reverberatory or
crucible furnace subject to Subpart H of this Part that has the potential to
emit NO
x
in an amount less than one ton per day may install and operate a
continuous emissions monitoring system on such emission unit in
accordance with the applicable requirements of 40 CFR Part 60, Subpart
A, and Appendix B, Performance Specifications 2 and 3, and Appendix F,
Quality Assurance Procedures, as incorporated by reference in Section
217.104 of this Part. The continuous emissions monitoring system must
be used to demonstrate compliance with the applicable emissions
limitation or emissions averaging plan on an ozone season and annual
basis.
c)
Fossil Fuel-Fired Stationary Boilers. The owner or operator of a fossil fuel-fired
stationary boiler subject to Subpart M of this Part must install, calibrate, maintain,
and operate a continuous emissions monitoring system on such emission unit for
the measurement of NO
x
emissions discharged into the atmosphere in accordance
with 40 CFR Part 96, Subpart H.
d)
Common Stacks. If two or more emission units subject to Subpart D, E, F, G, H,
M, or Q of this Part are served by a common stack and the owner or operator of
such emission units is operating a continuous emissions monitoring system, the
owner or operator may, with written approval from the Agency, utilize a single
continuous emissions monitoring system for the combination of emission units
subject to Subpart D, E, F, G, H, M , or Q of this Part that share the common
stack, provided such emission units are subject to an emissions averaging plan
under this Part.
91
e)
Compliance with the continuous emissions monitoring system (CEMS)
requirements by an owner or operator of an emission unit who is required to
install, calibrate, maintain, and operate a CEMS on the emission unit under
subsection (a)(1), (a)(2), (a)(3), or (b)(1) of this Section, or who has elected to
comply with the CEMS requirements under subsection (a)(5) or (b)(5) of this
Section, or who has elected to comply with the predictive emission monitoring
system (PEMS) requirements under subsection (f) of this Section, is required by
the following dates:
1)
For the owner or operator of an emission unit that is subject to a
compliance date in calendar year 2012 under Section 217.152 of this
Subpart, compliance with the CEMS or PEMS requirements, as
applicable, under this Section for such emission unit is required by
December 31, 2012, provided that during the time between the compliance
date and December 31, 2012, the owner or operator must comply with the
applicable performance test requirements under this Section and the
applicable recordkeeping and reporting requirements under this Subpart.
For the owner or operator of an emission unit that is in compliance with
the CEMS or PEMS requirements, as applicable, under this Section on
January 1, 2012, such owner or operator is not required to comply with the
performance test requirements under this Section.
2)
For the owner or operator of an emission unit that is subject to a
compliance date in a calendar year other than calendar year 2012 under
Section 217.152 of this Subpart, compliance with the CEMS or PEMS
requirements, as applicable, under this Section for such emission unit is
required by the applicable compliance date, and such owner or operator is
not required to comply with the performance test requirements under this
Section.
f)
As an alternative to complying with the requirements of this Section, other than
the requirements under subsections (a)(1) and (c) of this Section, the owner or
operator of an emission unit who is not otherwise required by any another statute,
regulation, or enforceable order to install, calibrate, maintain, and operate a
CEMS on the emission unit may comply with the specifications and test
procedures for a predictive emission monitoring system (PEMS) on the emission
unit for the measurement of NO
x
emissions discharged into the atmosphere in
accordance with the requirements of 40 CFR Part 60, Subpart A, and Appendix B,
Performance Specification 16. The PEMS must be used to demonstrate
compliance with the applicable emissions limitation or emissions averaging plan
on an ozone season and annual basis.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.158 Emissions Averaging Plans
92
a)
Notwithstanding any other emissions averaging plan provisions under this Part, an
owner or operator of a source with certain emission units subject to Subpart D, E,
F, G, H, or M of this Part, or subject to Subpart Q of this Part that are located in
either one of the areas set forth under Section 217.150(a)(1)(A) or (B) of this
Subpart, may demonstrate compliance with the applicable Subpart through an
emissions averaging plan. An emissions averaging plan can only address
emission units that are located at one source and each unit may only be covered
by one emissions averaging plan. Such emission units at the source are affected
units and are subject to the requirements of this Section.
1)
The following units may be included in an emissions averaging plan:
A)
Units that commenced operation on or before January 1, 2002.
