BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
RCLERK'S
oVI
ED
IN THE MATTER OF
:
)
STATIONARY RECIPROCATING
F
0 1 2002
)
R07- I
INTERNAL COMBUSTION
STATE OF ILLINOIS
)
(Rulemaking -
Air) Pollution Control Board
ENGINES AND TURBINES
:
)
AMENDMENTS TO
35 ILL.
)
ADM. CODE SECTION 201 .146,
)
AND PARTS 211 AND 217
)
NOTICE
TO :
Dorothy Gunn, Clerk
Matthew Dunn, Chief
Illinois Pollution Control Board
Attorney General's Office
State of Illinois Center
James R. Thompson Center
100 West Randolph, Suite 11-500
100 West Randolph, 12th Floor
Chicago, Illinois 60601
Chicago, Illinois 60601
Virginia I . Yang, Deputy Counsel
Illinois Department of Natural Resources
One Natural Resources Way
Springfield, IL 62702-1271
PLEASE TAKE NOTICE that I have today filed with the Office of the Pollution Control
Board the attached
REGULATORY PROPOSAL FOR STATIONARY TRUBINES AND
RECIPROCATION INTERNAL COMBUSTION ENGINES
: AMENDMENTS TO 35 ILL .
ADM
. CODE SECTION 201
.46, PART 211, AND PART 217, MOTION FOR WAIVER OF
COPY REQUIREMENTS,
and APPEARANCE
of the Illinois Environmental Protection Agency
a copy of which is herewith served upon you
.
ILLINOIS ENVIRONMENTAL PROTECTION
AGENCY
By:
Rachel L . Doctors
Assistant Counsel
Division of Legal Counsel
DATED: March 29, 2007
P.O. Box 19276
Springfield, Illinois 62794-9276
217/782-5544
BEFORE THE ILLINOIS
POLLUTION CONTROL BOARIRECopREIVED
I
APR 0 5 2001
Pollut on
OControl Board
IN THE MATTER OF :
)
STATIONARY RECIPROCATING
INTERNAL COMBUSTION
ENGINES AND TURBINES :
AMENDMENTS TO 35 ILL .
ADM. CODE SECTION 201
.146,
AND PARTS 211 AND 217
(Rulemaking - Air)
TABLE OF CONTENTS OF REGULATORY SUBMITTAL
Following is a Table of Contents of all pleadings and documents included with the proposed
regulatory action :
a
.
Interstate Ozone Transport
: Response to Court Decisions on the NO, SIP
Call, NO, SIP Call Technical Amendments, and Section 126 Rules
; Final
Rule
. 69 FR 21603, April 21, 2004
.
b.
Letter to Director Douglas P
. Scott, Director, Illinois Environmental
Protection Agency from Thomas V
. Skinner, Regional Administrator,
Region 5, United States Environmental Protection Agency, dated October
13, 2005 .
1 .
Notice of Proposal
2.
Appearance
Environmental
of Rachel L . Doctors, Assistant
Protection Agency
Counsel, for the Illinois
3 .
Director Douglas Scott's Proposal of Amendments
4 .
Motion for Waiver of Copy Requirements
5 .
Economic
a.
and Budgetary Analysis
35 Ill . Adm. Code 201
.146
b .
a.
35 111 . Adm. Code 211
35 Ill. Adm
. Code 217
6 .
Statement of Reasons
7 .
Attachments to Statement of Reasons
c .
Final Rule Making Findings of Failure to Submit Required State
Implementation Plans for Phase II NO, SIP Call
. 71 FR
6347, February 8,
2006 .
d.
Meeting with Stakeholders, Sign-in Sheets:
i .
August 25, 2005 ;
ii.
October 5, 2005 ; and
i
November 14, 2005.
8
.
First Notice Forms :
a
.
b.
c.
35 Ill . Adm. Code 201 .146
35111. Adm. Code 211
35 Ill . Adm. Code 217
9.
Proposed Amendments to
:
a.
35 Ill. Adm
. Code Part 201 .146
b.
35 Ill. Adm . Code Part 211
c.
35 Ill. Adm . Code Part 217
10.
Technical Support Document for Controlling NO, Emissions From Stationary
Reciprocating Internal Combustion Engines and Turbines,
AQPSTR 06-5, Illinois
Environmental Protection Agency, February 21, 2007
.
11 .
Attachments to
Technical Support Document for Controlling NO, Emissions
From Stationary Reciprocating Internal Combustion Engines and Turbines
:
a.
Technical Support Document for Final Clean Air Interstate Rule, Air
Quality Modeling, U .S
. EPA, Research Triangle Park, NC, March 2005
.
b.
LADCO, Attainment Strategy Options, Draft, October 28, 2005
.
Alternative Control Techniques Document--NO
t Emissions from
Stationary Reciprocating Internal Combustion Engines EPA-453/R-93-
032, July 1993, U .S
. EPA, OAQPS, RTP, NC 27711
.
d.
Alternative Control Techniques Document- NO, Emissions from
Stationary Gas Turbines, EPA-453/R-91-007, January 1993, U
.S . EPA,
OAQPS, Research Triangle Park, NC 27711
.
e.
Controlling Nitrogen Oxides Under the Clean Air Act
: A Menu of
Options, July 1994, State and Territorial Air Pollution Program
Administrators/Association of Local Air Pollution Control Officials
.
f.
Regulatory Impacts Analysis for the NO, SIP Call, FIP, and Section 126
Petitions, Volume 1
: Costs and Economic Impacts, EPA-452/R-98-003,
2
9-
h.
Texas Administrative Code
. Title 30, Rule 106.512 : Stationary Engines
and Turbines
.
P .
q
.
September 1998, U
.S
. EPA, Office of Air and Radiation, Washington,
DC20460.
Stationary Reciprocating Internal Combustion Engines Technical Support
Document for NO., SIP Call, October 2003, Doug Grano/Bill Neuffer,
EPA, OAR, OAQPS, OPSG .
Indiana Department of Environmental Management, Office of Air Quality,
Section 9 .326 IAC 10-5
. Rule 5 Nitrogen Oxide Reduction Program for
Internal Combustion Engines (ICE) .
Document Prepared by the State of Connecticut, Department of
Environmental Protection. Sec
. 22a-174-22 Control of Nitrogen Oxides
Emissions.
k.
Alabama Department of Environmental Management . Air Division,
Chapter 335-3-8, Nitrogen Oxides Emissions .
1 .
New York State, Department of Environmental Conservation Rule and
Regulations, Subpart 227
.2, Reasonable Available Control Technology
(RACT) for Oxides of Nitrogen (NO.).
m.
New Jersey State Department of Environmental Protection, New Jersey
Administrative Code Title 7, Chapter 27, Subchapter 19 : Control and
Prohibition of Air Pollution from Oxides of Nitrogen .
n.
Pennsylvania Department of Environmental Protection, Air Quality
Regulations, Small Source of NO x Cement Kilns and Large Internal
Combustion Engines, 25 PA Code CHS 121,129 and 145
.
o.
Code of Maryland Regulations
. Title 26 Department of the Environment .
Subtitle I 1 Air Quality, Chapter 09 : Control of Fuel-Burning Equipment,
Stationary Internal Combustion Engines, and Certain Fuel-Burning
Installation.
Antelope Valley Air Quality Management District
. Rule 1110 .2:
Emissions from Stationary, Non-Road & Portable Internal Combustion
Engines .
San Joaquin Valley Unified Air Pollution Control District Rule 4702 :
Internal Combustion Engines -
Phase 2.
3
r.
El Dorado County Air Pollution Control District Rule 233
: Stationary
Internal Combustion Engines
.
Stationary Reciprocating Internal Combustion Engines, Updated
Information on NO, Emissions and Control Techniques, Revised Final
Report, EPA Contract No
. 68-D-026, Work Assignment No. 2-28,EC/R
Project No
. ISD-228, September 1, 2000 .
t.
South Coast Air Quality Management District, Rule 1134
- Emissions of
Oxides of Nitrogen from Stationary Gas Turbines .
12.
Documents Relied On:
a.
Illinois Environmental Protection Act (415 ILCS 5/et. seq.)
b .
The Clean Air Act, as amended in 1990 ("CAA")
(42 U
.S.C
. 7401 et. seq.)
c.
National Ambient Air Quality Standards for Ozone, 62
FR 38855, July 18,
1997, (Ozone Standards).
d.
National Ambient Air Quality Standards for Particulate Matter, 62
FR
38652, July 18, 1997,
(PM2,5
Standards).
e .
Finding of Significant Contribution and Rulemaking for Certain States in
the Ozone Transport Assessment Group Region for Purposes of Reducing
Regional Transport of Ozone
; Rule. Part II, Environmental Protection
Agency, 63 FR 57355, October 27, 1998.
f
Interstate Ozone Transport
: Response to Court Decisions on the NOx SIP
Call, NOx SIP Call Technical Amendments, and Section 126 Rules
; Final
Rule. 69 FR 21603, April 21, 2004
.
g.
Air Quality Designations and Classifications for Fine Particles (PM2
.5)
National Ambient Air Quality Standards, 70 FR
943, January 5, 2005 .
h.
8-hour Ozone National Ambient Air Quality Standards, 69
FR 23858,
April 30, 2004
.
Final Rule to Implement the 8-Hour Ozone National Ambient Air Quality
Standard, 70 FR
71612, November 29, 2005 .
Proposed Rule to Implement the Fine Particle National Ambient Air
Quality Standards, 70 FR
65984, November 1, 2005 .
4
k.
Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone
(Clean Air Interstate Rule)
; Revisions to Acid Rain Program ; Revisions to
the NO, SIP Call, 70 FR
25162, May 12, 2005 .
National Ambient Air Quality Standards for Particulate Matter
; Proposed
Rule, 71 FR
25612, January 17, 2006 .
13 .
Incorporations by Reference
a.
The phenol disulfonic acid procedures, as published in 40 CFR 60,
Appendix A, Method 7 (2000) ;
b .
40 CFR 60, 72, 75 & 76 (2006) ;
c .
40 CFR 60
.13 (2001) ;
d.
40 CFR 60, Appendix A, Methods 3A, 7, 7A, 7C, 7D, 7E, 19, and 20
(2000) ;
e.
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) ;
f
Standards of Performance for Stationary Combustion Turbines, 40 CFR
60, Subpart KKKK, 60
.4400 (2006); and
g
14 .
Certificate of Service
15 .
Disk in Microsoft WORD containing
Compilation of Air Pollutant Emission Factors
: AP-42, Volume I
:
Stationary Point and Area Sources (2000), USEPA .
a. First Notice Forms for amendments to 35 111
. Adm
. Code 201, 211, and 217 ;
and
b. Proposed Amendments to 35 111
. Adm
. Code 201, 211, and 217 .
5
BEFORE THE ILLINOIS POLLUTION CONTROL BOAR&E
CLERKS
OFFIE(?
IN THE MATTER OF :
)
A;'4
a
g 2007
STATIONARY RECIPROCATING
Pollution OF ILLINOIS
)
R07- ~~
INTERNAL
COMBUSTION
Control go
)
(Rule aking - Air)
ENGINES AND TURBINES :
)
AMENDMENTS TO 35 ILL .
)
ADM
. CODE SECTION 201 .146,
)
PART 211, AND PART 217
)
APPEARANCE
The undersigned, as one of its attorneys, hereby enters an Appearance on behalf of the
Illinois Environmental Protection Agency .
ILLINOIS ENVIRONMENTAL PROTECTION
AGENCY
By:
Rachel L
. Doc ors
Assistant Counsel
Division of Legal Counsel
DATED: March 27, 2007
1021 North Grand Avenue East
P.O. Box 19276
Springfield, Illinois 62794-9276
217 .782.5544
217 .782.9143 (TDD)
THIS FILING IS SUBMITTED ON
RECYCLED PAPER
REC
E I VIE
D
BEFORE THE ILLINOIS POLLUTION CONTROL BOA
• 0 E2007
Pollution
STATE OF
Control
ILL11401S
Board
IN THE MATTER OF :
)
STATIONARY RECIPROCATING
)
R07-
INTERNAL COMBUSTION
)
(Rulemaking - Air)
ENGINES AND TURBINES :
)
AMENDMENTS TO 35 ILL .
)
ADM. CODE SECTION 201 .146,
)
AND PARTS 211 AND 217
)
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY PROPOSAL OF
AMENDMENTS
THE ILLINOIS ENVIRONMENTAL PROTECTION AGENCY ("Illinois EPA"),
pursuant to 35 Ill . Adm. Code 102
.202, moves that the Board accept for hearing the
Agency's proposal for amendments to 35 111 . Adm. Code Section 201 .146, 35 Ill . Adm.
Code Part 211, and 35 Ill. Adm . Code Part 217 . This regulatory proposal includes : 1) the
proposed amendments ; 2) the Statement of Reasons ; 3) an economic and budgetary form;
and 4) an Appearance for the attorney representing the Illinois EPA .
Respectfully submitted,
ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY
By:
DATED :
March 27, 2007
P.O. Box 19276
Springfield, Illinois 62794-9276
217/782-3397
Douglas Scott
Director
RECEIVED
BEFORE THE ILLINOIS POLLUTION CONTROL BOARIOPRR
U F 2©Q/
IN THE MATTER OF :
STATE OF ILLINOIS
)
Pollution Control Board
STATIONARY RECIPROCATING
)
R07-1%
INTERNAL COMBUSTION
)
(Rulemaking-Air)
ENGINES AND TURBINES :
)
AMENDMENTS TO 35 ILL .
)
ADM . CODE SECTION 201 .146,
)
PART 211, AND PART 217
)
MOTION FOR WAIVER OF COPY REQUIREMENTS
NOW COMES the Proponent, the ILLINOIS ENVIRONMENTAL PROTECTION
AGENCY ("Illinois EPA"), by one of its attorneys, and pursuant to 35 Ill . Adm. Code 101 .500,
102 .110 and 102 .402, moves that the Illinois Pollution Control Board ("Board") waive certain
requirements, namely that the Illinois EPA submit the original and nine copies of all documents
upon which it relied . In support of its Motion, the Illinois EPA states as follows :
A. First Request For Waiver Of Copy Requirements
Regulatory Proposal
Section 102 .200 of the Board's procedural rules requires that the original acrd nine copies
of each regulatory proposal be filed with the Clerk . 35 Ill. Adm . Code 102 .200 . This entire
regulatory proposal consists of at least 1,000 pages
. Given the length of the proposal and the
resources required to provide nine copies, the Illinois EPA requests that the Board waive the
normal copy requirements of Section 102 .200 and allow the Illinois EPA to instead file the
original and four complete copies of the proposal, plus five partial copies, the partial copies
consisting of the Table of Contents, Statement of Reasons (with attachments), pleadings and the
proposed rule absent documents relied upon .
B. Second Request For Waiver Of Copy Requirements
Documents Relied Upon
Section 28.5(e)(7) of the Environmental Protection Act requires the Illinois EPA to
submit copies of all documents that it relied upon in the development of the proposal or upon
which it intends to rely at hearing. 415 ILCS 5128 .5(e)(7) . A list of those documents relied upon
that are the subject of this motion is found in No . 12 of the Table of Contents . Some of the items
are denoted with an asterisk . The items in No. 12 are readily accessible to, or are already
within the possession of, the Board . Given this ease of accessibility, and in most cases the
lengthy nature of the documents, the Illinois EPA requests that the Board waive the normal copy
requirements of Section 102
.200 of the Board's procedural rules and allow the Illinois EPA to
not file any copies of the items denoted on No . 12.
C . Third Request For Waiver Of Copy Requirements
Documents Incorporated By Reference
Section 5-75(a) of the Illinois Administrative Procedure Act ("IAPA") provides in
relevant part that an agency may incorporate by reference the regulations, standards and
guidelines of an agency of the United States or a nationally recognized organization or
association wi$iout publishing the incorporated material in full
. 5 ILCS 100/5-75(a) . Further,
Section 5-75(b) of the IAPA provides in relevant part that the agency adopting a rule or
regulation under the IAPA shall maintain a copy of the referenced rule, regulation, standard or
guideline in at least one of its principal offices and shall make it available to the public upon
request
. 5 ILCS 100/5-75(b)
.
In developing this proposed rulemaking, the Illinois EPA has incorporated by reference
certain documents
. A list of those documents incorporated by reference that are the subject of
this motion is found in No . 13 of the Table of Contents .
The items listed in No . 13 are readily accessible to, or are already within the possession
of, the Board . (given this ease of accessibility, and the lengthy nature of the documents, the
2
Illinois EPA requests that the Board waive the normal copy requirements of Section 102
.200 of
the Board's procedural rules and allow the Illinois EPA to not file any copies of the items listed
on No. 13 .
WHEREFORE, for the reasons set forth above, the Illinois EPA moves that the Board
waive the copy requirement and allow the Illinois EPA to provide the Board with an original and
four complete copies of the proposal, along with five partial copies as described
supra . Further,
the Illinois EPA moves that the Board allow the Illinois EPA to file either no copies or an
original and four copies of the documents relied upon as listed in No
. 12 and as described supra .
Finally, the Illinois EPA moves that the Board allow the Illinois EPA to file no copies of the
documents incorporated by reference as listed in No . 13.
Respectfully submitted,
ILLINOIS ENVIRONMENTAL
PROTECTION AGE CY
By:
DATED: March 27 , 2007
1021 N. Grand Ave., East
P .O. Box 19276
Springfield, Illinois 62794-9276
217/782-5544
3
Rachel L
. Doctors
Assistant Counsel
Air Regulatory Unit
Division of Legal Counsel
THIS IS A
FAST TRACK
RULEMAKING
FILED IN ACCORDANCE WITH
SECTION 28 .5
OF THE ENVIRONMENTAL
PROTECTION
(415 ILCS 5/28.5)
ACT
Agency Analysis of Economic and
Budgetary Effects of Proposed Rulemaking
Agency:
Illinois Pollution Control Board
Part/Title :
Permits And General Provisions (35 Ill . Adm
. Code Section 201 .146)
Illinois Register Citation :
Please attempt to provide as dollar-specific responses as possible and feel free to add any relevant
explanation .
Anticipated effect on State expenditures and revenues .
5 . a
(a)
Current cost to the agency for this program/activity
. $100,000 per year
(approximately)
(b)
If this rulemaking will result in an increase or decrease in cost, specify the fiscal year in
which this change will first occur and the dollar amount of the effect .
2008, with the annual cost as estimated above
(c)
Indicate the funding source,
including Fund and appropriation lines, for this
program/activity.