B)
Units that the owner or operator may claim as exempt pursuant to
Section 217.162, 217.182, 217.202, 217.222, 217.242, or 217.342,
of this Part, as applicable, 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 emissions
limitations, and testing, monitoring, recordkeeping and reporting
requirements.
C)
Units that commence operation after January 1, 2002, if the unit
replaces a unit that commenced operation on or before January 1,
2002, or it replaces a unit that replaced a unit that commenced
operation on or before January 1, 2002. The new unit must be
used for the same purpose and have substantially equivalent or less
process capacity or be permitted for less NO
x
emissions on an
annual basis than the actual NO
x
emissions of the unit or units that
are replaced. Within 90 days after permanently shutting down a
unit that is replaced, the owner or operator of such unit must
submit a written request to withdraw or amend the applicable
permit to reflect that the unit is no longer in service before the
replacement unit may be included in an emissions averaging plan.
2)
The following types of units may not be included in an emissions
averaging plan:
A)
Units that commence operation after January 1, 2002, except as
provided by subsection (a)(1)(C) of this Section.
B)
Units that the owner or operator is claiming are exempt pursuant to
Section 217.162, 217.182, 217.202, 217.222, 217.242, or 217.342,
of this Part, as applicable.
93
C)
Units that are required to meet emission limits or control
requirements for NO
x
as provided for in an enforceable order,
unless such order allows for emissions averaging.
b)
An owner or operator must submit an emissions averaging plan to the Agency by
January 1, 2012. The plan must include, but is not limited to, the following:
1)
The list of affected units included in the plan by unit identification
number; and
2)
A sample calculation demonstrating compliance using the methodology
provided in subsection (f) of this Section for the ozone season (May 1
through September 30) and calendar year (January 1 through December
31).
c)
An owner or operator may amend an emissions averaging plan only once per
calendar year. Such an amended plan must be submitted to the Agency by
January 1 of the applicable calendar year. If an amended plan is not received by
the Agency by January 1 of the applicable calendar year, the previous year’s plan
will be the applicable emissions averaging plan.
d)
Notwithstanding subsection (c) of this Section:
1)
If a unit that is listed in an emissions averaging plan is taken out of
service, the owner or operator must submit to the Agency, within 30 days
of such occurrence, an updated emissions averaging plan; or
2)
If a unit that was exempt from the requirements of Subpart D, E, F, G, H,
or M of this Part pursuant to Section 217.162, 217.182, 217.202, 217.222,
217.242, or 217.342, of this Part, as applicable, no longer qualifies for an
exemption, the owner or operator may amend its existing averaging plan
to include such unit within 30 days of the unit no longer qualifying for the
exemption.
e)
An owner or operator must:
1)
Demonstrate compliance for 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 monitoring data or test data determined pursuant to Section 217.157 of
this Subpart, and the actual hours of operation for the applicable averaging
plan period; and
2)
Submit to the Agency by March 1 following each calendar year, a
compliance report containing the information required by Section
94
217.156(i) of this Subpart.
f)
The total mass of actual NOx emissions from the units listed in the emissions
averaging plan must be equal to or less than the total mass of allowable NOx
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
i
act i j
k
1
j
( , )
N
act
=
1
EM
∑
=
∑
=
n
i
all i j
k
1
j
( , )
N
all
=
1
EM
N
act
=
Total sum of the actual NOx mass emissions from units
included in the averaging plan for each fuel used (tons per
ozone season and year).
N
all
=
Total sum of the allowable NOx mass emissions from units
included in the averaging plan for each fuel used (tons per
ozone season and year).
EM
act(i)
=
Total mass of actual NO
X
emissions in tons for a unit as
determined in subsection (f)(1) of this Section.
i
=
Subscript denoting an individual unit.
j
=
Subscript denoting the fuel type used.
k
=
Number of different fuel types.
n
=
Number of different units in the averaging plan.
EM
all(i)
=
Total mass of allowable NOx emissions in tons for a unit as
determined in subsection (f)(2) of this Section.
For each unit in the averaging plan, and each fuel used by such unit,
determineactual and allowable NOx emissions using the following equations:
1)
Actual emissions must be determined as follows:
When emission limits are prescribed in lb/mmBtu,
EM
act(i)
=
E
act(i)
x H
i
/2000
When emission limits are prescribed in lb/ton of processed
product,
EM
act(i)
=
E
act(i)
x P
i
/2000
2)
Allowable emissions must be determined as follows:
When emission limits are prescribed in lb/mmBtu,
95
EM
all(i)
=
E
all(i)
x H
i
/2000
When emission limits are prescribed in lb/ton of processed
product,
EM
all(i)
=
E
all(i)
x P
i
/2000
Where:
EM
act(i)
=
Total mass of actual NOx emissions in tons for a
unit.