Clean Air Act Permit Program Fund (CAAPP)
(d)
If an increase or decrease in the costs of another State agency is anticipated, specify the
fiscal year in which this change will first occur and the estimated dollar amount of the
effect. N/A
(e)
Will this rulemaking have any effect on State revenues or expenditures not already
indicated above? No
2 .
Economic effect on persons affected by the rulemaking :
(a)
Indicate the economic effect and specify the persons affected
:
Positive Negative No effect X
Persons affected: owners and operators of certain
stationary internal combustion
engines and
Dollar
turbinesamount per
person
: 0
Total statewide cost : 0
(b)
If an economic effect is predicted, please briefly describe how the effect will occur
.
N/A
(c) Will the
rulemaking have an indirect effect that may result in increased
administrative costs? Will there be any change in requirements such as filing,
documentation, reporting or completion of forms?
The indirect effects are included in the above cost estimate The rule will may require
revisions to air permits, as well as additional recordkeeping and reporting .
Agency Analysis of Economic and
Budgetary Effects of Proposed Rulemaking
Agency :
Illinois Pollution Control Board
Part/Title:
Definitions and General Provisions (35 III . Adm
. Code Part 211)
Please
Illinois
attempt
Register
to
Citationprovide
: as
dollar-specific responses as possible and feel free to add any relevant
explanation .
Anticipated effect on State expenditures and revenues .
(a)
Current cost to the agency for this program/activity .
$ 0 per year
(approximately)
(b)
If this rulemaking will result in an increase or decrease in cost, specify the fiscal year in
which this change will first occur and the dollar amount of the effect
.
N/A
(c)
Indicate the funding source, including Fund and appropriation lines, for this
program/activity. N/A
(d)
If an increase or decrease in the costs of another State agency is anticipated, specify the
fiscal year in which this change will first occur and the estimated dollar amount of the
effect . N/A
(e)
Will this rulemaking have any effect on State revenues or expenditures not already
indicated above? No
2
.
Economic effect on persons affected by the rulemaking
:
(a)
Indicate the economic effect and specify the persons affected
:
Positive Negative
No effect X
Persons affected : Owners
and operators of affected stationary internal combustion
engines and turbines
Dollar amount per person: 0
Total statewide cost :
0
5
. b
(b)
If an economic effect is predicted, please briefly describe how the effect will occur . N/A
(c) Will the rulemaking have an indirect effect that may result in increased
administrative costs'? No Will there be any change in requirements such as filing,
documentation, reporting or completion of forms? No
The rulemaking should have no indirect effect that may result in
increased administrative
costs .
Agency Analysis of Economic and
Budgetary Effects of Proposed Rulemaking
Agency :
Illinois Pollution Control Board
Part/Title:
Nitrogen Oxides Emissions (35 Ill . Adm
. Code Part 217 )
Please
Illinois
attempt
Register
to
Citationprovide
: as
dollar-specific responses as possible and feel free to add any relevant
explanation.
Anticipated effect on State expenditures and revenues
.
(a)
Current cost to the agency for this program/activity
.
$150,000 per year
(approximately)
(b)
If this rulemaking will result in an increase or decrease in cost, specify the fiscal year in
which this change will first occur and the dollar amount of the effect
.
2008, with the annual cost as indicated above
(c)
Indicate the funding source, including Fund and appropriation lines, for this
program/activity.
Clean Air Act Permit Program Fund (CAAPP)
(d)
If an increase or decrease in the costs of another State agency is anticipated, specify the
fiscal year in which this change will first occur and the estimated dollar amount of the
effect
. N/A
(e)
Will this rulemaking have any effect on State revenues or expenditures not already
indicated above? N/A
Economic effect on persons affected by the rulemaking
:
(a)
Indicate the economic effect and specify the persons affected
:
Positive _ Negative _X No
effect _-
Persons affected :
_Owners and operators of affected stationary internal combustion
engines and turbines
Dollar amount per person :
$855 average annual cost per emission unit affected
Total statewide cost
: $15,270,000 average annual cost statewide
(b)
If an economic effect is predicted, please briefly describe how the effect will occur
. The
cost to install and to maintain required air pollution control equipment
.
5.c
(c) Will
the rulemaking have an indirect effect that may result in increased
administrative costs? No Will there be any change in requirements such as filing,
documentation, reporting or completion of forms?
The rulemaking should have no indirect effect that may result in increased administrative
costs .
IN THE MATTER OF :
BEFORE THE ILLINOIS POLLUTION CONTROL BOARD
CLERKS
APP tj 6 2007
STATIONARY RECIPROCATING
INTERNAL COMBUSTION
ENGINES AND TURBINES :
AMENDMENTS TO 35 ILL .
ADM. CODE SECTION 201 .146,
AND PARTS 211 AND 217
R07- 1%
(Rulemaking - Air)
Pollution
OCControl
Board
STATEMENT OF REASONS
The Illinois Environmental Protection Agency ("Illinois EPA" or "Agency") hereby
submits this Statement of Reasons to the Illinois Pollution Control Board ("Board") pursuant to
Sections 9
.9, 10, 27, and 28 .5 of the Environmental Protection Act ("Act") (415 ILCS 5/9.9, 10,
27 and 28.5) and 35 Ill . Adm. Code 102.304(b), in support of the attached proposed
amendments . Included in this proposal are amendments to 35 111 . Adm. Code Parts 201
.146,
211, and 217 (Subparts A and Q) . This proposal amends the most recent versions of Parts 201,
211 and 217, as found on the Board's website
. The purpose of this proposal is to reduce intra-
and interstate transport of nitrogen oxides ("NO.")
emissions on an annual basis (January 1
though December 31) and on an ozone season basis (May I through September 30) of each year,
through the adoption of the rules reducing NO, emissions from stationary reciprocating internal
combustion engines and turbines .
This proposal is intended to satisfy Illinois' obligations under the United States
Environmental Protection Agency's ("USEPA") NO, State Implementation Plan ("SIP") Call
Phase II . Exhibit A . The proposed new Subpart is also intended to address, in part, Illinois'
obligation to meet certain requirements under the federal Clean Air Act ("CAA"), 42 U.S .C . §
7401, et seq, specifically the requirements for reasonable further progress
("RFP"), reasonably
available control technology
("RACT"), rate-of-progress ("ROP"), and attainment
demonstrations for the 8-hour ozone and PM 2 5
National Ambient Air Quality Standards
("NAAQS")
. As part of Illinois' effort to develop a comprehensive attainment strategy, Illinois
EPA has proposed and plans to propose reasonable and cost effective NO, control on all major
source sectors, because it is a primary precursor to ozone and particulate matter .
This statewide approach to NO, control is consistent with the rulemaking now pending
with the Board addressing the requirements for the Clean Air Interstate Rule ("CAIR") (PCB
R06-26) which addresses NO, emissions from utility boilers . However, based upon USEPA's
modeling, not only are reductions from the CAIR not sufficient to insure attainment in Illinois of
the PM2 5 NAAQS, such reductions will not occur soon enough for PM
2.5 attainment (the second
phase of CAIR will not be implemented until 2015). Control of engines and turbines is an
important and necessary part of Illinois attainment strategy for PM2,5
. The Illinois EPA intends
to apply this approach to seek reasonable NO, controls on all major source sectors in future
related rulemakings .
The Illinois EPA has been working with its counterparts in nearby states to develop
attainment demonstrations for both of its nonattainment areas
. In the Lake Michigan region, the
modeling demonstrations are being performed by the Lake Michigan Air Directors Consortium
("LADCO") . For the Metro-East/St
.Louis area, the Illinois EPA has been working with the State
of Missouri
. The LADCO modeling, while it is not yet complete because the base year is being
changed, has also shown that the reductions from the implementation of CAIR are not enough
for Illinois' two nonattainment areas to reach attainment of the
PM2.5 NAAQS . LADCO has
prepared a summary of recent modeling that describes the role of NO, emissions in causing
Page
2
ozone, PM 2 5
and regional haze problems in the Midwest and has identified a number of
candidate control measures . TSD at 21
. LADCO's assessment demonstrates that NO, emissions
from sources throughout Illinois, both in nonattainment areas and in attainment areas, contribute
to ozone and PM2
.5 formation . Id.
Hence, the Illinois EPA has proposed in this rulemaking that
NO, reductions be required at the same level as that required by Phase II for turbines and engines
that are not subject to Phase II
. In addition, the Illinois EPA is planning on proposing that NO,,
RACT level emission controls be implemented statewide on major stationary sources
. These
NO, reductions are needed for PM2.5
attainment, which is a regional pollutant not just affected by
NO, emissions within a local (nonattainment) area
.
While some affected owners and operators of engines and turbines have objected to the
parts of the proposal that go beyond Phase II and nonattainment area RACT requirements,
reductions from these emissions sources are needed for the attainment demonstration which is
due April 2008
. Section 110 of the CAA requires that measures included in all State
Implementation Plans ("SIP")
and SIP revisions be fully adopted
. The attainment
demonstrations for ozone and PM2
. 5
will revise Illinois' SIP
. The Board has already fully
adopted rules implementing the multi-pollutant standard
("MPS")
(PCB R06- 25) and is in the
process of adopting rules for the combined pollutant standard
("CPS") (PCB R06-26)
. Both of
these provisions will provide, for those power plants electing to comply with these provisions,
more stringent and earlier control of NO, and SO2 emissions, than is provided for under CAIR
.
The Illinois EPA will shortly be proposing NO, RACT level of emission controls statewide for
the major stationary source categories, including power plants that do not opt-in to either the
MPS or CPS
. Finally, Illinois EPA is developing and will propose SO2 RACT level of emissions
control statewide
. For all these reasons, the statewide approach to NO, control is appropriate
.
Page 3
II. BACKGROUND
The CAA establishes a comprehensive program for controlling and improving the
nation's air quality through both state and federal regulation
. Under Sections 108 and 109 of the
CAA, USEPA is charged with identifying air pollutants that endanger the public health and
welfare, and with formulating the National Ambient Air Quality Standards ("NAAQS") that
specify the maximum permissible concentrations of those pollutants in the ambient air
. 42
U.S .C. 7408-7409
. USEPA has promulgated NAAQS for various pollutants, including 8-hour
ozone and PM2 5 . 40 CFR 50
. Pursuant to Section 107(a) of the CAA, states are given primary
responsibility for ensuring that the ambient air quality meets the NAAQS for the identified
pollutants . 42 U.S .C . 7407(a) .
A.
8-Hour Ozone NAAQS
On July 18, 1997, USEPA promulgated revised primary and secondary ozone NAAQS
that increased the averaging period for the ozone standard from 1-hour to 8-hour and lowered the
concentration for violations from 0
.12 to 0
.08 parts per million ("ppm").'
USEPA has identified
volatile organic material
("VOM")
and NO, as the primary precursors responsible for the
formation of ozone
. Specifically, Illinois has two areas (greater Chicago and Metro East/St
.
Louis) consisting of 12 counties or partial counties that were designated
as not attaining the 8-
hour ozone standard.'
The designations were effective on June 15, 2004
. 69 Fed. Reg. 23858,
23898 (April 30, 2004) .
'The newly revised standard is the 3-year average of the fourth highest daily maximum 8-hour average ozone
concentration may not exceed 0
.08 ppm. 62 Fed. Reg
38856 (July 18, 1997) .
2
The two arc as (greater Chicago and Metro East/St
. Louis) were designated as moderate nonattainment for ozone
.
The greater (
Chicago nonattairiment area,
for
purposes of the 8-hour ozone standard, consists of the following
counties and partial counties
: Cook County, DuPage County, Grundy County (partial- Aux Sable and Goose Lake
townships), Kane County, Kendall County (partial- Oswego Township), Lake County, McHenry County and Will
County
. The Metro East/St
. Louis nonattainment area for purposes of the 8-hour ozone standard, consists of the
following counties
: Jersey County, Madison County, Monroe County, and St
. Claw County . 40 CFR 81
.314 .
Page 4
USEPA has classified the two nonattainment areas in Illinois as moderate . Moderate
nonattainment areas are required to submit attainment demonstrations by June 15, 2007,
addressing how the State will achieve the 8-hour ozone standard by the attainment date of June
15, 2009, which is within six years of the effective date of the nonattainment designations
. The
attainment demonstrations will revise the State's SIP for ozone .
B. PM2
.5 NAAQS
On July 18, 1997, USEPA also added a new 24-hour and a new annual NAAQS for fine
particles, using as the indicator particles with aerodynamic diameters smaller than a nominal 2 .5
micrometers,' termed PM2 .5 . 62 Fed. Reg. 38652 (July 18, 1997)
. USEPA has determined that,
in addition to direct particulate matter, that NO R, SO2 , volatile organic compounds ("VOCs"),
carbon and ammonia are precursors to the formation of PM2 .5
. States are required to address
NO, and sulfur dioxide ("SO 2") only, unless modeling demonstrates a need to control VOCs
and/or ammonia . This proposal only addresses NO, . 70 Fed. Reg. 65984, 65999 (November 1,
2005) .
USEPA has designated two areas in Illinois (greater Chicago and Metro East/St
. Louis),
consisting of 12 counties or partial counties within Illinois, as not attaining the PM
2.5 standard.'
70 Fed. Reg.
944, 968 (January 5, 2005) . The designations became effective on April 5, 2005 .
The attainment demonstration is due April 5, 2008, and the attainment date for most areas is
April 5, 2010, based on air quality data from 2007 through 2009
. States may be granted up to a
' On January 17,
2006, USEPA proposed to amend the NAAQS for PM2.5
.
71 Fed. Reg . 2620 .
USEPA listed the areas of greater Chicago and Metro East /St . Louis as areas that did not attain the
PM2.5 standard .
The Chicago nonattainment area, for purposes of the PM2
.5 standard, consists of the following counties/partial
counties
: Cook County, DuPage County, Grundy County (partial- Aux Sable and Goose Lake Townships), Kane
County, Kendall County (partial- Oswego Township), Lake County, McHenry County and Will County
. The St .
Louis/Metro East nonattainment area, for purposes of the PM 2.5 standard, consists of the following counties/partial
counties
: Madison County, Monroe County, Randolph County (partial- Baldwin Township) and St . Clair County .
40 CFR 81
.314 .
Page 5
five-year extension of the attainment date with a demonstration showing that it is impractical for
the state to attain within five years and that the state is making generally linear progress toward
attainment. 70 Fed. Reg. 65984, 66003 (November 1, 2005) .
C. Clean Air Act Planning and Emission Control Requirements
The proposed new Subpart also is intended to address, in part, Illinois EPA's obligation
to meet certain requirements under the CAA . These requirements include
: Part D, Subpart I of
the CAA, adoption of control strategies necessary to demonstrate attainment of the fine PM
2
5
and 8-hour ozone NAAQS in the greater Chicago moderate nonattainment area and the Metro
East/St
. Louis moderate nonattainment area
; Part D, Subpart 2 of the CAA, adoption of control
strategies necessary to demonstrate attainment of 8-hour ozone NAAQS for the greater Chicago
nonattainment area and Metro East/St . Louis nonattainment areas ; and Sections 172 and 182 of
the CAA, adoption of RACT measures, and RFP and ROP requirements .
D. NOx SIP Call
This proposal is intended to satisfy Illinois' obligations under USEPA's NO, SIP Call
Phase II
. Subparts T, U, and W of Part 217, addressing Phase I, were adopted by the Board on
December 21, 2000, March 1, 2001, and April 5, 2001, respectively. Subparts T, U, and W
regulate NO, emissions from large cement kilns, industrial boilers and utilities boilers,
respectively
. Illinois was required to regulate these sources pursuant to the NO, SIP Call . 63
Fed. Reg. 57356 (October 27, 1998) . Subparts U and W implement the NO, Trading Program in
Illinois to reduce ozone transport, meeting Illinois' obligations pursuant to Sections 110(a)(2)
and 126 of the CAA .
On April 21, 2004, USEPA promulgated a rule responding to the court's ruling in
Michigan v . EPA (213 F.3d 663 (DC Cir . 2000)), 69 Fed. Reg. 21603 (April 21, 2004) . Most
Page 6
importantly, the rule sets the control limit for large natural gas-fired stationary internal
combustion engines at 82 percent and for diesel and dual fuel stationary internal combustion
engines at 90 percent . It also set the date for states required to submit Phase II SIPs as April 1,
2005 . States required to submit Phase II SIPs included those states required to address the NO,
budget for stationary internal combustion engines . States are required to implement the controls
for stationary internal combustion engines no later than May 1, 2007 .
In November 2005, Illinois and other states received notification that USEPA had found a
failure to submit a SIP addressing the Phase II requirements . Exhibit B
. On February 8, 2006,
USEPA published the findings of failure to submit Phase II SIPs, but it has not yet published a
federal implementation plan for Phase II or started a Section 179 sanctions clock
. 71 Fed
. Reg
.
6347 (February 8, 2006).
III. AUTHORITY FOR RULEMAKING
A. Section 9.9 ofthe Act
Section 9 .9(b) of the Act requires Illinois EPA to propose and the Board to adopt
regulations for the control of NO, emissions from stationary internal combustion engines .
B. Section 10 of theAct
Section 10(A) of the Act provides the Board's general authority for rulemaking
addressing air pollution :
The Board, pursuant to procedures prescribed in Title VII of this Act, may adopt
regulations to promote the purposes of this Title . Without limiting the generality of this
authority, such regulations may among other things prescribe . . . ambient air quality
standards . . . emissions standards . . . standards for issuance of permits
. . .
415 ILCS 5/10(A) . It is pursuant to this Section, and Sections 9
.9, 27, and 28 .5 of the Act, that
Illinois EPA is submitting this regulatory proposal . As discussed above, not only are the
proposed regulations necessary to meet the State's obligations under the NO, SIP Call, they are
Page 7
also necessary to meet the State's obligations under the CAA to attain the two new NAAQS
: 8-
hour ozone and
PM2,5 . With respect to ozone and PM25
, and as noted above, USEPA has
identified emissions of NO, as a precursor to ozone and PM
2 5 formation in the atmosphere . As
part of the steps needed for Illinois to demonstrate attainment and to meet RFP requirements for
the 8-hour ozone and the PM 2 5
NAAQS, Illinois EPA must adopt and implement regulations for
control of NO, emissions that meet these federal requirements, including implementation of
RACT for large sources of NO, in nonattainment areas
.
C.