EM
all(i)
=
Total mass of allowable NOx emissions in tons for
a unit.
E
act
=
Actual NOx emission rate (lbs/mmBtu or lbs/ton of
product) as determined by a performance test,
continuous emissions monitoring system, or an
alternative method approved by the Agency.
E
all
=
Allowable NOx emission rate (lbs/mmBtu or lbs/ton
of product) as provided in Section 217.164,
217.184, 217.204, 217.224, 217.244, or 217.344, as
applicable, of this Part. For an affected industrial
boiler subject to Subpart D of this Part, or process
heater subject to Subpart E of this Part, with a rated
heat input capacity less than or equal to 100
mmBtu/hr demonstrating compliance through an
emissions averaging plan, the allowable NOx
emission rate is to be determined from a
performance test after such boiler or heater has
undergone combustion tuning. For all other units in
an emissions averaging plan, an uncontrolled NOx
emission rate from USEPA’s AP-42, as
incorporated by reference in Section 217.104 of this
Part, or an uncontrolled NOx emission rate as
determined by an alternative method approved by
the Agency will be used.
H
=
Heat input (mmBtu/ozone season or mmBtu/year)
calculated from fuel flow meter and the heating
value of the fuel used.
P
=
weight in tons of processed product.
g)
An owner or operator of an emission unit subject to Subpart Q of this Part that is
located in either one of the areas set forth under Section 217.150(a)(1)(A) or (B)
that is complying through an emissions averaging plan under this Section must
comply with the applicable provisions for determining actual and allowable
96
emissions under Section 217.390 of Subpart Q of this Part, the testing and
monitoring requirements under Section 217.394 of Subpart Q of this Part, and the
recordkeeping and reporting requirements under Section 217.396 of Subpart Q of
this Part.
h)
The owner or operator of an emission unit located at a petroleum refinery who is
demonstrating compliance with an applicable Subpart through an emissions
averaging plan under this Section may exclude from the calculation demonstrating
compliance those time periods when an emission unit included in the emissions
averaging plan is shut down for a maintenance turnaround, provided that such
owner or operator notify the Agency in writing at least 30 days in advance of the
shutdown of the emission unit for the maintenance turnaround and the shutdown
of the emission unit does not exceed 45 days per ozone season or calendar year
and NO
x
pollution control equipment, if any, continues to operate on all other
emission units operating during the maintenance turnaround.
i)
The owner or operator of an emission unit that combusts a combination of coke
oven gas and other gaseous fuels and located at a source that manufactures iron
and steel who is demonstrating compliance with an applicable Subpart through an
emissions averaging plan under this Section may exclude from the calculation
demonstrating compliance those time periods when the coke oven gas
desulfurization unit included in the emissions averaging plan is shut down for
maintenance, provided that such owner or operator notify the Agency in writing at
least 30 days in advance of the shutdown of the coke oven gas desulfurization unit
for maintenance and such shutdown does not exceed 35 days per ozone season or
calendar year and NO
x
pollution control equipment, if any, continues to operate
on all other emission units operating during the maintenance period..
(Source: Added at 33 Ill. Reg. ____, effective ______________)
SUBPART D: INDUSTRIAL BOILERS
Section 217.160 Applicability
a)
The provisions of Subpart C of this Part and this Subpart apply to all industrial
boilers located at sources subject to this Subpart pursuant to Section 217.150 of
this Part, except as provided in subsections (b) and (c) of this Section.
b)
The provisions of this Subpart do not apply to boilers serving a generator that has
a nameplate capacity greater than 25 MWe and produces electricity for sale, and
cogeneration units, as that term is defined in Section 225.130 of Part 225, if such
boilers or cogeneration units are subject to the CAIR NO
x
Trading Programs
under Subpart D or E of Part 225.
c)
The provisions of this Subpart do not apply to fluidized catalytic cracking units,
their regenerator and associated CO boiler or boilers and CO furnace or furnaces
97
where present, if such units are located at a petroleum refinery and such units are
required to meet emission limits or control requirements for NO
x
as provided for
in an enforceable order.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.162 Exemptions
Notwithstanding Section 217.160 of this Subpart, the provisions of this Subpart do not apply to
an industrial boiler operating under a federally enforceable limit of NO
x
emissions from such
boiler to less than 15 tons per year and less than five tons per ozone season.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.164 Emissions Limitations
On and after January 1, 2012, no person shall cause or allow emissions of NO
x
into the
atmosphere from any industrial boiler to exceed the following limitations. Compliance must be
demonstrated with the applicable emissions limitation on an ozone season and annual basis.