Section 28 .5 of the Act
This regulatory proposal is properly submitted to the Board under Section 28
.5 of the Act
as a fast-track rulemaking proceeding . Section 28
.5 of the Act "shall apply solely to the adoption
of rules proposed by Illinois EPA and required to be adopted by the State under the Clean Air
Act as amended by the Clean Air Act Amendments (CAAA) ." 415 ILCS 5/28
.5(a) . A fast-track
rulemaking proceeding is
:
a proceeding to promulgate a rule that the CAAA requires to be adopted
. For purposes of
this Section, 'requires to be adopted' refers only to those regulations or parts of
regulations for which the United States Environmental Protection Agency is empowered
to impose sanctions against the State for failure to adopt such rules
.
415 ILCS 5/28
.5(c) . Further, Section 28
.5(d) of the Act provides, "When the CAAA requires
rules other than identical in substance rules to be adopted, upon request by Illinois EPA, the
Board shall adopt rules under fast-track rulemaking requirements
." 415 ILCS 5/28 .5(d) .
Illinois EPA meets the criteria set forth by Section 28
.5 of the Act
. This Section provides
in pertinent part :
(a) This Section shall apply solely to the adoption of rules proposed by the Agency and
required to be adopted by the State under the Clean Air Act as amended by the Clean Air
Act Amendments of 1990 (CAAA)
.
Page 8
(c) For purposes of this Section, a "fast-track" rulemaking proceeding is a proceeding
to promulgate a rule that the CAAA requires to be adopted . For purposes of this Section,
"requires to be adopted" refers only to those regulations or parts of regulations for which
the United States Environmental Protection Agency is empowered to impose sanctions
against the State for failure to adopt such rules . All fast-track rules must be adopted under
procedures set forth in this Section, unless another provision of this Act specifies the
method for adopting a specific rule .
415 ILCS 5/28 .5 . Section 28.5 of the Act provides that it applies solely to the adoption of rules
proposed by Illinois EPA that are required to be adopted by the State under the CAAA . The
phrase "requires to be adopted" refers to rules for which the USEPA is empowered to impose
sanctions against the State for failure to adopt such rules . Section 28.5 of the Act also states that
a fast-track rulemaking must be for rules other than "identical in substance" rules . Illinois EPA's
rulemaking proposal here meets all the criteria of Section 28 .5 .
Illinois EPA's regulatory proposal to require Phase II is clearly required to be adopted by
the CAA
. The NO, SIP Call was promulgated under Section 110(a)(2)(D) of the CAA, which
requires states to develop SIPs to ensure that emissions from a source or group of sources do not
significantly contribute to nonattainment, or interfere with maintenance, of a NAAQS in other
states
. In addition to meeting the requirements of Section 110(a)(2)(D) of the CAA, adoption of
the Phase II rules and NO,, emission control regulations for engines and turbines, are also
necessary for the State to meet the requirements of Sections 172 and 182 of the CAA for
submitting attainment demonstrations, RACT, and RFP
. If a state fails to submit plans as
required for the NO, SIP Call Phase II, attainment demonstrations, RACT, or RFP, USEPA has
the authority to impose a Federal Implementation Plan
("FIP") pursuant to its authority under
Section 110(c)(1) of the CAA
.
Another component of Section 28 .5 of the Act concerns the criteria that the rule that is
required to be adopted must subject the State to sanctions from USEPA if the State fails to adopt
Page 9
such rule
. Pursuant to Section 179, two different sanctions are available to USEPA should
Illinois EPA fail to adopt rules that would allow for the submission of an approvable SIP
: 1) the
loss of highway funds
; and 2) the increase in the emissions offset requirement for New Source
Review to 2:1 .
USEPA triggers "sanctions" by making a finding of substantial inadequacy under
Section 110(k)(5) of the CAA known as a "SIP Call ." Such a finding is made whenever
USEPA finds that a State has a plan for any area is substantially inadequate to attain or maintain
the relevant NAAQS
. By its very tenor, a plan that fails to demonstrate attainment would be
substantially inadequate and would trigger Section 179 sanctions :
(a) State Failure
.--For any implementation plan or plan revision required under
this part (or required in response to a finding of substantial inadequacy as
described in section 1 10(k)(5)), if the Administrator
(3)(A)
determines that a State has failed to make any submission as may be
required under this Act, other than one described under paragraph (1) or (2),
including an adequate maintenance plan, or has failed to make any submission, as
may be required under this Act, other than one described under paragraph (1) or
(2),
that satisfies the minimum criteria established in relation to such submission
under section 110(k)(1)(A) . . . .
42 U.S.C. 7509(a) .
As discussed supra, without these regulations, Illinois will not be able to
submit a plan that would demonstrate attainment or meet RACT or ROP requirements for the
PM2.5
or 8-hour ozone NAAQS .
Not only will Illinois need the reductions from the State's rule to implement the federal
Clean Air Interstate Rule ("CAIR") to attain these NAAQS, it will need additional reductions as
well
. The Board has determined in the past that regulations adopted in order to obtain the
reductions needed for attainment demonstrations and meeting other requirements under Section
182 of the CAA warranted the use of Section 28
.5 of the Act to avoid sanctions
. Further, the
Page 1 0
Board has the authority to adopt regulations to avoid sanctions for a failure to meet the
requirements of Section 172 of the CAA as t is also contained in Part D of the CAA . See, In
the Matter of: 15% ROP Plan Control Measures for VOM Emissions-Part II Marine Vessel
Loading: Amendments 35111 . Adm
. Code Parts 211, 218 and 219, R94-15, October 25, 1994 ;
and In the Matter of
: Visible and Particulate Matter Emissions-Conditional Approval and Clean
Up Amendments to 35 111 . Adm. Code Parts 211 and 212, R96-5, May 22, 1996 . Thus, through
past practice and as confirmed by relevant case law, the Board has recognized that failure to
adopt regulations proposed for the purposes of meeting the requirements of Part D of the CAA
would satisfy the requirements for a Section 28
.5 rulemaking .
The remaining criterion as set out in Section 28 .5 of the Act is that the subject
rulemaking not be an identical in substance proposal . Subpart Q is being proposed to meet three
federal CAA requirements and does not mirror any federal guidance or rule
. Hence, Illinois
EPA's proposal is not identical in substance . For all these reasons, this rulemaking properly
appears before the Board under the fast-track provisions of Section 28
.5 of the Act as all
described criteria of that section have been met .
IV. GEOGRAPHIC REGIONS AND SOURCES AFFECTED
The geographic region subject to "Subpart Q
: Stationary Reciprocating Internal
Combustion Engines and Turbines" is the entire State of Illinois
. The proposed regulations are
expected to affect existing and new units as described below
. There are 28 existing engines that
were identified by the NO, SIP Call that will be subject to Subpart
. TSD at 7 .1 . Existing NO,
SIP Call engines were those identified as emitting one ton a day or more in 1995
. In Illinois, 28
engines were identified, 25 at gas pipeline facilities and three at a chemical manufacturing
company. The NOx
SIP Call engines are listed in proposed Appendix G . Other engines that will
Page 11
be affected by this proposal are those that are rated at 500 bhp or greater
. There are 1,200
engines rated at or greater than 1,500 bhp, and 175 engines rated between 500 bhp and 1,500
bhp. Of these, 202 of the larger engines are potentially impacted as are 44 of the smaller
engines. Turbines that will be affected are those rated at 3 .5 MW or greater. TSD at 7
.2 and 7 .3
.
There are 205 turbines rated at 3
.5 MW or greater. Of these, 36 are expected to be affected by the
rule
. TSD at 7 .2 .
V.
PURPOSE AND EFFECT OF THE PROPOSAL
As discussed below, this proposal has been prepared to meet portions of several
obligations of Illinois under the CAA ; namely, reductions necessary to assist the State in
reaching attainment of the PM 2.5 and 8-hour ozone NAAQS, NO, RACT for large engines and
turbines located in the two nonattainment areas for both NAAQS, RFP, and Phase II of the NO,
SIP Call .
A. Reductions
needed for attainment of the NAAQS
Both USEPA's findings and the Lake Michigan Air Directors Consortium ("LADCO")
modeling confirm that existing control programs will not be enough to provide for attainment of
the 8-hour and PM 2.5 NAAQS in Illinois . As such, additional reductions of NO, emissions from
sources in attainment and nonattainment areas will be necessary. TSD at 2.5 . Nonattainment is
shown in the Chicago area for both 8-hour ozone and PM2 .5, and in the Metro-EasUSt . Louis area
for PM2,5 , even with implementation of CAIR . By 2010, CAIR does not provide significant
reductions beyond those provided for in the NO, SIP Call . Although modeling work is ongoing,
sufficient modeling has been conducted thus far by USEPA, LADCO, and the Illinois EPA to
justify this proposal to require reductions in NO, emissions statewide, including sources
(engines, turbines, and other NO, emission sources) located in attainment areas as part of
Page 12
Illinois' plan to attain the 8-hour ozone and PM 2 5 NAAQS in Illinois, even prior to the full
implementation to CAIR .
The proposed regulations will, when fully implemented in 2012, reduce NO, emissions
statewide by approximately 17,869 tons per year and 7,540 tons per ozone control season
. TSD
at 8 .3
. This equates to a 65 percent NO, reduction annually and a 55 percent NO, emission
reduction in the ozone season
. TSD at 8 .4.
B. NO, RACT
States are required to submit SIPs addressing RACT for precursors of ozone, which
includes NO
N. Major sources in moderate nonattainment areas are defined as those that have the
potential to emit 100 tons or more of NO, in a nonattainment area
. States are also required to
submit SIPS addressing RACT for precursors of PM 2 .5, which includes NOR.
While USEPA has
not yet finalized the guidance for implementing the PM 2 .5 NAAQS, its proposal indicates that the
RACT requirement will apply to 100 ton sources, and may include smaller units as well . The
applicability includes such units
. The NO, control levels proposed are considered reasonable,
attainable and cost-effective . TSD at 6 .3 .
C.
NO, SIP Call Phase II
The NO, SIP Call Phase II specifically requires affected states to meet a NO, budget that
represents 82 percent control of large stationary internal combustion engines
. The proposal
would control these engines reducing base emissions by 5,422 tons per ozone season to 1,196
tons per ozone season
. TSD at 8 .1 . This meets the NO, SIP Call Phase II requirements
.
VI. TECHNICAL FEASIBILITY AND ECONOMIC REASONABLENESS
Emissions of NO, from stationary internal combustion engines are not currently regulated
in the State of Illinois
. Only turbines rated at 250 mmBtu/hr are regulated pursuant to 35 111 .
Page 13
Adm . Code 217 .
Subpart Q is expected to reduce NO, emissions by 17,869 tons per year and 7,540 tons
per ozone season beginning in 2012
. TSD at 8 .3 . Illinois EPA's staff has determined that
affected engines and turbines can meet the requirements of proposed Subpart Q through a
combination of control techniques such that compliance is both technically feasible and
economically reasonable
. Control techniques for reducing NO, emissions from engines include
air/fuel ratio adjustments, low emission combustion ("LEC"),
prestratified charge and non-
selective catalytic reduction
. Gas turbines can use water/steam injection, dry low NO,
combustors as control strategies
. Both engines and turbines can use selective catalytic reduction
("SCR").
Reductions from the engine technologies range from 10 to 40 percent for air/fuel
ration adjustments to 70 to 90 percent for LEC
. Reductions from the turbine technologies range
from 70 to 90 percent for the water/steam injection to 60 to 90 percent for low NO, combustors
.
TSD at 4.9.
Based on USEPA's Alternative Control Techniques
("ACT") document, with which
Illinois EPA staff agrees, there are a number of control options available which achieve the
control levels proposed in this rulemaking in the range of unit sizes affected
. Cost effectiveness
for large NO, SIP call engines ranged from $522 per ton of NO, reduced by gas-fired engines to
$1,000 per ton of NO, reduced by oil-fired engines
. TSD at 5 .1 . The cost effectiveness for
retrofitting engines ranges from $496 to $2,436 per ton of NO, reduced and for turbines ranges
from $712 to $2,189 per ton of NO, reduced in 2004 dollars
. TSD at 5 .2 .
In addition, Illinois EPA's staff found that the levels proposed in this rule were consistent
with rules promulgated in other states
. Typical NO, RACT limits range from 105 to 210 ppm for
gas-fired rich- and lean-burn engines
. The size cut-off for engines required to control NO,
Page 14
emissions ranges from 50 bhp to 500 blip
. In addition, several states have promulgated rules
limiting NO, emissions from turbines . TSD at 6 .2
. Texas, New York, New Jersey, and
California South Coast all have regulatory requirements for smaller turbines
.
VII.
COMMUNICATION WITH INTERESTED PARTIES
Illinois EPA held three general meetings (August 25, 2005, October 5, 2005, and
November 14, 2005) to which owners and operators of affected units and environmental groups
were invited
. At least three additional meetings were held at the request of particular groups or
companies affected by this proposal .
Throughout the development of the rule, Illinois EPA has received extensive comments
.
These amendments are being proposed after representatives of industry and environmental
groups have had an opportunity to review the proposed changes, discuss any issues and provide
comments to Illinois EPA .
The areas in which the parties have reached agreement are the
applicability level for engines and turbines, use of an emissions averaging plan as a method of
compliance, use of continuous emissions monitoring system ("CEMS") in lieu of certain testing
and monitoring requirements, the exemptions, the frequency of testing, treatment of low usage
units (e.g.,
by bhp-hr/MW-hr and treatment of sources with NO, emissions of less than 100 tons
per year), and the use of NO, allowances to address unexpected noncompliance issues
. The areas
where the parties have not reached agreement include the statewide applicability of the rule
.
However, the Illinois EPA is proceeding with the proposal because the overall benefit of the rule
outweighs the detriment of further delay
. The Illinois EPA has presented and discussed with the
stakeholders the need for statewide reductions of NO, emissions from sources located in both
attainment and nonattainment areas in order to achieve the 8-hour and PM2
. 5 NAAQS
. The
Illinois EPA has also addressed some concerns raised by these parties by including averaging
Page 15
and low usage provisions in the proposal, as well as, stretching the compliance schedule .
VIII. ILLINOIS EPA'S PROPOSAL
35 I11 .Adm. Code 201 : SUBPART C : PROHIBITIONS
Section 201 .146 Exemptions from State Permit Requirements
Illinois EPA is proposing to amend subsection (i) of this Section to reflect the
requirement that an engine or turbine required to comply with the requirements of Subpart Q
must obtain a permit. In addition, the heading of the exemption is being amended to reflect that
the criteria of the exemption apply to both engines and turbines and the exemption for turbines is
being clarified as it does not apply to engines .
35111.Adm. Code 211 :SUBPART B : DEFINITIONS
Illinois EPA is proposing to add four definitions and amend the definition for
emergency/standby unit to Part 211
.
Section 211 .740 Brakehorsepower (rated-bhp)
Illinois EPA is proposing to add a definition for brakehorsepower . This definition is
needed to define which engines will be subject to the requirements of Subpart Q
.
Section 211 .1740 Diesel Engine
Illinois EPA is proposing to add a definition for "diesel engine
." This definition is
needed to define what level of control the affected engine will be subject to pursuant to the
requirements of Subpart Q .
Section 211
.1920 Emergency or Standby Unit
Illinois EPA is proposing to amend the definition of "emergency or standby unit ." This
definition is being amended to clarify that the exemption from the requirements of Subpart Q for
"emergency or standby unit(s)" is limited to circumstances unrelated to the unit being used to
Page 16
supplement power capacity and that testing the unit or verifying the unit's readiness for use does
not disqualify the unit as an emergency or standby unit .
Section 211 .3300 Lean-Burn Engine
Illinois EPA is proposing to add a definition for "lean-bum engine ." This definition is
needed to define what level of control the affected engine will be subject to pursuant to the
requirements of Subpart Q .
Section 211 .5640 Rich-Burn Engine
Illinois EPA is proposing to add a definition for "rich-bum engine ." This definition is
needed to define what level of control an affected engine will be subject to pursuant to the
requirements of Subpart Q .
35111. Adm. Code 217 : SUBPARTA:GENERAL PROVISIONS
Section 217 .101 Measurement Methods
Illinois EPA is proposing two types of amendments to this Section
. First, it is proposing
to strike the date that USEPA last updated the applicable methods . The dates for these methods
will be included in the Section 217 .104 : Incorporations by Reference . Second, it is also
proposing is to add a method for monitoring NO, using portable monitors .
Section217.102 Abbreviations
and Units
Illinois EPA is proposing to add the abbreviations and conversion factors used in Subpart
Q and to correct the alphabetical order of the existing list .
Section 217 .104 Incorporations by Reference
Illinois EPA is proposing to update the incorporations by reference, except for 40 CFR
96, add the American Society Testing and Methods ("ASTM") for portable monitors, and test
methods for NO,, emissions from engines and turbines .
Page
17
PART 217 : SUBPARTQ
: STATIONARY RECIPROCATING INTERNAL
COMBUSTION ENGINES AND TURBINES
Section 217.402 Applicability
Subsection (a) provides that the requirements of the Subpart apply to stationary
reciprocating internal combustion engines rated 500 bhp and above, and turbines rated 3
.5 MW
and above
. Subsection (b) provides that certain engines and turbines that meet the rating
requirements of subsection (a) be exempt from the requirements of the Subpart
. Proposed
exemptions include units meeting the definition for emergency and standby
; units used for
research or performance verification
; units that control gas from a landfill, where 50 percent or
more of the heat input is gas from a landfill
; units used for agricultural purposes, e.g., raising
livestock and crops, but not for associated businesses
; portable units ; and units that are regulated
by Subpart W or other federal NO, trading program.
Subsection (c) provides that if a unit ceases to meet the exemption criteria, the owner or
operator must notify Illinois EPA within 30 days of becoming aware that the unit is no longer
exempt and comply with the requirements of the Subpart
. Subsection (d) provides that if an
affected unit has ever been subject to the control requirements of the Subpart, it will remain
subject to the requirements even if it ceases to meet the rating criteria or becomes eligible for an
exemption .
Section 217 .388 Control
and Maintenance Requirements
In this Section, Illinois EPA is proposing control and maintenance requirements
.
Subsection (a) provides separate concentration limits for engine and turbines by type and fuel
used
. Subsection (b) provides that owners and operators be allowed the option of complying
with an emissions averaging plan instead of concentration limits
. Subsection (c) provides that
Page 18
certain low usage units be exempt from the requirement to comply with the concentration limits
if the aggregate usage of the units meets certain limits and is contained in a federally enforceable
permit, unless the unit is located at a gas transmission compression station or storage facility .
The aggregate usage from all such units at the source that are not otherwise exempt and are not
complying with the control requirements of the Subpart must be less than 5 mm bhp-hrs for
engines or 20,000 MW-hrs or less for turbines . The aggregate for each type of unit, e .g ., engines
or turbines, is calculated separately
. Subsection (d) requires owners and operators to perform
periodic maintenance . Maintenance and inspection must be done in accordance with a
maintenance plan based on the manufacturer's recommendations, unless the unit is located at a
gas transmission compressor station or storage facility . Owners and operators of such units may
use the procedures contained in the applicable air pollution permit . In addition, if the original
equipment manual is not available, the maintenance and inspection shall be done in accordance
with what is customary for the type of unit and air pollution control equipment .
Section 217.390 Emissions Averaging Plans
This Section provides that owners and operators may comply with an emissions
averaging plan in lieu of meeting the specified concentration limit for each affected unit set forth
in Section 217 .388
. Subsection (a)(1) describes the types of units that may be included in an
emissions averaging plan . These units include : any unit located in Illinois as long as the units are
owned by the same company or parent company and are not included in more than one plan ;
units that have a compliance date later than the control period for which the averaging plan is
being used for compliance
; and units that could be claimed as exempt pursuant to Section
217.386(b)
. If an exempt unit is included in an emissions averaging plan, it will be treated as an
Page 19
affected unit with respect to concentration limits, testing, monitonng, recordkeeping and
reporting requirements
.
Subsection (a)(2)
describes the types of units that may not be included in an emissions
averaging plan
. Two types of affected units may not be included in averaging plans
: 1) units
that commence operation on or after January 1, 2002, unless the unit replaces a unit that
commenced operation prior to this date or is a unit that replaced an engine or turbine that
replaced a unit that commenced operation prior to this date, and the unit is used for the same
purpose
; and 2) units that the owner or operator is claiming as exempt
.
Subsection (b) provides the requirements for submitting an emissions averaging plan
.
The owner or operator must submit the emissions averaging plan by the applicable compliance
date
. The plan must include a list of affected units by unit identification and a sample calculation
demonstrating compliance using the methodology provided in subsection
(f).
Subsection (c)
limits amendment of the emissions averaging plan to once a year
. If an amendment for a
calendar year is going to be submitted, it must be submitted no later than May I of the applicable
year
; otherwise, the plan from the previous year will be the applicable plan
. Subsection (d)
requires that if an affected unit included in a plan is sold or taken out of service, the owner or
operator, and the buyer, if applicable, must submit an updated emissions averaging plan within
60 days of the occurrence
. Subsection (d) also allows an owner or operator to amend its
emissions averaging plan if a unit no longer qualifies as exempt or low usage, so long as the plan
is submitted with 30 days of discovery
.
Subsection (e) requires an owner or operator to demonstrate compliance on both the
ozone season and calendar year basis
. Compliance is demonstrated using the methodology in
subsection (f) using the most recent monitoring data or test results
. Owners and operators are
Page 20
also required to notify Illinois EPA by October 31 following the ozone season if they cannot
demonstrate compliance for that ozone season . Finally, owners and operators must submit a
compliance report by January 31 following the applicable calendar year .
Subsection (1) provides the averaging formula that must be used to demonstrate
compliance . The total mass of actual NO, emissions from all affected units included in the
emissions averaging plan must be less than the total mass of allowable NO x emissions for the
same units . Subsections (g)(1) and (g)(2)
provide formulas for determining a unit's actual and
allowable emissions by fuel type . Subsection (g)(3) provides a specific formula for electric
replacement units
. Subsection (g)(4) provides a formula for non-electric replacement units.
Subsection (g)(5) provides a formula for units that have been replaced through the purchase of
power and limits the use of purchased power to five years. Subsection (g)(6) provides criteria
for determining the allowable emissions for units with a later compliance date . Subsection (h)
provides conditions for units using CEMS in lieu of stack testing and portable monitoring .
Section 217 .398 Compliance
Subsection (a) provides four different compliance dates . Subsection (a)(1) requires that
engines subject to the NO, SIP Call, as listed in Appendix G, comply by May 1, 2007 .
Subsection (a)(2) requires that units located in either of the 8-hour ozone or PM2 .5 nonattainment
areas comply by January 1, 2009 . Subsection (a)(3) requires that engines and turbines located
outside of the two nonattainment areas and rated at 1,500 bhp or more, or five MW or more
comply by January 1, 2011 . Subsection (a)(4) requires that the smaller engines and turbines
comply by January 1, 2012 .
Subsection (b) provides that owners and operators may use NO, allowances to meet the
compliance requirements of Section 217 .388 if they meet certain criteria . Subsection (b)(1)
Page
21
provides that use is limited to circumstances where all of the following conditions have been
met. First, noncompliance must be due to unforeseen circumstances
. Second, allowances may
be used no more than twice in any five-year rolling period
. Finally, allowances may not be used
for a unit listed in Appendix G . Subsection (b)(2) provides that the correct type of NO,
allowances must be used, e .g.,
an annual allowance for an exceedance of an annual limit and an
ozone season allowances for an exceedance of a seasonal limit . Subsection
(b)(3)
provides that
the owner or operator must submit a report documenting the circumstances that required the use
of allowances and the actions that will be taken to address these circumstances
. In addition, the
report must contain the NO, Allowance Tracking System ("NATS") serial numbers of the
allowances.
Section 217.394 Testing and Monitoring
Subsection (a) provides that affected units conduct a compliance test by the applicable
compliance date . Subsection
(a)(1) provides that engines listed in Appendix G must be tested by
May 1, 2007 . Subsection (a)(2)
provides that affected units and units included in emissions
averaging plans be tested by the applicable compliance date in Section 217
.392 or within the first
876 hours of operation . Subsection
(a)(3) provides that units that operate less than 876 hours per
calendar year be tested once within the five-year period after the compliance date
.
Subsection (b) provides the requirements for performing subsequent tests
. Subsection
(b)(1) provides that units listed in Appendix G and units in an emissions averaging plan must be
tested once every five years and that testing must be done by May 1 or within 60 days of starting
operation, whichever is later . Subsection
(b)(2) provides that if monitoring data shows that the
unit is not in compliance, the owner or operator must notify Illinois EPA within 30 days of the
finding that the unit is not in compliance with the applicable concentration limit or emissions
Page 22
averaging plan and the unit must also be tested
. Finally, subsection (b)(3) provides that Illinois
EPA or USEPA may require testing to demonstrate compliance at the owner or operator's
expense
.
Subsection (c) provides the testing procedures . Owners and operators of engines must
use Method 7 or 7E or 40 CFR 60, Appendix E . Each test must consist of three runs and be at
least 60 minutes long. If a unit combusts more than one type of fuel, a separate test is required
for each type of fuel . Owners and operators of turbines must comply with the testing provisions
of 40 CFR 60.4400 .
Subsection (d) provides that owners and operators of affected units perform annual
monitoring to determine compliance, except in years in which a compliance test is performed or
for units that operate less than 876 hours per calendar year and then only once every five years .
Monitoring must be completed each year by May 1 or within 60 days of starting operation for
that calendar year . Measurements of NO, and 02 concentrations must be taken three times for a
duration of at least 20 minutes while the unit is operating at the highest achievable load
.
Subsection (e) provides that units equipped with a CEMS meeting the applicable
requirements of 40 CFR 60, subpart A and Appendix B, or alternate procedures as approved by
Illinois EPA or USEPA in a federally enforceable permit, not be required to comply with the
compliance testing and annual monitoring requirements of this Section . Compliance will be
required on an ozone season and calendar year basis .
Section 217 .396 Recordkeeping and Reporting
Subsection (a) provides that owners and operators of affected units that are not exempt
and not low usage units maintain records that demonstrate compliance with the Subpart
.
Subsection (b) provides that owners and operators of low usage units maintain either records of
Page 23
NO, emissions for the calendar year or bhp or MW hours operated for the calendar year, as
applicable
. Subsection (c) provides that owner's and operator's records be maintained for five
years.
Subsection (d) provides that owners or operators report the following
: notification prior
to testing; a testing protocol ; and the test results . In addition, owners and operators are required
to report : monitored exceedances
; permanent shutdowns of affected units ; if demonstrating
compliance through an emissions averaging plan, notification of failure to comply with the ozone
season plan, if applicable, and an annual compliance report ; if using a CEMS, an excess
emissions and monitoring systems report
; and if using NO, allowances to comply, a
reconciliation report.
Appendix G Large Existing Reciprocating Internal Combustion Engines
In Appendix G, Illinois EPA is proposing to add a list of the NO x
SIP Call engines based
on how the unit is listed in the most recent permit issued or construction permit application
submitted .
Page 24
DATED
: March 27, 2007
1021 North Grand Ave . East
P.O. Box 19276
Springfield, IL 62794-9276
IX. CONCLUSION
For the reasons stated above, Illinois EPA hereby submits this regulatory proposal and
respectfully requests that the Board expeditiously adopts these rules for the State of Illinois .
Respectfully submitted,
ILLINOIS ENVIRONMENTAL
PROTECTION AGENCY
i
By:
Rachel L . Doctors
Assistant Counsel
Division of Legal Counsel
Page
25
Section
201 .101
Other Definitions
201 .102
Definitions
201 .103
Abbreviations and Units
201
.104
Incorporation by Reference
ILLINOIS REGISTER
9. a
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
TITLE 35 : ENVIRONMENTAL PROTECTION
SUBTITLE B : AIR POLLUTION
CHAPTER I: POLLUTION CONTROL BOARD
SUBCHAPTER a: PERMITS AND GENERAL PROVISIONS
PART 201
PERMITS AND GENERAL PROVISIONS
SUBPART A: DEFINITIONS
SUBPART B : GENERAL PROVISIONS
Section
201 .121
Existence of Permit No Defense
201 .122
Proof of Emissions
201 .123
Burden of Persuasion Regarding Exceptions
201 .124
Annual Report
201 .125
Severability
201 .126
Repealer
SUBPART C : PROHIBITIONS
Section
201 .141
Prohibition of Air Pollution
201 .142
Construction Permit Required
201 .143
Operating Permits for New Sources
201 .144
Operating Permits for Existing Sources
201 .146
Exemptions from State Permit Requirements
201 .147
Former Permits
201 .148
Operation Without Compliance Program and Project Completion Schedule
201 .149
Operation During Malfunction, Breakdown or Startups
201 .150
Circumvention
201 .151
Design of Effluent Exhaust Systems
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
SUBPART D
: PERMIT APPLICATIONS AND REVIEW PROCESS
Section
201 .152
Contents of Application for Construction Permit
201 .153
Incomplete Applications (Repealed)
201 .154
Signatures (Repealed)
201 .155
Standards for Issuance (Repealed)
201 .156
Conditions
201 .157
Contents of Application for Operating Permit
201 .158
Incomplete Applications
201 .159
Signatures
201 .160
Standards for Issuance
201 .161
Conditions
201 .162
Duration
201 .163
Joint Construction and Operating Permits
201 .164
Design Criteria
201 .165
Hearings
201 .166
Revocation
201 .167
Revisions to Permits
201 .168
Appeals from Conditions
201 .169
Special Provisions for Certain Operating Permits
201 .170
Portable Emission Units
SUBPART E
: SPECIAL PROVISIONS FOR OPERATING PERMITS FOR CERTAIN
SMALLER SOURCES
Section
201 .180
Applicability (Repealed)
201 .181
Expiration and Renewal (Repealed)
201 .187
Requirement for a Revised Permit (Repealed)
SUBPART F: CAAPP PERMITS
Section
201 .207
Applicability
201 .208
Supplemental Information
201 .209
Emissions of Hazardous Air Pollutants
201 .210
Categories of Insignificant Activities or Emission Levels
201 .211
Application for Classification as an Insignificant Activity
201 .212
Revisions to Lists of Insignificant Activities or Emission Levels
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
SUBPART G
: EXPERIMENTAL PERMITS
(Reserved)
SUBPART H : COMPLIANCE PROGRAMS AND PROJECT COMPLETION
SCHEDULES
Section
201 .241
Contents of Compliance Program
201 .242
Contents of Project Completion Schedule
201 .243
Standards for Approval
201 .244
Revisions
201 .245
Effects of Approval
201 .246
Records and Reports
201 .247
Submission and Approval Dates
SUBPART I: MALFUNCTIONS, BREAKDOWNS OR STARTUPS
Section
201 .261
Contents of Request for Permission to Operate During a Malfunction,
Breakdown or Startup
201 .262
Standards for Granting Permission to Operate During a Malfunction,
Breakdown or Startup
201
.263
Records and Reports
201 .264
Continued Operation or Startup Prior to Granting of Operating Permit
201 .265
Effect of Granting of Permission to Operate During a Malfunction,
Breakdown or Startup
SUBPART J
: MONITORING AND TESTING
Section
201 .281
Permit Monitoring Equipment Requirements
201.282
Testing
201 .283
Records and Reports
SUBPART K: RECORDS AND REPORTS
Section
201 .301
Records
201 .302
Reports
SUBPART L : CONTINUOUS MONITORING
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
Section
201 .401
Continuous Monitoring Requirements
201 .402
Alternative Monitoring
201
.403
Exempt Sources
201 .404
Monitoring System Malfunction
201 .405
Excess Emission Reporting
201 .406
Data Reduction
201 .407
Retention of Information
201 .408
Compliance Schedules
201
.APPENDIX A Rule into Section Table
201 .APPENDIX B
Section into Rule Table
201 .APPENDIX C Past Compliance Dates
AUTHORITY : Implementing Sections 10, 39, and 39 .5 and authorized by Section 27 of
the Environmental Protection Act [415 ILCS 5/10, 27, 39, and 39 .5] .
SOURCE: Adopted as Chapter 2 : Air Pollution, Part I : General Provisions, in R71-23, 4
PCB 191, filed and effective April 14, 1972 ; 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. 13579; amended in R82-1
(Docket A) at 10111. Reg. 12628, effective July 7, 1986 ; amended in R87-38 at 13 Ill.
Reg. 2066, effective February 3, 1989 ; amended in R89-7(A) at 13 Ill . Reg. 19444,
effective December 5, 1989 ; amended in R89-7(B) at 15 Ill . Reg. 17710, effective
November 26, 1991 ; amended in R93-11 at 17111 . Reg. 21483, effective December 7,
1993; amended in R94-12 at 18 Ill. Reg. 15002, effective September 21, 1994
; amended
in R94-14 at 18 Ill . Reg. 15760, effective October 17, 1994 ; amended in R96-17 at 21111 .
Reg
. 7878, effective June 17, 1997
; amended in R98-13 at 22111 . Reg. 11451, effective
June 23, 1998 ; amended in R98-28 at 22 Ill . Reg. 11823, effective July 31, 1998 ;
amended in R02-10 at 27 Ill . Reg. 5820, effective March 21, 2003 ; amended in R05-19
and R05-20 at 30 Ill . Reg. 4901, effective March 3, 2006 ; amended in R07- at
Ill. Reg. , effective , 2007 .
SUBPART C: PROHIBITIONS
Section 201 .146
Exemptions from State Permit Requirements
Construction or operating permits, pursuant to Sections 201 .142, 201 .143 and 201
.144 of
this Part, are not required for the classes of equipment and activities listed below in this
Section. The permitting exemptions in this Section do not relieve the owner or operator
of any source from any obligation to comply with any other applicable requirements,
including the obligation to obtain a permit pursuant to Sections 9 .1(d) and 39 .5 of the
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
Act, Sections 165, 173 and 502 of the Clean Air Act or any other applicable permit or
registration requirements . . .
i)
Any stationary turbine or
internal combustion engine with a rated power
output of less than 1118 kW (1500 bhp horsepower), except that a permit
shall be required for the following:
1) Anyany stationary gas turbine engine with a rated heat input at
peak load of 10
.7 gigajoules/hr (10 mmbtu/hr) or more that is
constructed, reconstructed or modified after October 3, 1977 and
that is subject to requirements of 40 CFR 60, Subpart GG ; or
2) Any internal combustion engine with a rating at equal to or greater
than 500 bhp output that is subject to the control requirements of
35 Ill. Adm. Code Part 217
.Subpart 0.