NO
x
Emissions
Emission Unit Type and
Limitation
Fuel
Rated Heat Input Capacity
(lb/mmBtu)
(mmBtu/hr)
or Requirement
---------------------------------------------------------------------------------------------------------
a)
Natural Gas
1)
Industrial boiler
0.08
or Other Gaseous
greater than 100
Fuels
2)
Industrial boiler
Combustion tuning
less than or equal to 100
b)
Distillate Fuel Oil
1)
Industrial boiler
0.10
greater than 100
2)
Industrial boiler
Combustion tuning
less than or equal to 100
c)
Other Liquid
1)
Industrial boiler
0.15
Fuels
greater than 100
2)
Industrial boiler
Combustion tuning
less than or equal to 100
d)
Solid Fuel
1)
Industrial boiler
0.12
98
greater than 100,
circulating fluidized bed
combustor
2)
Industrial boiler
0.18
greater than 250
3)
Industrial boiler
0.25
greater than 100 but
less than or equal to 250
4)
Industrial boiler
Combustion tuning
Less than or equal to 100
e)
For an industrial boiler combusting a combination of natural gas, coke oven gas,
and blast furnace gas, the NO
x
emissions limitation shall be calculated using the
following equation:
NO
x
emissions limitation for period in lb/MMBtu=
(NOx
NG
* BTU
NG
+ NOx
COG
* BTU
COG
+ NOx
BFG
* BTU
BFG
) /(BTU
NG
+ BTU
COG
+ BTU
BFG
)
Where:
NOx
NG
= 0.084 lb/MMBtu for natural gas
BTU
NG
=
the heat input of natural gas in BTU over that period
NOx
COG
= 0.144 lb/MMBtu for coke oven gas
BTU
COG
= the heat input of coke oven gas in BTU over that period
NOx
BFG
= 0.0288 lb/MMBtu for blast furnace gas
BTU
BFG
= the heat input of blast furnace gas in BTU over that
period
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.165 Combination of Fuels
The owner or operator of an industrial boiler subject to this Subpart and operated with any
combination of fuels must comply with a heat input weighted average emissions limitation to
demonstrate compliance with Section 217.164 of this Subpart.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.166 Methods and Procedures for Combustion Tuning
The owner or operator of an industrial boiler subject to the combustion tuning requirements of
Section 217.164 of this Subpart must have combustion tuning performed on the boiler at least
99
annually. The combustion tuning must be performed by an employee of the owner or operator or
a contractor who has successfully completed a training course on the combustion tuning of
boilers firing the fuel or fuels that are fired in the boiler. The owner or operator must maintain
the following records that must be made available to the Agency upon request:
1)
The date the combustion tuning was performed;
2)
The name, title, and affiliation of the person who performed the combustion
tuning;
3)
Documentation demonstrating the provider of the combustion tuning training
course, the dates the training course was taken, and proof of successful
completion of the training course;
4)
Tune-up procedure followed and checklist of items (such as burners, flame
conditions, air supply, scaling on heating surface, etc.) inspected prior to the
actual tune-up; and
5)
Operating parameters recorded at the start and at conclusion of combustion
tuning.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
SUBPART E: PROCESS HEATERS
Section 217.180
Applicability
The provisions of Subpart C of this Part and this Subpart apply to all process heaters located at
sources subject to this Subpart pursuant to Section 217.150 of this Part.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.182 Exemptions
Notwithstanding Section 217.180 of this Subpart, the provisions of this Subpart do not apply to a
process heater operating under a federally enforceable limit of NO
x
emissions from such heater
to less than 15 tons per year and less than five tons per ozone season.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.184 Emissions Limitations
On and after January 1, 2012, no person shall cause or allow emissions of NO
x
into the On and
after January 1, 2012, no person shall cause or allow emissions of NO
x
into the atmosphere from
any process heater to exceed the following limitations. Compliance must be demonstrated with
the applicable emissions limitation on an ozone season and annual basis.