(Source: Amended at - Ill. Reg. , effective )
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
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
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
9.b
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
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 .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
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 .1010
Clean Air Act
211 .1050
Cleaning and Separating Operation
211 .1070
Cleaning Materials
211
.1090
211 .1110
211 .1120
211 .1130
211 .1150
211 .1170
211 .1190
211 .1210
211 .1230
211 .1250
211 .1270
211 .1290
211 .1310
211 .1312
211 .1316
211 .1320
211 .1324
211
.1328
211 .1330
211 .1350
211 .1370
211 .1390
211 .1410
211 .1430
211 .1465
211 .1467
211
.1470
211 .1490
211 .1510
211
.1515
211 .1520
211 .1530
211 .1550
211 .1570
211 .1590
211 .1610
211 .1630
211 .1650
211 .1670
211 .1690
211 .1710
211 .1730
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
Clear Coating
Clear Topcoat
Clinker
Closed Purge System
Closed Vent System
Coal Refuse
Coating
Coating Applicator
Coating Line
Coating Plant
Coil Coating
Coil Coating Line
Cold Cleaning
Combined Cycle System
Combustion Turbine
Commence Commercial Operation
Commence Operation
Common Stack
Complete Combustion
Component
Concrete Curing Compounds
Concentrated Nitric Acid Manufacturing Process
Condensate
Condensible PM-10
Continuous Automatic Stoking
Continuous Coater
Continuous Process
Control Device
Control Device Efficiency
Control Period
Conventional Air Spray
Conventional Soybean Crushing Source
Conveyorized Degreasing
Crude Oil
Crude Oil Gathering
Crushing
Custody Transfer
Cutback Asphalt
Daily-Weighted Average VOM Content
Day
Degreaser
Delivery Vessel
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
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
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 .2360
211 .2365
211 .2370
211 .2390
211 .2410
211 .2420
211 .2425
211 .2430
211
.2450
211 .2470
211 .2490
211 .2510
211 .2530
211
.2550
211 .2570
211 .2590
211 .2610
211 .2620
211 .2630
211 .2650
211 .2670
211 .2690
211 .2710
211 .2730
211 .2750
211.2770
211 .2790
211 .2810
211 .2815
211 .2820
211 .2830
211.2850
211 .2870
211 .2890
211 .2910
211
.2930
211 .2950
211 .2970
211 .2990
211 .3010
211 .3030
211 .3050
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
Flexible Coating
Flexible Operation Unit
Flexographic Printing
Flexographic Printing Line
Floating Roof
Fossil Fuel
Fossil Fuel-Fired
Fountain Solution
Freeboard Height
Fuel Combustion Emission Unit or Fuel Combustion Emission Source
Fugitive Particulate Matter
Full Operating Flowrate
Gas Service
Gas/Gas Method
Gasoline
Gasoline Dispensing Operation or Gasoline Dispensing Facility
Gel Coat
Generator
Gloss Reducers
Grain
Grain-Drying Operation
Grain-Handling and Conditioning Operation
Grain-Handling Operation
Green-Tire Spraying
Green Tires
Gross Heating Value
Gross Vehicle Weight Rating
Heated Airless Spray
Heat Input
Heat Input Rate
Heatset
Heatset Web Offset Lithographic Printing Line
Heavy Liquid
Heavy Metals
Heavy Off-Highway Vehicle Products
Heavy Off-Highway Vehicle Products Coating
Heavy Off-Highway Vehicle Products Coating Line
High Temperature Aluminum Coating
High Volume Low Pressure (HVLP) Spray
Hood
Hot Well
Housekeeping Practices
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
211 .3070
Incinerator
211 .3090
Indirect Heat Transfer
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-Bum Engine
211 .3310
Light Liquid
211 .3330
Light-Duty Truck
211 .3350
Light Oil
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 .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
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
211 .3750
211 .3770
211 .3780
211
.3790
211 .3810
211 .3830
211 .3850
211 .3870
211
.3890
211
.3910
211 .3915
211 .3930
211
.3950
211 .3960
211 .3965
211 .3970
211
.3980
211 .3990
211 .4010
211 .4030
211 .4050
211
.4055
211 .4065
211 .4067
211 .4070
211 .4090
211 .4110
211
.4130
211 .4150
211 .4170
211 .4190
211 .4210
211
.4230
211 .4250
211 .4260
211 .4270
211 .4290
211 .4310
211
.4330
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
Metal Furniture Coating
Metal Furniture Coating Line
Metallic Shoe-Type Seal
Mid-Kiln Firing
Miscellaneous Fabricated Product Manufacturing Process
Miscellaneous Formulation Manufacturing Process
Miscellaneous Metal Parts and Products
Miscellaneous Metal Parts and Products Coating
Miscellaneous Metal Parts or Products Coating Line
Miscellaneous Organic Chemical Manufacturing Process
Mixing Operation
Mobile Equipment
Monitor
Monomer
Motor Vehicles
Motor Vehicle Refinishing
Multiple Package Coating
Nameplate Capacity
New Grain-Drying Operation (Repealed)
New Grain-Handling Operation (Repealed)
No Detectable Volatile Organic Material Emissions
Non-Contact Process Water Cooling Tower
Non-Flexible Coating
Non-Heatset
NOx
Trading Program
Offset
One Hundred Percent Acid
One-Turn Storage Space
Opacity
Opaque Stains
Open Top Vapor Degreasing
Open-Ended Valve
Operator of a Gasoline Dispensing Operation or Operator of a Gasoline
Dispensing Facility
Organic Compound
Organic Material and Organic Materials
Organic Solvent
Organic Vapor
Oven
Overall Control
Overvarnish
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
211 .5730
Roll Printer
211 .5750
Roll Printing
211 .5770
Rotogravure Printing
211 .5790
Rotogravure Printing Line
211 .5810
Safety Relief Valve
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
211 .6410
211
.6420
211 .6430
211 .6450
211 .6470
211 .6490
211 .6510
211
.6530
211 .6540
211 .6550
211 .6570
211 .6580
211 .6590
211 .6610
211
.6620
211 .6630
211 .6650
211 .6670
211 .6690
211 .6695
211 .6710
211 .6720
211 .6730
211 .6750
211 .6770
211 .6790
211
.6810
211
.6830
211 .6850
211 .6860
211.6870
211 .6880
211 .6890
211 .6910
211 .6930
211 .6950
211 .6970
211 .6990
211 .7010
211 .7030
211 .7050
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
Stencil Coat
Storage Tank or Storage Vessel
Strippable Spray Booth Coating
Styrene Devolatilizer Unit
Styrene Recovery Unit
Submerged Loading Pipe
Substrate
Sulfuric Acid Mist
Surface Condenser
Surface Preparation Materials
Synthetic Organic Chemical or Polymer Manufacturing Plant
Tablet Coating Operation
Texture Coat
Thirty-Day Rolling Average
Three-Piece Can
Three or Four Stage Coating System
Through-the-Valve Fill
Tooling Resin
Topcoat
Topcoat Operation
Topcoat System
Touch-Up
Touch-Up Coating
Transfer Efficiency
Tread End Cementing
True Vapor Pressure
Turnaround
Two-Piece Can
Under-the-Cup Fill
Undertread Cementing
Uniform Finish Blender
Unregulated Safety Relief Valve
Vacuum Metallizing
Vacuum Producing System
Vacuum Service
Valves Not Externally Regulated
Vapor Balance System
Vapor Collection System
Vapor Control System
Vapor-Mounted Primary Seal
Vapor Recovery System
Vapor-Suppressed Polyester Resin
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
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
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
.5 of the Environmental Protection Act [415 ILCS 5/9, 9 .1, 9.9,
10, 27 and 28 .5] .
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 10111
. 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 11111
. Reg
. 12267, effective
July 10, 1987; amended in R86-39 at l 1111
. 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 14111 . 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 15 111
.
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,
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
effective September 27, 1993
; amended in R93-11 at 17 Ill . Reg. 21471, effective
December 7, 1993 ; amended in R93-14 at 18 111 . Reg. 1253, effective January 18, 1994 ;
amended in R94-12 at 18 Ill . Reg. 14962, effective September 21, 1994 ; amended in
R94-14 at 18111 . Reg. 15744, effective October 17, 1994
; amended in R94-15 at 18111 .
Reg. 16379, effective October 25, 1994; amended in R94-16 at 18111
. 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 19111 . Reg. 7344, effective May 22,
1995 ; amended in R95-2 at 19111 . Reg. 11066, effective July 12, 1995 ; amended in R95-
16 at 19111 . Reg. 15176, effective October 19, 1995 ; amended in R96-5 at 20111 . Reg.
7590, effective May 22, 1996 ; amended in R96-16 at 21111 . Reg
. 2641, effective
February 7, 1997 ; amended in R97-17 at 21111 . Reg. 6489, effective May 16, 1997;
amended in R97-24 at 21111. 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 29111 . Reg.8892, effective June 13, 2005 ; amended in R04-
12/20 at 30111 . Reg. 9654, effective May 15, 2006; amended in R07- at
Ill
. Reg.
SUBPART B : DEFINITIONS
Section 211 .740 Brakehorsepower (rated-bhp)
`Brakehorsepower (bhp)" means the rated horsepower capacity of the engine as defined
on the engine nameplate at standard conditions .
(Source : Added at -
Ill. Reg. ., effective _
Section 211 .1740 Diesel Engine
"Diesel engine" means for the purposes of 35 Ill . Adm. Code 217, Subpart Q, a
compression ignited two- or four-stroke engine in which liquid fuel injected into the
combustion chamber ignites when the air charge is compressed to a temperature
sufficiently high for auto-ignition.
(Source : Added at
-
Ill. Reg. , effective )
Section 211 .1920
Emergency or Standby Unit
"Emergency or Standby Unit" means, for a stationary gas turbine or stationary
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
reciprocating internal combustion engine, a unit that :
a)
Supplies power for the source at which it is located but operates only
when the normal supply of power has been rendered unavailable by
circumstances beyond the control of the owner or operator of the source
and only as necessary to assure the availability of the engine or turbine.
An emergency standby unit may not be operated to supplement a primary
power source when the load capacity or rating of the primary power
source has been reached or exceeded .,
b)
Operates exclusively for firefighting or flood control or both,; or
c)
Operates in response to and during the existence of any officially declared
disaster or state of emergency .
d) Operates
for the purpose of testing, repair or routine maintenance to verify
its readiness for emergency standby use
.
The term does not include equipment used for purposes other than emergencies,
as described above, such as to supply power during high electric demand days
.
(Source: Amended at
-
Ill . Reg.
, effective )
Section 211 .3300 Lean-Burn Engine
"Lean-bum engine" means any spark-ignited engine that is not a rich-burn engine
.
(Source: Added at - Ill. Reg. ,
effective )
Section 211 .5640 Rich-Burn Engine
"Rich-burn engine" means a spark-ignited engine where the oxygen content in the
exhaust stream of the engine before any dilutions is 1 percent or less by volume measured
on a dry basis .
(Source: Added at
-
Ill. Reg. ,
effective . )
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
TITLE 35 : ENVIRONMENTAL PROTECTION
SUBTITLE B
: AIR POLLUTION
CHAPTER I
: POLLUTION CONTROL BOARD
SUBCHAPTER C : EMISION STANDARDS AND LIMITATIONS
FOR STATIONARY SOURCES
PART 217
NITROGEN OXIDES EMISSIONS
SUBPART 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
Section
217.121
New Emission Sources
SUBPART C : EXISTING FUEL COMBUSTION EMISSION SOURCES
Section
217.141
Existing Emission Sources in Major Metropolitan Areas
SUBPART K: PROCESS EMISSION SOURCES
Section
217.301
Industrial Processes
SUBPART 0: CHEMICAL MANUFACTURE
Section
217 .381
Nitric Acid Manufacturing Processes
SUBPART Q: STATIONARY RECIPROCATING INTERNAL COMBUSTION
ENGINES AND TURBINES
9
.c
Section
217.386 Applicability
217.388 Control 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 NO, Trading Budget
217 .462
Methodology for Obtaining NO, Allocations
217 .464
Methodology for Determining NO, Allowances from the New Source Set-Aside
217 .466
NO, 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 NO, Trading Program
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
ILLINOIS REGISTER
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NOTICE OF PROPOSED RULES
ILLINOIS
REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
217.708
NO, Averaging
217.710
Monitoring
217.712
Reporting and Recordkeeping
SUBPART W : NO, 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
NO, Trading Budget
217.762
Methodology for Calculating NO, 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 NO, 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
NO, Emission Reductions and the Subpart X NO, Trading Budget
217.820
Baseline Emissions Determination
217.825
Calculation of Creditable NOx Emission Reductions
217.830
Limitations on NO, Emission Reductions
217 .835
NOx
Emission Reduction Proposal
217
.840
Agency Action
217.845
Emissions Determination Methods
217 .850
Emissions Monitoring
217 .855
Reporting
217 .860
Recordkeeping
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
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, SIP
Call
Authority
: Implementing Sections 9
.9 and 10 and authorized by Sections 27 and 28 .5 of the
Environmental Protection Act [415 ILCS 5/9.9,
10, 27 and 28 .5 (2004)]
.
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 7 111
. Reg. 13609; amended in R01-9 at 25 111
. Reg. 128,
effective December 26, 2000 ; amended in R01-1 I at 25 Ill
. Reg. 4597, effective March 15, 2001
;
amended in RO1-16 and RO1-17 at 25 Ill
. Reg. 5914, effective April 17, 2001
; amended in R07-
at III
. Reg. ,
SUBPART
effective - A
: GENERAL PROVISIONS
Section 217 .101
Measurement Methods
Measurement of nitrogen oxides must be according to_
a)
The phenol disulfonic acid
proceduresmethod, 40 CFR 60, Appendix A, Method
7, as incorporated by reference in Section 217
.104(4999);
b)
Continuous emissions monitoring pursuant to 40 CFR
75, as incorporated by
reference in Section 217
.104(4999); and
c)
Determination of Nitrogen Oxides Emissions from Stationary Sources
(Instrumental Analyzer Procedure), 40 CFR 60, Appendix A, Method
7E, as
incorporated by reference in Section 217
.104;(1999).
d) Monitoring
with portable monitors pursuant to ASTM D6522-00, as incorporated
by reference in Section 217 .104
; and
e) How
do I conduct the initial and subsequent performance tests (for turbines),
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
regarding NO, pursuant to 40 CFR 60
.4400, as incorporated by reference in
Section 217 .101 .
(SourceSection
:
217Amended
.102
at Ill
. Reg.
, effective
Abbreviations and Units
a)
The following abbreviations are used in this Part
:
ASTM
American Society for Testing and Materials
Bbtu
British thermal unit (60°)
bhp brake
horsepower
GEMS continuous
emissions monitoring system
EGU
Electrical Generating Unit
dscf dry
standard cubic feet
g/bhp-hr grams
per brake horsepower-hour
kg
kilogram
kg/MW-hr
kilograms per megawatt-hour,
usually used as an
hour-Iy-emission
rate
lb
pound
NO, Nitrogen
Oxides
lbs/mmBbtu
pounds per million btu,
usually used as an
hourly cmis&ion
rate
Mg
megagram or metric tonne
mm million
mmBbtu
million British thermal units
mmBbtu/hr
million British thermal units per hour
MWe
megawatt of electricity
MW
megawatt
; one million watts
MW-hr
megawatt-hour
NATS NO,
Allowance Tracking System
NO2 nitrogen
dioxide
N% nitrogen
oxides
p oxygen
psia pounds
per square inch absolute
peoc
potential electrical output capacity
PTE
potential to emit
ppm
parts per million
ppmv
parts per million by volume
T
English ton
TPY tons
per year
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
(Source : Amended at Ill. Reg. , effective )
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 proceduresmethed,
as published in 40 CFR 60,
Appendix A, Method 7 (2000)(1999) ;
b)
40 CFR 96, subparts B, D, G, and H (1999) ;
c)
40 CFR
§4
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 672, 75 & 76
(2006)(1999) ;
e)
Alternative Control Techniques Document NO, 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 ;
0
g)
ILLINOIS REGISTER
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 ;
40 CFR
4
60.13 (2001)(1999); and
b)
The following conversion factors have been used in this Part :
English
Metric
2.205 lb
1 kg
1 T
0.907 Mg
1 Ib/T
0.500
kg/Mg
Mmbtu/hr 0.293MW
1 lb/mmBbtu 1 .548 kg/MW-hr
I mmBtu/hr 0.293 MW
1 mmBtu/hr 393 bhp
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
h)
40 CFR 60, Appendix A, Methods
.3A
7, 7A, 7C, 7D, and 7E, 19, and 20
(2000)(1999) .;
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)
;
k) Standards
of Performance for Stationary Combustion Turbines, 40 CFR 60,
Subpart KKKK, 60 .4400 (2006) ; and
1) Compilation
of Air Pollutant Emission Factors
: AP-42, Volume I : Stationary
Point and Area Sources (2000), USEPA
.
(Source
: Amended at Ill . Reg
. , effective )
SUBPART 0
: STATIONARY RECIPROCATING INTFRNAL COMBUSTION ENGINES
AND TURBINES
Section 217 .386
Applicability
a)
A stationary reciprocating internal combustion engine or turbine that meets the
criteria in subsection (a)(1) or (a)(2)
of this Section is an affected unit and is
subject to the requirements of this Subpart Q
.
1)
The engine at nameplate capacity is rated at equal to or greater than 500
bhp output
; or
2)
The turbine is rated at equal to or greater than 3
.5 MW (4,694 bhp) output
at 14.7
psia, 59°F, and 60 percent relative humidity
.
b)
Notwithstanding subsection (a) of this Section, an engine or turbine will not be an
affected unit and is not subject to the requirements of this Subpart Q, if the engine
or turbine is or has :
1)
Used as an emergency or standby unit as defined by 35 Ill . Adm
. Code
211 .1920;
2)
Used for research or for the purposes of performance verification or
testing;
ILLINOIS REGISTER
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
3)
Used to control emissions from landfills, where at least 50 percent of the
heat input is gas collected from a landfill ;
4)
Used for agricultural purposes including the raising of crops or livestock
that are produced on site, but not associated businesses like packing
operations, sale of equipment or repair
;
5)
A nameplate capacity rated at less than 1500 bhp (1118 kW) output,
mounted on a chassis or skids, designed to be moveable, and moved to a
different source at least once every 12 months ; or
6)
Regulated under Subpart W or a subsequent federal NO, Trading program
for electrical generating units .
c)
If an exempt unit ceases to fulfill the criteria specified in subsection (b) of this
Section, the owner or operator must notify the Agency in writing within 30 days
after becoming aware that the exemption no longer applies and comply with the
control requirements of this Subpart Q .
d)
The requirements of this Subpart Q will continue to apply to any engine or turbine
that has ever been subject to the control requirements of Section 217
.388, even if
the affected unit ceases to fulfill the rating requirements of subsection (a) of this
Section or becomes eligible for an exemption pursuant to subsection (b) of this
Section.
Section 217 .388
Control and Maintenance Requirements
On and after the applicable compliance date in Section 217
.392,'an owner or operator of an
affected unit must inspect and maintain affected units as required by subsection (d) of this
Section and comply with either the applicable emissions concentration as set forth in subsection
(a) of this Section, or the requirements for an emissions averaging plan as specified in subsection
(b) of this Section or the requirements for operation as a low usage unit as specified in subsection
(c) of this Section.
a)
The owner or operator must limit the discharge from an affected unit into the
atmosphere of any gases that contain NO, to no more than :
1)
150 ppmv (corrected to 15 percent 02 on a dry basis) for spark-ignited
rich-bum engines;
2)
210 ppmv (corrected to 15 percent 0
2
on a dry basis) for spark-ignited
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
lean-bum engines, except for existing spark-ignited Worthington engines
that are not listed in Appendix G;
3)
365 ppmv (corrected to 15 percent 02 on a dry basis) for existing spark-
ignited Worthington engines that are not listed in Appendix G ;
4)
660 ppmv (corrected to 15 percent 0 2
on a dry basis) for diesel engines;
5)
42 ppmv (corrected to 15 percent
02
on a dry basis) for gaseous fuel-fired
turbines ; and
6)
96 ppmv (corrected to 15 percent 0 2
on a dry basis) for liquid fuel-fired
turbines
.
b)
The owner or operator must comply with the requirements of the applicable
emissions averaging plan as set forth in Section 217
.390.
c)
The owner or operator must operate the affected unit as a low usage unit pursuant
to subsection (c)(1) or (c)(2) of this Section
. Low usage units are not subject to
the requirements of this Subpart Q except for the requirements to inspect and
maintain the unit pursuant to subsection (d) of this Section, and retain records
pursuant to Sections 217 .396(b) and
(c). Only one of the following exemptions
may be utilized at a particular source :
I)
The potential to emit (PTE) is no more than 100 TPY NO, aggregated
from all engines and turbines located at the source that are not otherwise
exempt pursuant to Section 217
.386(b), and not complying with the
requirements of subsection (a) or (b) of this Section and the NO, PTE
limit is contained in a federally enforceable permit
; or
2)
The aggregate bhp-hr/MW-hr from all affected units located at the source
that are not exempt pursuant to Section 217
.386(b), and not complying
with the requirements of subsection (a) or (b) of this Section, are less than
or equal to the bhp-hrs and MW-hrs operation limit listed in subsection
(c)(2)(A) and (c)(2)(B)
of this Section . For units not located at a natural
gas transmission compressor station or storage facility that drive a natural
gas compressor station, the operation limits of subsections (c)(2)(A)
and
(B) of this Section must be contained in a federally enforceable permit
.
A)
8 mm bhp-hrs or less on an annual basis for engines
; and
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
B)
20,000 MW-hrs or less on an annual basis for turbines .
d)
The owner or operator must inspect and perform periodic maintenance on the
affected unit, in accordance with a Maintenance Plan that documents :
1)
For a unit not located at natural gas transmission compressor station or
storage facility either :
A) The manufacturer's recommended inspection and maintenance of
the applicable air pollution control equipment, monitoring device,
and affected unit ; or
B)
If the original equipment manual is not available or substantial
modifications have been made that require an alternative procedure
for the applicable air pollution control device, monitoring device,
or affected unit, the owner or operator must establish a plan for
inspection and maintenance in accordance with what is customary
for the type of air pollution control equipment, monitoring device,
and affected unit .
2)
For a unit located at a natural gas compressor station or storage facility,
the operator's maintenance procedures for the applicable air pollution
control device, monitoring device, and affected unit .
Section 217 .390
Emissions Averaging Plans
a)
An owner or operator of certain affected units may comply through an emissions
averaging plan .
1)
The unit or units that commenced operation before January 1, 2002, may
be included in an emissions averaging plan as follows:
A)
Units located at a single source or at multiple sources in Illinois, so
long as the units are owned by the same company or parent
company where the parent company has working control through
stock ownership of its subsidiary corporations . A unit may be
listed in only one emissions averaging plan ;
B)
Units that have a compliance date later than the control period for
which the averaging plan is being used for compliance ; and
ILLINOIS REGISTER
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NOTICE OF PROPOSED RULES
C)
Units which the owner or operator may claim as exempt pursuant
to Section 217
.386(b) but does not claim exempt
. For as long as
such a unit is included in an emissions averaging plan, it will be
treated as an affected unit and subject to the applicable emission
concentration limits, testing, monitoring, recordkeeping and
reporting requirements
.
2)
The following types of units may not be included in an emissions
averaging plan :
A)
Units that commence operation after January 1, 2002, unless the
unit replaces an engine or turbine that commenced operation on or
before January 1, 2002, or it replaces an engine or turbine that
replaced a unit that commenced operation on or before January 1,
2002
. The new unit must be used for the same purpose as the
replacement unit
. The owner or operator of a unit that is shutdown
and replaced must comply with the provisions of Section
217.396(d)(3)
before the replacement unit may be included in an
emissions averaging plan.
B)
Units which the owner or operator is claiming are exempt pursuant
to Section 217
.386(b) or as a low usage unit pursuant to Section
217 .388(c).
b)
An owner or operator must submit an emissions averaging plan to the Agency by
the applicable compliance date set forth in Section 217
.392 . The plan must
include, but is not limited to :
1)
The list of affected units included in the plan by unit identification number
and permit number.
2)
A sample calculation demonstrating compliance using the methodology
provided in subsection (f) of this Section for both the ozone season and
calendar year
.
c)
An owner or operator may amend an emissions averaging plan only once per
calendar year
. An amended plan must be submitted to the Agency by May 1 of
the applicable calendar year
. If an amended plan is not received by the Agency
by May 1 of the applicable calendar year, the previous year's plan will be the
applicable emissions averaging plan .
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
d)
Notwithstanding subsection (c) of this Section, an owner or operator, and the
buyer, if applicable :
1)
Must submit an updated emissions averaging plan or plans to the Agency
within 60 days, if a unit that is listed in an emissions averaging plan is sold
or taken out of service
.
2)
May amend its emissions averaging plan to include another unit within 30
days of discovering that the unit no longer qualifies as an exempt unit
pursuant to Section 217
.386(b) or as a low usage unit pursuant to Section
217.388(c)
.
e)
An owner or operator must :
1)
Demonstrate compliance for both the ozone season (May I through
September 30) and the calendar year (January 1 through December 31) by
using the methodology and the units listed in the most recent emissions
averaging plan submitted to the Agency pursuant to subsection (b) of this
Section
; the higher of the monitoring or test data determined pursuant to
Section 217.394; and the actual hours of operation for the applicable
control period ;
2)
Notify the Agency by October 31 following the ozone season, if
compliance cannot be demonstrated for that ozone season
; and
3)
Submit to the Agency by January 31 following each calendar year, a
compliance report containing the information required by Section
217 .396(d)(4) .
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,
emissions for those units for both the ozone season and calendar year
. The
following equation must be used to determine compliance
:
Nact < Nall
Where :
f)
Nact
=
ILLINOIS REGISTER
11
EEMact(i)
g)
Nall
Nact
E act(; _
13a11(j)
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
Total
E
n
=t
EMao(i)sum
of the actual NO, mass emissions from units
included in the averaging plan for each fuel used (lbs per
ozone season and calendar year) .
Nall
Total sum of the allowable NO, mass emissions from units
included in the averaging plan for each fuel used (lbs
per ozone season and calendar year) .
EMall(p =
Total mass of allowable NOx emissions in lbs for a unit as
determined in subsection (g)(2), (g)(3), (g)(4), (g)(5),or
(g)(6)
of this Section .
EMact(p-
Total mass of actual NOx
emissions in lbs for a unit as
determined in subsection
(g)(1), (g)(3), (g)(5) or (h) of
this Section .
t
=
Subscript denoting an individual unit and fuel used
.
n
=
Number of different units in the averaging plan
.
For each unit in the averaging plan, and each fuel used by a unit, determine actual
and allowable NO, emissions using the following equations, except as provided
for in subsection (h) of this Section:
1)
Actual emissions must be determined as follows
:
EMac,o)
E,~,(,) x H;
'a
20.9
Y-
Cd(aatUXFax
v
20.9-%oO
2d(i)
2)
Allowable emissions must be determined as follows
:
EMaI
,(;)
=
Eau(;) X H;
1n
Y-Cd(au)xFdx
=1
v 20.9-
%O 2d(j)
m
m
20.9
Where :
EMact(;)
-
Total mass of actual NO, emissions in lbs for a unit .
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EM,i1(,) = Total mass of allowable NO, emissions in lbs for a unit .
Eact
-
Actual NO x emission rate (lbs/mmBtu) calculated
according to the above equation .
Ea„
=
Allowable NO x emission rate (lbs/mmBtu) calculated
according to the above equation .
H
=
Heat input (mmBtu/ozone season or mmBtu/year)
calculated from fuel flow meter and the heating value of the
fuel used.
Cd(act) =
Actual concentration of NO, in lb/dscf (ppmv x 1 .194 x
10'7) on a dry basis for the fuel used. Actual concentration
is determined on each of the most recent test run or
monitoring pass performed pursuant to Section 217 .394,
whichever is higher .
Cd(au)
=
Allowable concentration of NO x in lb/dscf (allowable
emission limit in ppmv specified in Section 217 .388(a),
except as provided for in subsection (g)(6) of this Section,
if applicable.
multiplied by 1 .194 x 10-7) on a dry basis for the fuel used .
Fd
The ratio of the gas volume of the products of combustion
to the heat content of the fuel (dsef/mmBtu) as given in the
table of F Factors included in 40 CFR 60, Appendix A,
Method 19 or as determined using 40 CFR 60, Appendix A,
Method 19 .
%O2d =
Concentration of oxygen in effluent gas stream measured
on a dry basis during each of the applicable test or
monitoring runs used for determining emissions, as
represented by a whole number percent, e .g ., for 18.7%O2d,
18 .7 would be used .
I
Subscript denoting an individual unit and the fuel used .
j
Subscript denoting each test run or monitoring pass for an
affected unit for a given fuel .
m
The number of test runs or monitoring passes for an
affected unit using a given fuel .
3)
For a replacement unit that is electric-powered, the allowable NO,
emissions from the affected unit that was replaced should be used in the
averaging calculations and the actual NO, emissions for the electric-
powered replacement unit (EM(j)a,,,,,,) are zero . Allowable NO,
emissions for the electric-powered replacement are calculated using the
actual total bhp-hrs generated by the electric-powered replacement unit on
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NOTICE OF PROPOSED RULES
an ozone season and on an annual basis multiplied by the allowable NO,
emission rate in lb/bhp-hr of the replaced unit
.
The allowable mass of NOx
emissions from an electric-powered
replacement unit (EM (0au
elec)
must be determined by multiplying the
nameplate capacity of the unit by the hours operated during the ozone
season or annually and the allowable NO, emission rate of the replaced
unit (Ean rep)
in lb/mmBtu converted to lb/bhp-hr . For this calculation the
following equation should be used
:
EMan eiee(i)
= bhp x OP x F x E,11,,p(,)
Where:
EMa„
e,ec(i)=
Mass of allowable NO x
emissions from the electric-
powered replacement unit in pounds per ozone season or
calendar year.
bhp
Nameplate capacity of the electric-powered
replacement unit in brake-horsepower
.
OP
Operating hours during the ozone season or calendar year
.
F
Conversion factor of 0.0077 mmBtu/bhp-hr
.
Ban
rep(i)=
Allowable NOx
emission rate (lbs/mmBtu) of the replaced
unit.
i
Subscript denoting an individual electric unit and the fuel
used.
4)
For a replacement unit that is not electric, the allowable NO, emissions
rate used in the above equations set forth in subsection
(g)(2) of this
Section must be either
:
A)
Prior to the applicable compliance date for the replaced unit
pursuant to Section 217
.392, the higher of the actual NO,
emissions as determined by testing or monitoring data or the
applicable uncontrolled NO, emissions factor from Compilation of
Air pollutant emission Factors
: AP-42, Volume I : Stationary Point
and Area Sources, as incorporated by reference in Section 217.104
for the unit that was replaced
; or
B)
On and after the applicable compliance date for the replaced unit
pursuant to Section 217
.392, the applicable emissions
concentration for the type of unit that replaced pursuant to Section
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217 .388(a) .
5)
For a unit that is replaced with purchased power, the allowable NO,
emissions rate used in the above equations set forth in subsection (g)(2) of
this Section must be the emissions concentration as set forth in Section
217.388(a) or subsection (g)(6) of this Section, when applicable, for the
type of unit that was replaced
. For owners or operators replacing units
with purchased power, the annual hours of operations that must be used
are the calendar year hours of operation for the unit that was shutdown
averaged over the three-year period prior to the shutdown . The actual
NO, emissions for the units replaced by purchased power (EM
(; ,ct) are
zero
. These units may be included in any emissions averaging plan for no
more than five years beginning with the calendar year that the replaced
unit is shut down.
6)
For units that have a later compliance date, allowable emissions rate used
in the above equations set forth in subsection (g)(2) of this Section must
be:
A)
Prior to the applicable compliance date pursuant to Section
217
.392, the higher of the actual NO, emissions as determined by
testing or monitoring data, or the applicable uncontrolled NO,
emissions factor from Compilation of Air Pollutant Emission
Factors: AP-42, Volume I
: Stationary Point and Areas Sources, as
incorporated by reference in Section 217.104; and
B)
On and after the units applicable compliance date pursuant to
Section 217
.392, the applicable emissions concentration for that
type of unit pursuant to Section 217 .388(a)
.
h)
For units that use CEMS the data must show that the total mass of actual NO x
emissions determined pursuant to subsection (h)(1)
of this Section is less than or
equal to the allowable NO, emissions calculated in accordance with the equations
in subsections (f) and (h)(2) of this Section for both the ozone season and calendar
year. The equations in subsection (g) of this Section will not apply
.
1)
The total mass of actual NO, emissions in lbs for a unit (EM,,,) must be
the sum of the total mass of actual NO x
emissions from each affected unit
using CEMS data collected in accordance with 40 CPR 60 or 75, or
alternate methodology that has been approved by the Agency or USEPA
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
and included in a federally enforceable permit
.
2)
The allowable NO, emissions must be determined as follows
:
EM(,,, ) _
f
m
1
(Cd, * flowstack, * 1.194x10-')
Where:
EMaupl--
Total mass of allowable NO, emissions in lbs for a unit
.
Flow; =
Stack flow (dscf/hr) for a given stack
.
Cd;
=
Allowable concentration of NO, (ppmv) specified in
Section 217
.388(a) of this subpart for a given stack
. (1 .194
X
10-')
converts to lb/dscf) .
i
subscript denoting each hour operation of a given unit
.
in
Total number of hours of operation of a unit
.
I
Subscript denoting an individual unit and the fuel used
.
Section 217 .392
Compliance
ILLINOIS REGISTER
a)
An owner or operator of an affected unit may not operate that unit unless it meets
the applicable concentration limit in Section 217.388(a),
or is included in an
emissions averaging plan pursuant to Section 217
.388(b), or meets the low usage
requirements pursuant to Section 217.388(c),
and complies with all other
applicable requirements of this Subpart Q by the earliest applicable date listed
below :
1)
On and after May 1, 2007, an owner or operator of an affected engine
listed in Appendix G may not operate the affected engine unless the
requirements of this Subpart Q are met or the affected engine is exempt
pursuant to Section 217
.386(b);
2)
On and after January 1, 2009, an owner or operator of an affected unit and
that is located in Cook, DuPage, Aux Sable' Township and Goose Lake
Township in Grundy, Kane, Oswego Township in Kendall, Lake,
McHenry, Will, Jersey, Madison, Monroe, Randolph Township in
Randolph, or St
. Clair County, and is not listed in Appendix G may not
operate the affected unit unless the requirements of this Subpart Q are met
or the affected unit is exempt pursuant to Section 217
.386(b) ;
3)
On and after January 1, 2011, an owner or operator of an affected engine
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with a nameplate capacity rated at 1500 bhp or more, and affected turbines
rated at 5 MW (6,702 bhp) or more that is not subject to subsection
(a)(1)
or (a)(2) of this Section, may not operate the affected unit unless the
requirements of this Subpart Q are met or the affected unit is exempt
pursuant to Section 217 .386(b) ; or
4)
On and after January 1, 2012, an owner or operator of an affected engine
with a nameplate capacity rated at less than 1500 bhp or an affected
turbine rated at less than 5 MW (6,702 bhp) that is not subject to
subsection (a)(1), (a)(2) or (a)(3) of this Section, may not operate the
affected engine or turbine unless the requirements of this Subpart Q are
met or the affected unit is exempt pursuant to Section 217 .386(b) .
b)
Owners and operators of an affected unit may use NO, allowances to meet the
compliance requirements in Section 217 .388 as specified below . A NO,
allowance is defined as an allowance used to meet the requirements of a NO,
trading program administered by USEPA where one allowance is equal to one ton
of NO, emissions .
1)
NO, allowances may only be used under the following circumstances :
A) An anomalous or unforeseen operating scenario inconsistent with
historical operations for a particular ozone season or calendar year
that causes an emissions exceedance.
B)
To achieve compliance no more than twice in any rolling five-year
period.
C)
For a unit that is not listed in Appendix G .
2)
The owner or operator of the affected unit must surrender to the Agency
one NO, allowance for each ton or portion of a ton of NO, by which
actual emissions exceed allowed emissions
. For noncompliance with a
seasonal limit, a NO, ozone season allowance must be used
. For
noncompliance with the emissions concentration limits in Section
217.388(a) or an annual limitation in an emissions averaging plan, only a
NO, annual allowance may be used .
3)
The owner or operator must submit a report documenting the
circumstances that required the use of NO, allowances and identify what
actions will be taken in subsequent years to address these circumstances
Section 217.394
Testing and Monitoring
ILLINOIS REGISTER
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and must transfer the NO, allowances to the Agency's federal NO,
retirement account
. The report and the transfer of allowances must be
submitted by October 31 for exceedances during the ozone season and
March 1 for exceedances of the emissions concentration or the annual
emission averaging plan limits
. The report must contain the NATS serial
numbers of the NO, allowances .
a)
An owner or operator of an engine or turbine must conduct an initial performance
test pursuant to subsection (c)(1)
or (c)(2) of this Section as follows
:
1)
By May 1, 2007, for affected engines listed in Appendix G
. Performance
tests must be conducted on units listed in Appendix G, even if the unit is
included in an emissions averaging plan pursuant to Section 217
.388(b).
2)
By the applicable compliance date as set forth in Section 217
.392, or
within the first 876 hours of operation per calendar year, whichever is
later:
A)
For affected units not listed in Appendix G that operate more than
876 hours per calendar year ; and
B)
For units that are not affected units that are included in an
emissions averaging plan and operate more than 876 hours per
calendar year.
3)
Once within the five-year period after the applicable compliance date as
set forth in Section 217 .392 :
A)
For affected units that operate fewer than 876 hours per calendar
year; and
B)
For units that are not affected units that are included in an
emissions averaging plan and that operate fewer than 876 hours per
calendar year
b)
An owner or operator of an engine or turbine must conduct subsequent
performance tests pursuant to subsection (c)(1) or (c)(2)
of this Section as
follows :
c)
Testing Procedures .
ILLINOIS REGISTER
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NOTICE OF PROPOSED RULES
1)
For affected engines listed in Appendix G and all units included in an
emissions averaging plan, once every five years . Testing must be
performed in the calendar year by May 1 or within 60 days of starting
operation, whichever is later ;
2)
If the monitored data shows that the unit is not in compliance with the
applicable emissions concentration or emissions averaging plan, the owner
or operator must report the deviation to the Agency in writing within 30
days and conduct a performance test pursuant to subsection (c) of this
Section within 90 days of the determination of noncompliance ; and
3)
When in the opinion of the Agency or USEPA, it is necessary to conduct
testing to demonstrate compliance with Section 217 .388, the owner or
operator of a unit must, at his or her own expense, conduct the test in
accordance with the applicable test methods and procedures specified in
this Section 217 .394 within 90 days of receipt of a notice to test from the
Agency or USEPA
.
1)
For an engine: The owner or operator must conduct a performance test
using Method 7 or 7E of 40 CFR 60, Appendix A, as incorporated by
reference in Section 217 .104. Each compliance test must consist of three
separate runs, each lasting a minimum of 60 minutes
. NO, emissions must
be measured while the affected unit is operating at peak load . If the unit
combusts more than one type of fuel (gaseous or liquid) including backup
fuels, a separate performance test is required for each fuel .