100
NO
x
Emissions
Emission Unit Type and
Limitation
Fuel
Rated Heat Input Capacity
(lb/mmBtu)
(mmBtu/hr)
or Requirement
--------------------------------------------------------------------------------------------------------------
a)
Natural Gas
1)
Process heater
0.08
or Other Gaseous
greater than 100
Fuels
2)
Process heater
Combustion tuning
less than or equal to 100
b)
Residual Fuel Oil
1)
Process heater
0.10
greater than 100,
natural draft
2)
Process heater
0.15
greater than 100,
mechanical draft
3)
Process heater
Combustion tuning
less than or equal to 100
c)
Other Liquid
1)
Process heater
0.05
Fuels
greater than 100,
natural draft
2)
Process heater
0.08
greater than 100,
mechanical draft
3)
Process heater
Combustion tuning
less than or equal to 100
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.185 Combination of Fuels
The owner or operator of a process heater subject to this Subpart and operated with any
combination of fuels must comply with a heat input weighted average emissions limitation to
demonstrate compliance with Section 217.184 of this Subpart.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.186 Methods and Procedures for Combustion Tuning
101
The owner or operator of a process heater subject to the combustion tuning requirements of
Section 217.184 of this Subpart must have combustion tuning performed on the heater at least
annually. The combustion tuning must be performed by an employee of the owner or operator or
a contractor who has successfully completed a training course on the combustion tuning of
heaters firing the fuel or fuels that are fired in the heater. The owner or operator must maintain
the following records that must be made available to the Agency upon request:
1)
The date the combustion tuning was performed;
2)
The name, title, and affiliation of the person who performed the combustion
tuning;
3)
Documentation demonstrating the provider of the combustion tuning training
course, the dates the training course was taken, and proof of successful
completion of the training course;
4)
Tune-up procedure followed and checklist of items (such as burners, flame
conditions, air supply, scaling on heating surface, etc.) inspected prior to the
actual tune-up; and
5)
Operating parameters recorded at the start and at conclusion of combustion
tuning.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
SUBPART F: GLASS MELTING FURNACES
Section 217.200
Applicability
The provisions of Subpart C of this Part and this Subpart apply to all glass melting furnaces
located at sources subject to this Subpart pursuant to Section 217.150 of this Part.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.202
Exemptions
Notwithstanding Section 217.200 of this Subpart, the provisions of this Subpart do not apply to a
glass melting furnace operating under a federally enforceable limit of NO
x
emissions from such
furnace to less than 15 tons per year and less than five tons per ozone season.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.204 Emissions Limitations
102
a)
On and after January 1, 2012, no person shall cause or allow emissions of NO
x
into the atmosphere from any glass melting furnace to exceed the following
limitations. Compliance must be demonstrated with the emissions limitation on
an ozone season and annual basis.
NO
x
Emissions
Limitation
(lb/ton glass
Product
Emission Unit Type
produced)
--------------------------------------------------------------------------------------------------------------
1)
Container Glass
Glass melting furnace
5.0
2)
Flat Glass
Glass melting furnace
7.9
3)
Other Glass
Glass melting furnace
11.0
b)
The emissions limitations under this Section do not apply during glass melting
furnace startup (not to exceed 70 days) or idling (operation at less than 35% of
furnace capacity). For the purposes of demonstrating seasonal and annual
compliance, the emissions limitation during such periods shall be calculated as
follows:
NOx emissions limitation (lb/day) = (ANL) / (PPC)
Where:
ANL = The applicable NOx emissions limitation under this
Section in pounds per ton of glass produced
PPC = Permitted production capacity in tons of glass produced per
day
(Source: Added at 33 Ill. Reg. ____, effective ______________)
SUBPART G: CEMENT AND LIME KILNS
Section 217.220 Applicability
a)
Notwithstanding Subpart T of this Part, the provisions of Subpart C of this Part
and this Subpart apply to all cement kilns located at sources subject to this
Subpart pursuant to Section 217.150 of this Part.
b)
The provisions of Subpart C of this Part and this Subpart apply to all lime kilns
located at sources subject to this Subpart pursuant to Section 217.150 of this Part.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.222 Exemptions
103
Notwithstanding Section 217.220 of this Subpart, the provisions of this Subpart do not apply to a
cement kiln or lime kiln operating under a federally enforceable limit of NO
x
emissions from
such kiln to less than 15 tons per year and less than five tons per ozone season.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.224 Emissions Limitations
a)
On and after January 1, 2012, no person shall cause or allow emissions of NO
x
into the atmosphere from any cement kiln to exceed the following limitations.