2)
For a turbine
: The owner operator must conduct a performance test using
the applicable procedures and methods in 40 CFR 60 .4400, as
incorporated by reference in Section 217.104.
d)
Monitoring : Except for those years in which a performance test is conducted
pursuant to subsection (a) or (b) of this Section, the owner or operator of an
affected unit or a unit included in an emissions averaging plan must monitor NO x
concentrations annually, once between January 1 and May I or within the first
876 hours of operation per calendar year, whichever is later
. If annual operation
is less than 876 hours per calendar year, each affected unit must be monitored at
least once every five years . Monitoring must be performed as follows :
1)
A portable NO, monitor and utilizing method ASTM D6522-00, as
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NOTICE OF PROPOSED RULES
incorporated by reference in Section 217 .104, or a method approved by
the Agency must be used . If the engine or turbine combusts both liquid or
gaseous fuels as primary or backup fuels, separate monitoring is required
for each fuel .
2)
NO, and 0 2
concentrations measurements must be taken three times for a
duration of at least 20 minutes . Monitoring must be done at highest
achievable load . The concentrations from the three monitoring runs must
be averaged to determine whether the affected unit is in compliance with
the applicable emissions concentration or emissions averaging plan as
specified in Section 217 .388 .
e)
Instead of complying with the requirements of subsections (a), (b), (c) and (d) of
this Section, an owner or operator may install and operate a CEMS on an affected
unit that meets the applicable requirements of 40 CFR 60, subpart A, and
Appendix B, incorporated by reference in Section 217
.104, and complies with the
quality assurance procedures specified in 40 CFR 60, Appendix F, or 40 CFR 75
as incorporated by reference in Section 217 .104, or an alternate procedure as
approved by the Agency or USEPA in a federally enforceable permit
. The CEMS
must be used to demonstrate compliance with the applicable emissions
concentration or emissions averaging plan only on an ozone season and annual
basis.
Section 217 .396
Recordkeeping and Reporting
a)
Recordkeeping . The owner or operator of a unit included in an emissions
averaging plan or an affected unit that is not exempt pursuant to Section
217.386(h) and is not subject to the low usage exemption of Section 217
.388(c)
must maintain records that demonstrate compliance with the requirements of this
Subpart Q which include, but are not limited to :
1)
Identification, type (e.g., lean-bum, gas-fired), and location of each unit
.
2)
Calendar date of the record .
3)
The number of hours the unit operated on a monthly basis, and during
each ozone season .
4)
Type and quantity of the fuel used on a daily basis .
5)
The results of all monitoring performed on the unit and reported
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deviations.
6)
The results of all tests performed on the unit
.
7)
The plan for performing inspection and maintenance of the units, air
pollution control equipment, and the applicable monitoring device
pursuant to Section 217
.388(d) .
8)
A log of inspections and maintenance performed on the unit's air
emissions, monitoring device, and air pollution control device
. These
records must include, at a minimum, date, load levels and any manual
adjustments along with the reason for the adjustment (e
.g., air to fuel ratio,
timing or other settings) .
9)
If complying with the emissions averaging plan provisions of Sections
217 .388(b) and 217
.390 copies of the calculations used to demonstrate
compliance with the ozone season and annual control period limits,
noncompliance reports for the ozone season, and ozone and annual control
period compliance reports submitted to the Agency
.
10)
Identification of time periods for which operating conditions and pollutant
data were not obtained by either the CEMS or alternate monitoring
procedures including the reasons for not obtaining sufficient data and a
description of corrective actions taken .
11)
Any NO, allowance reconciliation reports submitted pursuant to Section
217.392(e).
b)
The owner or operator of an affected unit that is complying with the low usage
provisions of Section 217
.388(c), must:
1)
For each unit complying with Section 217
.388(c)(1), maintain a record of
the NO, emissions for each calendar year ; or
2)
For each unit complying with Section 217
.388(c)(2), maintain a record of
bhp or MW hours operated each calendar year.
c)
The owner or operator of an affected unit or unit included in an emissions
averaging plan must maintain the records required by subsections (a) and (b) of
this Section for a period of five-years at the source at which the unit is located
.
The records must be made available to the Agency and USEPA upon request
.
d)
Reporting requirements :
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NOTICE OF PROPOSED RULES
1)
The owner or operator must notify the Agency in writing 30 days and five
days prior to testing pursuant to Section 217 .394(a) and :
A)
If after the 30-days notice for an initially scheduled test is sent,
there is a delay (e .g., due to operational problems) in conducting
the performance test as scheduled, the owner or operator of the unit
must notify the Agency as soon as possible of the delay in the
original test date, either by providing at least seven days prior
notice of the rescheduled date of the performance test, or by
arranging a new test date with the Agency by mutual agreement ;
B)
Provide a testing protocol to the Agency 60 days prior to testing
;
and
C)
Not later than 30 days after the completion of the test, submit the
results of the test to the Agency .
2)
Pursuant to the requirements for monitoring in Section 217 .394(d), the
owner or operator of the unit must report to the Agency any monitored
exceedances of the applicable NO, concentration from Section 217
.388(a)
or (b) within 30 days of performing the monitoring
.
3)
Within 90 days of permanently shutting down an affected unit or a unit
included in an emissions averaging plan, the owner or operator of the unit
must withdraw or amend the applicable permit to reflect that the unit is no
longer in service .
4)
If demonstrating compliance through an emissions averaging plan :
A)
By October 31 following the applicable ozone season, the owner or
operator must notify the Agency if he or she cannot demonstrate
compliance for that ozone season ; and
B)
By January 30 following the applicable calendar year, the owner or
operator must submit to the Agency a report that demonstrates the
following :
i)
For all units that are part of the emissions averaging plan,
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the total mass of allowable NO x
emissions for the ozone
season and for the annual control period
;
ii)
The total mass of actual NO, emissions for the ozone
season and annual control period for each unit included in
the averaging plan;
iii)
The calculations that demonstrate that the total mass of
actual NO, emissions are less than the total mass of
allowable NOx emissions using equations in Sections
217.390(f) and (g); and
iv)
The information required to determine the total mass of
actual NOx
emissions and the calculations performed in
subsection (d)(4)(B)(iii) of this Section .
5)
If operating a CEMS, the owner or operator must submit an excess
emissions and monitoring systems performance report in accordance with
the requirements of 40 CFR 60 .7(c) and 60 .13, or 40 CFR 75 incorporated
by reference in Section 217
.104, or an alternate procedure approved by the
Agency or USEPA and included in a federally enforceable permit .
6)
If using NO, allowances to comply with the requirements of Section
217.388, reconciliation reports as required by Section 217
.392(b)(3).
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POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
APPENDIX G
: EXISTING RECIPROCATING INTERNAL COMBUSTION ENGINES
AFFECTED BY NOx SIP CALL
Plan ID
Point ID
Segment
ANR Pipeline Co . - Sandwich
093802AAF
E-108
1
Natural Gas
027807AACPipeline
Co . of America 8310
730103540041_
Natural Gas Pipeline Co . of America Sta 110
073816AAA
851000140011
1
073816AAA
851000140012
2
673816AAA
851000140013
3
073816AAA
851000140014
073816AAA
851000140041
073816AAA
851000140051
Northern Illinois Cas Co . - Stor Stat 359
113817AAA
730105440021
1_
113817AAA
730105440031
1
113821AAA
730105430021
113821AAA
730105430051
Panhandle Eastern Pipe Line Co : Glenarm
167801AAA
87090038002
167801AAA
87090038004
167801AAA
87090038005
1
Panhandle Eastern Pipeline
-
Tuscola S
041804AAC
73010573009
9
041804AAC
73010573010
10
041804AAC
73010573011
11
041804AAC
73010573012
12
041804 AC
73010573013
13
ILLINOIS REGISTER
POLLUTION CONTROL BOARD
NOTICE OF PROPOSED RULES
Panhandle Eastern Pipeline Co .
149820AAB
7301057199G
3
149820AAB
73010571991
1
149820AAB
7301057199)
1
149820AAB
7301057199K
1
Panhandle Eastern Pipeline Co : Glenarm
167801AAA
87090038001
1
Phoenix Chemical Co .
085809AAA
730700330101
1
085809AAA
730700330102
2
085809AAA
730700330103
3
TECHNICAL SUPPORT DOCUMENT
FOR
CONTROLLING NOx EMISSIONS
FROM
STATIONARY RECIPROCATING INTERNAL COMBUSTION
ENGINES AND TURBINES
AQPSTR 07-01
March 19, 2007
ILLINOIS ENVIRONMENTAL PROTECTION AGENCY
AIR QUALITY PLANNING SECTION
DIVISION OF AIR POLLUTION CONTROL
BUREAU OF AIR
1021 NORTH GRAND AVENUE EAST
P.O
. BOX 19276
SPRINGFIELD, IL 62794-9276
Table of Contents
Page
List of Figures
4
List of
Tables
5
List of Acronyms
7
Executive Summary
9
1 .0
Introduction
12
2.0
Background
14
2.1
National Ambient Air Quality Standards (NAAQS) for Ozone and
Fine Particulates
14
2 .2
NOx SIP Call
16
2 .3
Reasonably Available Control Technology (RACT) 17
2 .4
Reasonable Further Progress (RFP)
18
2 .5
Air Quality Impacts of Existing Regulations
19
3 .0
Process Description and Sources of Emissions
26
3 .1
Stationary Reciprocating Internal Combustion Engines (RICE) 26
3 .2
Stationary Turbines
27
4.0
Technical Feasibility of Controls
29
4 .1
Air/Fuel Ratio Adjustment
29
4 .2
Ignition Timing Retard
30
4 .3
Prestratified Charge
31
4 .4
Low Emission Combustion (LEC)
31
4 .5
Water/Steam Injection
32
4 .6 Dry Low-NOx Combustors
33
4 .7
Non-Selective Catalytic Reduction (NSCR) 34
4 .8
Selective Catalytic Reduction (SCR)
35
4.9
Technical Feasibility of Controls Summary
35
5.0
Cost Effectiveness of Controls
37
5 .1
Cost Effectiveness of Controls on RICE
37
5 .2
Cost Effectiveness of Controls on Turbines
42
6.0
Existing and Proposed Regulations
45
6.1
Existing Illinois Regulations
45
6.2
Other States Regulations
45
6.3
Proposed Illinois Regulations
47
7.0
Potentially Affected Sources
54
7.1
Sources Affected by the NOx Sip Call
54
7.2
Other Potentially Affected Sources
54
8.0
Emissions Reductions
56
2
8 .1
Reductions from Sources Affected by the NOx SIP Call
56
8 .2
Reductions from Other Affected Sources
56
9.0 Summary
59
10.0 References
62
Attachment A
Assessment of Regional NOx Emissions
in the Upper Midwest
65
Attachment B
List of Sources Affected by the NOx SIP Call 79
Attachment C
List of Impacted RICE and Turbines
82
3
List of Figures
Figure 2-1
PM2.
5 Nonattamment Areas
15
Figure 2-2
8-Hour Ozone Nonattainment Areas
15
Figure 2-3
Quarterly Average PM2
.5
Reductions from a
30% NOx Emission Reduction
24
Figure 2-4
8-hour Ozone Reductions from a 30% NOx Reduction
25
4
List of Tables
Table 2-1
Illinois Contribution to Downwind Ozone Nonattainment Counties in
2010 Based on U .S. EPA's Modeling in Support of the CAIR
Rulemaking
21
Table 2-2
Illinois Contribution to Downwind PM 2 5 Nonattainment Counties in
2010 Based on U .S. EPA's Modeling in Support of the CAIR
Rulemaking
22
Table 3-1
Uncontrolled NOx Emissions from RICE and Turbines 28
Table 4-1
Potential Emissions Reductions from RICE
36
Table 4-2
Potential Emissions Reductions from Turbines 36
Table 5-1
Cost Effectiveness for Retrofit of Various NOx Control Systems
38
Table 5-2
2007 Ozone Season NOx Emission Reductions for Large
RICE
40
Table 5-3
2007 Cost and Cost-Effectiveness Results for Large
RICE
40
Table 5-4
Costs and Cost Effectiveness of LEC Controls in 2004 Dollars 41
Table 5-5
AirControlNET Costs of Various NOx Combustion Controls Available
for RICE
42
Table 5-6
Cost Effectiveness for Various NOx Control Systems for Turbines 43
Table 5-7
AirControlNET Costs of Various NOx Combustion Controls Available for
Turbines
43
Table 6-1
NOx Control Requirements for RICE in Other States 46
Table 6-2
NOx Control Requirements for Turbines in Other States
47
Table 6-3
Example of Averaging Plan-Case I
50
Table 6-4
Example of Averaging Plan-Case 2
50
Table 6-5
Compliance Schedule for Various Types of Affected Units
52
Table 7-1
Number of Affected Sources
55
5
Table 8-1
Estimated NOx Emissions Reductions from Affected RICE 57
Table 8-2
Estimated NOx Emissions Reductions from Affected Turbines
57
Table 8-3
Estimated NOx Emissions Reductions from Affected RICE
and Turbines
57
6
A/F
ACT
ALAPCO
BART
bhp
Board
BOOS
Btu
CAA
CAIR
CO
CO2
CPI
CT
EE
EGU
FIP
HC
Illinois EPA
ITR
Lb
LADCO
LEC
mmBtu
MW
NAA
NAAQS
NOx
02
03
PM2.5
ppm
ppmv
PSC
PTE
RACT
RFP
RIA
RICE
SCR
SI
SIP
SNCR
SO2
STAPPA
List of Acronyms
air-to-fuel
Alternative Control Techniques document
Association of Local Air Pollution Control Officials
Best Available Retrofit Technology
brake horsepower
Illinois Pollution Control Board
burner out of service
British Thermal Unit
Clean Air Act
Clean Air Interstate Rule
carbon monoxide
carbon dioxide
Consumer Price Index
combustion tuning
energy efficiency
electric generating unit
Federal Implementation Plan
hydrocarbons
Illinois Environmental Protection Agency
ignition timing retard
pound
Lake Michigan Air Directors' Consortium
low emission combustion
million British Thermal Units
megawatt
nonattainment area
National Ambient Air Quality Standards
nitrogen oxide
oxygen
ozone
fine particulate matter
parts per million
parts per million by volume
prestratified charge
potential to emit
Reasonably Available Control Technology
Reasonable Further Progress
Regulatory Impact Analysis
stationary reciprocating internal combustion engine
selective catalytic reduction
spark-ignited
State Implementation Plan
selective non-catalytic reduction
sulfur dioxide
State and Territorial Air Pollution Program
7
TSD
Technical Support Document
TPY
tons per year
VOM
volatile organic material
ug/m3
microgram per cubic meter
U.S. EPA
United States Environmental Protection Agency
8
Executive Summary
This technical support document (TSD) presents the rationale, documentation, and methodology
developed by the Illinois Environmental Protection Agency (Illinois EPA) in support of its
proposed regulation to control nitrogen oxide (NOx) emissions from stationary reciprocating
internal combustion engines (RICE) and turbines . Reciprocating internal combustion engines
and turbines are a significant source category of NOx emissions in Illinois and a contributor to
fine particulate matter (PM2 .5) and ozone levels in areas of Illinois that are designated as
nonattainment areas (NAAs) for these pollutants . Air quality modeling performed by the United
States Environmental Protection Agency (U.S. EPA) and by the Lake Michigan Air Directors'
Consortium (LADCO) indicates that control of NOx emissions are necessary for the State of
Illinois to attain the National Ambient Air Quality Standards (NAAQS) for 8-hour ozone (62 FR
38885) and PM2 .5 (62 FR 38652).' 2 This regulatory proposal is intended to satisfy, in part,
Illinois' obligation under the Clean Air Act (CAA) to develop a State Implementation Plan (SIP)
to comply with the NAAQS
.
On April 21, 2004, U.S. EPA issued the final NOx SIP Call that required large RICE that emit
more than one ton per day of NOx emissions during the ozone season to reduce their NOx
emissions by 82 to 90 percent relative to 1995 levels . This regulatory proposal, if adopted, will
satisfy this federal requirement
. This proposal is also intended to address, in part, the
requirement for Reasonably Available Control Technology (RACT) for NOx in 8-hour ozone and
PM2.5 nonattainment areas (NAAs)
. The Illinois EPA intends to address RACT requirements for
other source categories in a separate rulemaking
. This proposal will also address, in part, federal
requirements to achieve emission reductions needed to ensure Reasonable Further Progress
(RFP) toward attainment of the NAAQS .
Illinois EPA is proposing to control NOx emissions from sources that have a potential to emit
(PTE) of 100 tons per year (TPY) of NOx, aggregated from all the affected units at the source
.
Regulations to control NOx emissions from RICE down to 500 brake-horsepower (bhp) and
turbines down to 3 .5 megawatts (MW) that are not regulated under other existing or proposed
NOx regulations are included in this proposal
. The proposed regulation does not apply to
9
emergency standby engines
; engines used in research and testing for the purposes of performance
verification of engines; engines/turbines regulated under Subpart W of 35 Ill . Adm. Code;
engines/turbines used for agricultural purpose ; and certain portable engines . Illinois EPA, in
consultation with the affected sources, is proposing a low-usage limit of 8 million bhp-hour per
year, aggregated from all affected engines at a source, and 20 thousand MW-hour per year,
aggregated from all affected turbines at a source .
The statewide NOx control levels proposed in this submittal are considered reasonable,
attainable, and cost-effective
. The NOx emissions levels are prescribed in parts per million by
volume (ppmv) corrected to 15 percent oxygen (02) on a dry basis . The NOx limits for engines
are 150 ppmv for spark-ignited rich-bum; 210 ppmv for spark-ignited lean-bum; 365 ppmv for
Worthington engines ; and 660 ppmv for diesel engines
. For turbines, the NOx limits are 42
ppmv for gas-fired, and 96 ppmv for liquid-fired turbines. An owner or operator may comply
with the control requirements by averaging the emissions of affected units . Compliance with the
emission limits will be determined on both an ozone season (May 1 to September 30) and an
annual (January 1 to December 31) basis each year
.
This proposal requires the owner or operator of large engines that emit more than 1 ton of NOx
per summer day to reduce the emissions from those engines by 82 percent by the beginning of the
2007 ozone control season (by May 1, 2007)
. It also requires that each stationary internal
combustion engine of 500 bhp capacity and above, and each stationary turbine of capacity equal
to or greater than 3
.5 MW be controlled to prescribed standards and by specified compliance
dates based on the size and geographical location of the affected unit .