Compliance must be demonstrated with the applicable emissions limitation on an
ozone season and annual basis.
NO
x
Emissions
Limitation
(lb/ton clinker
Emission Unit Type
produced)
--------------------------------------------------------------------------------------------------
1)
Long dry kiln
5.1
2)
Short dry kiln
5.1
3)
Preheater kiln
3.8
4)
Preheater/precalciner kiln
2.8
b)
On and after January 1, 2012, no person shall cause or allow emissions of NO
x
into the atmosphere from any lime kiln to exceed the following limitations.
Compliance must be demonstrated with the applicable emissions limitation on an
ozone season and annual basis.
NO
x
Emissions
Limitation
(lb/ton lime
Fuel
Emission Unit Type
produced)
---------------------------------------------------------------------------------------------------
1)
Gas
Rotary kiln
2.2
2)
Coal
Rotary kiln
2.5
(Source: Added at 33 Ill. Reg. ____, effective ______________)
104
SUBPART H: IRON AND STEEL AND ALUMINUM MANUFACTURING
Section 217.240 Applicability
a)
The provisions of Subpart C of this Part and this Subpart apply to all reheat
furnaces, annealing furnaces, and galvanizing furnaces used in iron and steel
making located at sources subject to this Subpart pursuant to Section 217.150 of
this Part.
b)
The provisions of Subpart C of this Part and this Subpart apply to all
reverberatory furnaces and crucible furnaces used in aluminum melting located at
sources subject to this Subpart pursuant to Section 217.150 of this Part.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.242 Exemptions
Notwithstanding Section 217.240 of this Subpart, the provisions of this Subpart do not apply to
an iron and steel reheat furnace, annealing furnace, or galvanizing furnace, or aluminum
reverberatory furnace or crucible furnace operating under a federally enforceable limit of NO
x
emissions from such furnace to less than 15 tons per year and less than five tons per ozone
season.
(Source: Added at 33 Ill. Reg. ____, effective ______________)_________)
Section 217.244
Emissions Limitations
a)
On and after January 1, 2012, no person shall cause or allow emissions of NO
x
into the atmosphere from any reheat furnace, annealing furnace, or galvanizing
furnace used in iron and steel making to exceed the following limitations.
Compliance must be demonstrated with the applicable emissions limitation on an
ozone season and annual basis.
NO
x
Emissions
Limitation
Emission Unit Type
(lb/mmBtu)
------------------------------------------------------------------------------------------------------------
1)
Reheat furnace, regenerative
0.18
2)
Reheat furnace, recuperative,
0.09
combusting natural gas
3)
Reheat furnace, recuperative,
0.142
combusting a combination of
natural gas and coke oven gas
105
4)
Reheat furnace, cold-air
0.03
5)
Annealing furnace, regenerative
0.38
6)
Annealing furnace, recuperative
0.16
7)
Annealing furnace, cold-air
0.07
8)
Galvanizing furnace, regenerative
0.46
9)
Galvanizing furnace, recuperative
0.16
10)
Galvanizing furnace, cold-air
0.06
b)
On and after January 1, 2012, no person shall cause or allow emissions of NO
x
into the
atmosphere from any reverberatory furnace or crucible furnace used in aluminum melting
to exceed the following limitations. Compliance must be demonstrated with the
applicable emissions limitation on an ozone season and annual basis.
NO
x
Emissions
Limitation
Emission Unit Type
(lb/mmBtu)
--------------------------------------------------------------------------------------------------------------
1)
Reverberatory furnace
0.08
2)
Crucible furnace
0.16
(Source: Added at 33 Ill. Reg. ____, effective ______________)
SUBPART M: ELECTRICAL GENERATING UNITS
Section 217.340 Applicability
Notwithstanding Subpart V or W of this Part, the provisions of Subpart C of this Part and this
Subpart apply to any fuel-fired stationary boiler serving a generator that has a nameplate capacity
greater than 25 MWe and produces electricity for sale, excluding any units listed in Appendix D
of this Part, located at sources subject to this Subpart pursuant to Section 217.150 of this Part.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.342 Exemptions
106
a)
Notwithstanding Section 217.340 of this Subpart, the provisions of this Subpart
and this Subpart do not apply to a fossil fuel-fired stationary boiler operating
under a federally enforceable limit of NO
x
emissions from such boiler to less than
15 tons per year and less than five tons per ozone season.
b)
Notwithstanding Section 217.340 of this Subpart, the provisions of this Subpart
do not apply to a coal-fired stationary boiler that commenced operation before
January 1, 2008, that is complying with thePart 225 Subpart B through the multi-
pollutant standard under Section 225.233 of Part 225 or the combined pollutant
standards under Subpart F of Part 225.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.344 Emissions Limitations
On and after January 1, 2012, no person shall cause or allow emissions of NO
x
into the
atmosphere from any fossil fuel-fired stationary boiler to exceed the following limitations.
Compliance must be demonstrated with the applicable emissions limitation on an ozone season
and annual basis.
NO
x
Emissions
Limitation
Fuel
Emission Unit Type
(lb/mmBtu)
-------------------------------------------------------------------------------------------------------
a)
Solid
Boiler
0.12
b)
Natural gas
Boiler
0.06
c)
Liquid
1)
Boiler that commenced
0.10
operation before January 1, 2008
2)
Boiler that commenced
0.08
operation on or after January 1, 2008
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.345 Combination of Fuels
The owner or operator of a fossil fuel-fired stationary boiler subject to this Subpart and operated
with any combination of fuels must comply with a heat input weighted average emissions
limitation to demonstrate compliance with Section 217.344 of this Subpart.
(Source: Added at 33 Ill. Reg. ____, effective ______________)
Section 217.APPENDIX H: Compliance Dates for Certain Emission Units at Petroleum
107
Refineries
ExxonMobil Oil Corporation (Facility ID 197800AAA)
Point
Emission Unit Description
Compliance Date
0019
Crude Vacuum Heater (13-B-2)
December 31, 2014
0038
Alky Iso-Stripper Reboiler (7-B-1)
December 31, 2014
0033
CHD Charge Heater (3-B-1)
December 31, 2014
0034
CHD Stripper Reboiler (3-B-2)
December 31, 2014
0021
Coker East Charge Heater (16-B-1A)
December 31, 2014
0021
Coker East Charge Heater (16-B-1B)
December 31, 2014
0018
Crude Atmospheric Heater (1-B-1A)
December 31, 2014
0018
Crude Atmospheric Heater (1-B-1B)
December 31, 2014
ConocoPhillips Company Wood River Refinery (Facility ID 119090AAA)
IT IS SO ORDERED.
Point
Emission Unit Description
Compliance Date
0017
BEU HM-1
December 31, 2012
0018
BEU HM-2
December 31, 2012
0004
CR-1 Feed Preheat, H-1
December 31, 2012
0005
CR-1 1
st
Interreactor Heater, H-2
December 31, 2012
0009
CR-1 3
rd
Interreactor Heater, H-7
December 31, 2012
0091
CR-3 Charge Heater
December 31, 2012
0092
CR-3 1
st
Reheat Heater, H-5
December 31, 2012
0082
Boiler 17
December 31, 2012
0080
Boiler 15
December 31, 2012
0073
Alky HM-2 Heater
December 31, 2012
0662
VF-4 Charge Heater, H-28
December 31, 2012
0664
DU-4 Charge Heater, H-24
December 31, 2014
0617
DCU Charge Heater, H-20
December 31, 2014
0014
HCU Fractionator Reboil, H-3
December 31, 2016
0024
DU-1 Primary Heater South, F-301
December 31, 2016
0025
DU-1 Secondary Heater North, F-302
December 31, 2016
0081
Boiler 16
December 31, 2016
0083
Boiler 18
December 31, 2016
0095
DHT Charge Heater
December 31, 2016
0028
DU-2 Lube Crude Heater, F-200
December 31, 2016
0029
DU-2 Mixed Crude Heater West, F-202
December 31, 2016
0030
DU-2 Mixed Crude Heater East, F-203
December 31, 2016
0084
CR-2 North Heater
December 31, 2016
108
I, John T. Therriault, Assistant Clerk of the Illinois Pollution Control Board, certify that
the Board adopted the above opinion and order on May 7, 2009, by a vote of 5-0.
___________________________________
John T. Therriault, Assistant Clerk
Illinois Pollution Control Board