The Illinois EPA relied on the cost data and cost effectiveness estimates contained in the U .S.
EPA's TSDs for the NOx SIP Call, alternative control technology (ACT) guidance documents
prepared by the U .S EPA for RICE and turbines, and the U.S. EPA's AirControlNET cost
analysis model
. The proposed regulations will reduce NOx emissions by 5,422 tons per ozone
season in the 2007 ozone control season and satisfy the U .S. EPA's NOx SIP Call Phase II
requirements for impacted RICE
. In addition, the proposed regulation will potentially affect a
total of 202 RICE (including engines affected by the NOx SIP Call) and 36 turbines in Illinois .
10
When fully implemented, NOx emissions will be reduced statewide by approximately 17,082
TPY and 7,206 tons per ozone control season
. This equates to NOx reductions from this source
category of approximately 65 percent on an annual basis, and 55 percent in the ozone season
.
11
1 .0
Introduction
This TSD presents the rationale, documentation, and methodology developed by the Illinois EPA
to support its proposed regulation to control NOx emissions from RICE and turbines . RICE and
turbines are significant sources of NOx emissions in Illinois
. Based on the Illinois EPA's 2002
base year emissions inventory, out of 277,899 TPY of NOx emissions from point sources in
Illinois, approximately 23,347 TPY of NOx were emitted from RICE and turbines . This
represents approximately 8 .4 percent of Illinois' total point source NOx emissions .
Illinois has the responsibility under the CAA to develop a State Implementation Plan (SIP) which
provides the emissions reductions needed to attain the NAAQS for ozone and PM 2.5. Air quality
modeling performed by U .S
. EPA and LADCO indicates that control of NOx emissions is
necessary for the State of Illinois to comply with the NAAQS for 8-hour ozone
I and PM2.5
2
The
statewide NOx emissions reductions which will be achieved by implementation of this proposal
are a necessary component of Illinois' plan to attain the NAAQS .
This proposal is an element of Illinois EPA's plan to meet the NAAQS, but it is intended to
address other federal requirements as well
. As will be discussed later in this report, the proposal
is intended to address the requirements of U .S
. EPA's Phase H of the NOx SIP Call affecting
large RICE
. This proposal is also intended to address, in part, the requirement for RACT for
NOx in 8-hour ozone and PM 2.5 NAAs. The Illinois EPA intends to address RACT requirements
for other source categories in a separate rulemaking . This proposal will also address, in part,
federal requirements to achieve emission reductions needed to ensure RFP toward attainment of
the NAAQS.
A brief summary of the various sections in this TSD is as follows :
Section 2 provides background information on ozone and particulate matter air quality and the
effects of these pollutants on human health
. The regulatory requirements that are being
addressed by this proposal are also described in Section 2 . National and regional air quality
12
modeling analyses demonstrating the effectiveness of local and regional NOx emission
reductions on improving air quality are also presented .
Section 3 contains descriptions of the various types of internal combustion engines and turbines
and how NOx emissions are generated by these processes
. Also presented in this Section are the
estimated uncontrolled levels of NOx emissions from RICE and turbines in Illinois
.
Section 4 identifies control techniques available to reduce NOx emissions from RICE and
turbines .
General cost information on various control technologies is discussed in Section 5 . This Section
provides cost information for the various control technologies that are available to control NOx
emissions from stationary RICE and turbines, described in terms of cost effectiveness of controls
(i.e., dollars per ton of NOx emission reduced) to comply with the proposed regulation
.
Existing and proposed regulations are discussed in Section 6 . This Section summarizes the
existing Illinois NOx regulations, and other states' NOx regulations for RICE and turbines, and
concludes with an explanation of the proposed regulations .
Sources in Illinois that are potentially affected by the proposed regulations are listed in Section 7
.
Also described in this Section is the methodology that Illinois EPA used to identify sources that
may potentially be affected by the proposed regulations
.
Section 8 provides an estimate of emissions reductions that will be achieved by implementing the
Illinois EPA's proposal and explains the methodology used by Illinois EPA to estimate NOx
emissions reductions from this proposal.
Finally, a summary of this TSD is provided in Section 9 .
13
2.0
Background
2.1
National Ambient Air Quality Standards for Ozone and Fine Particulates
The U.S. EPA revised the NAAQS for particulate matter and ozone in 1997
.'1,2 The revised
standards for particulate matter recognized that the smallest particles, those less than equal to 2 .5
microns in diameter, have adverse health effects in the humans . In response to the establishment
of the NAAQS for PM2.5,
U.S
. EPA designated two areas in Illinois as NAAs : the Chicago area
(consisting of Cook, DuPage, Kane, Lake, McHenry, and Will counties, and the townships of
Oswego, in Kendall County, and Aux Sable and Goose Lake, in Grundy County), and the Metro-
East St. Louis area (consisting of Madison, Monroe, and St . Clair counties, and Baldwin
Township in Randolph County) . Figure 2-1 shows the PM2.5 NAAs for Illinois and nearby states .
These designations became effective on April 5, 2005 (70 FR 943)."
The revised NAAQS for ozone replaced the previous 1-hour averaging time with an 8-hour
averaging time, and reduced the applicable ambient concentration threshold from 0
.12 parts per
million (ppm) to 0.08 ppm. U.S. EPA designated certain areas in Illinois and other states as
nonattainment for this air quality standard . Figure 2-2 shows the 8-hour ozone NAAs for the
states in the central U.S . These designations became effective on June 15, 2004 (69 FR 23858).27
Geographically, the ozone NAAs in Illinois are roughly the same areas that were designated as
nonattainment for PM2,5 . The exception is in the Metro-East area . The 8-hour ozone NAA
includes Jersey County and does not include Baldwin Township in Randolph County, while the
PM2.5
NAA does not.
Fine particles and ozone are associated with thousands of premature deaths and illnesses each
year in the United States . In revising the NAAQS for particulate matter, U .S
. EPA found that
fine particles aggravate respiratory, lung, and cardiovascular diseases, decrease lung function,
and increase asthma attacks, heart attacks, and cardiac arrhythmia . As a consequence of
exposure to PM2.5
, hospital admissions and emergency room visits increase as
does absenteeism
from school and work. Older adults, people with heart and lung disease, and children are the
segments of society that are particularly sensitive to fine particle exposure . Attainment of the
PM2.5 standard will prolong thousands of lives in Illinois and other states . Additional
14
information on the health effects of fine particles can be found on U .S . EPA's website at
littp_iwwwcpa
.gov/ttn/naags/sIandards/pm/ s pm index .hlnil.
Figure 2-1
PM2
.
5
Nonattainment Areas
PM2 .5 Designations
Attarient
- Nonanaitment
Nonanairanent (pan county)
Figure 2-2
8-Hour Ozone
Nonattainment Areas
8-Hour Ozone Designations
PltaIn
t
- Nonanair neat
Nonattamrnent (pan wunty)
U.S. EPA's revised NAAQS for ozone was intended to provide increased protection to the
public, especially children and other at-risk populations, against a wide range of ozone-induced
health effects . In setting the 8-hour ozone standard, U .S . EPA found that exposures to ozone of
one to three hours in length had been found to irritate the respiratory system, causing coughing,
throat irritation, and chest pain . Ozone exposure can limit lung function and breathing capacity,
resulting in rapid and shallow breathing, thereby lowering or curtailing a person's normal activity
level. As with PM2.5
exposure, ozone exposure increases asthma attacks for people with
respiratory disorders. Longer-term ozone exposure may result in damage to the lung tissue and
15
lining from inflammation, which can produce permanent and irreversible changes in lung
function . Children and adults who are active outdoors are particularly susceptible to ozone, as
are people with asthma and respiratory diseases . Ozone also affects sensitive ecosystems and
vegetation, resulting in reduced crop yields, reduced growth and lowered pest resistance, and a
lowered ability for plants and trees to survive . Additional information on the health effects to
humans and vegetation from exposure to ozone is found on U .S . EPA's website :
http ://www .epa.gov/ttn/naags/standards/ozonc/
s o3 index .html
U
.S
. EPA has long recognized the relationship between emissions of NOx and adverse regional
air quality issues and federal efforts to reduce emissions of NOx were initiated in 1990 . The
CAA placed several new requirements to reduce NOx emissions
. The federal programs that
affect NOx emissions sources are discussed in the following subsections .
2.2
NOx SIP Call
Section 110 of the CAA mandates that the State of Illinois adopt a SIP containing adequate
provisions to assure attainment of the primary and secondary NAAQS within its boundaries .
Further, Section 11 0(a)(2)(D) of the CAA prohibits stationary sources from emitting air
pollutants that prevent any other state from attaining the NAAQS . On October 27, 1998, U.S .
EPA determined that sources in twenty-two states, including Illinois, emitted NOx in amounts
that significantly contributed to nonattainment of the 1-hour ozone NAAQS in one or more
downwind states, and issued a call for revisions to states' implementation plans . U.S
. EPA's rule
required the identified states to revise their SIP's to reduce emissions of NOx from certain
sources by September 30, 1999
. This action is commonly referred to as the NOx SIP Call .
To calculate the NOx budget for stationary sources for each of the NOx SIP Call states, U .S .
EPA selected large electric generating units (EGU) and certain large non-EGU sources for which
highly cost-effective control measures were available to reduce NOx emissions . For Illinois,
U
.S
. EPA required an overall reduction of approximately 27 percent from its projected 2007 base
ozone season total of 368,933 tons of NOx emissions
.
16
For large RICE, U .S. EPA determined that NOx emissions should be reduced by 90 percent, a
level that U .S. EPA determined to be highly cost effective . Legal challenges to the NOx SIP Call
delayed implementation of the provisions affecting large RICE . On March 3, 2000, the DC
Circuit issued its decision in Michigan v. EPA (213 F3d 663 (DC Cir. 2000) 69 Fed. Reg.
21603),5 that U.S. EPA failed to provide adequate notice of the change in the control level
assumed for large RICE . On April 21, 2004, in response to the court's decision, U .S. EPA issued
a final rules that required large RICE that emit one ton or more of NOx per summer day to
control NOx emissions by 82 percent to 90 percent (82 percent for gas-fired and 90 percent for
other liquid-fired engines) . The required control level for large non-EGU turbines was 60
percent below their projected 2007 uncontrolled level. hi Illinois, the NOx SIP Call affects large
engines, greater than 1,500 bhp, and large turbines, 25 MW capacities and greater
. This proposal
is intended to satisfy this Federal requirement .
2.3 Reasonably Available Control Technology (RACT)
Pursuant to Sections 172, 182(b) and (f) of the CAA, PACT is required for all existing major
sources of the applicable criteria pollutant and its precursors located in NAAs
. This rulemaking
addresses NO, as a precursor to ozone and PM2 .5. U.S
. EPA defines RACT as the lowest
emission limitation that a particular source is capable of meeting by the application of control
technology that is reasonably available considering technological feasibility and economic
reasonableness (70 Fed. Reg. 71612).28
The major source threshold for moderate NAAs is
defined as 100 TPY . A source generally consists of several units that emit pollutants
. The sum
of emissions from all units at the source determines if a unit is major and thus subject to
RACT
requirements . This rulemaking addresses two RACT categories, engines and turbines .
Additional RACT categories will be addressed in subsequent rulemakings
.
RACT is not a new requirement under the CAA, but one that had previously been waived with
respect to Illinois' two ozone NAAs . For the implementation of the 1-hour ozone NAAQS,
Illinois requested and received a waiver under Section 182(1) of the CAA from the requirement
to implement NOx RACT for major sources located in ozone NAAs
. With respect to the 8-hour
ozone NAAQS, Illinois will not pursue the NOx waiver because the local-scale, NOx disbenefit
17
(i.e., the scavenging of ambient ozone by local nitrogen oxide emissions) is not as important for
the longer 8-hour averaging time . Also, the level of the 8-hour ozone standard is closer to
regional background levels in the Midwest, which argues for the application of controls on a
regional basis . Illinois therefore intends to submit a SIP revision to implement NOx RACT
requirements per Sections 182(b)(2) and 182(f) of the CAA . Pursuant to 40 CFR 51 .912, the
State is required to submit a RACT SIP no later than 27 months (September 2006) after
designation of NAAs that provides for implementation of the measures no later than the first
ozone season that occurs 30 months after the RACT SIP is due (2009 ozone season)
. (70
FR
71611, 71701)
28
This rulemaking also addresses NOx
as a precursor to PM 2,5. As Section 172 of the CAA does
not set a source size threshold and U .S. EPA has not finalized its proposed guidance for
implementation of the PM 2.5 NAAQS, there is no lower limit of the size of the source that this
requirement may affect . However, U.S. EPA has indicated in its proposed guidance that the
source threshold for this requirement will not be higher than 100 TPY for NOx and SO2 (U.S .
EPA proposed a lower threshold for PM2.5). Despite the lack of guidance, states nonetheless are
required to submit SIPs addressing RACT within three years of an area being designated as
nonattainment, April 5, 2008 .
2.4
Reasonable Further Progress (RFP)
For an area classified
as an ozone NAA under Subpart 2 of Part D of the CAA, and the
requirements of Section 182, a state is required to submit a SIP revision that includes measures
that ensure RFP towards the emissions reductions targets needed for attainment (40 CFR
51
.910). To meet RFP requirements of Section 172(c)(2) of CAA, the state is required to submit
no later than 3 years (June 2007) following designation for the 8-hour NAAQS, a SIP providing
for RFP from the baseline year (2002) within 6 years after the baseline year (2008)
. The state
may use either NOx for VOM emission reductions (or both) to achieve the RFP reduction
requirement
. Use of NOx emissions reductions must meet the criteria in Section 182(c) (2) (C)
of the CAA
. For each subsequent 3-year period out to the attainment date, the RFP SIP must
provide for an additional increment of progress . The increment for each 3-year period must be a
18
portion of the remaining emission reductions needed for attainment beyond those reductions
achieved for the first increment of progress
(e.g., beyond 2008).
U.S. EPA has not finalized its proposed guidance for implementation of the PM 2.5 NAAQS.
Preliminary guidance published on November 1, 2005, indicates that states are required to submit
SIPs addressing RFP within three years of an area being designated as nonattainment .
2.5
Air Quality Impacts of Existing Regulations
Areas classified as moderate or higher for 8-hour ozone are subject to the attainment
demonstration requirement for that classification under Section 182 of the CAA (40 CFR
51 .910)
. The demonstration is due no later than 3 years after its designation . The demonstration
must meet the requirements of 40 CFR 51 .112 and be determined by a photochemical grid model
or other method approved by U .S. EPA. Although U .S. EPA has not finalized its proposed
guidance for implementation of the PM2 .5 NAAQS, preliminary guidance published on
November 1, 2005, indicates that states are required to submit SIPs addressing the attainment
demonstration within three years of an area being designated as nonattainment . (70 FR 65984)
.
29
The Illinois EPA has been working with its counterparts in nearby states to develop attainment
demonstrations for ozone and PM2.5 for both of its NAAs. In the Lake Michigan region, the
modeling demonstrations are being performed under the direction of LADCO . For the St . Louis
metropolitan area, including Metro-East, the Illinois EPA is working closely with the Missouri
Department of Natural Resources to perform the requisite modeling. The 8-hour ozone
attainment demonstrations must be submitted to the U .S. EPA by June 15, 2007
. The PM2
.5
attainment demonstrations are due by April 5, 2008
. Although this work is ongoing, and the
attainment targets for emissions reductions have not been fully identified, sufficient modeling has
been conducted to date by the U .S
. EPA, LADCO, and the Illinois EPA to justify the Illinois
EPA's proposals to reduce NOx emissions from RICE, turbines, and other NOx emission sources
statewide as part of its overall plan to attain both the ozone and PM2
.5 NAAQS in Illinois.
19
U.S
. EPA performed air quality modeling to evaluate the air quality benefits of emission controls
required by the Clean Air Interstate Rule (CAIR) . U.S
. EPA finalized CAIR on May 12, 2005,
and CAIR is intended to address, in part, ozone and PM2.5
air quality problems and improve
public health and the environment .30 Through air quality modeling, U .S
. EPA determined that
NOx and SO2 emissions from sources in 28 states (including Illinois) and the District of
Columbia contribute significantly to nonattainment of the NAAQS for PM2.
5 and/or 8-hour
ozone in one or more downwind states . U.S. EPA used the Comprehensive Air Quality Model
with Extensions (CAMx) for the ozone analysis and the Community Model for Air Quality
(CMAQ) for PM2.5
(Technical Support Document for the Final Clean Air Interstate Rule
- Air
Quality Modeling, U .S
. EPA, March 2005) .6
U.S
. EPA's model results for ozone demonstrate that regional NOx emission reductions are
effective at improving ozone air quality
. However, U.S. EPA also showed that, because CAIR
does not provide significant NOx emission reductions in 2010, CAIR NOx emission controls
provide few air quality benefits in 2010, beyond those provided by the NOx SIP Call
. U.S. EPA
concluded that the Chicago ozone NAA and other NAAs around Lake Michigan will continue to
exceed the 8-hour ozone standard in 2010
. In fact, U.S. EPA's modeling shows that the Chicago
area will not attain the 8-hour ozone standard even with full implementation of CAIR in 2015,
and significant additional emission reductions will be necessary .
Illinois has been shown to contribute significantly to ozone nonattainment in a number of
counties downwind of Illinois
. These counties and associated contributions from Illinois are
given in Table 2-1, based on U.S. EPA's modeling .
For PM2.5, U.S
. EPA's modeling demonstrates that regional SO2 and NOx reductions are
effective at improving
PM2.5 air quality. The modeling also shows that CAIR NOx and SO2
emission reductions provide some air quality benefits in 2010
. For Illinois, however, the
modeling shows that CAIR does not provide sufficient emission reductions for the St
. Louis and
Chicago NAAs to attain the PM2.5
annual standard, even by 2015 . Clearly, Illinois will need to
20
pursue additional emission reductions beyond CAIR to achieve compliance with the PM2
.5
NAAQS.
Table 2-1
Illinois Contribution to Downwind Ozone Nonattainment Counties in 2010 Based on
U.S.
EPA's Modeling in Support of the CAIR Rulemaking
Note: U.S. EPA's significance criteria is 2 ppb .
Illinois has been shown to contribute significantly to PM2 .5 nonattainment in 2010 in a number of
counties downwind of Illinois . These counties and associated contributions from Illinois are
given in Table 2-2, based on U.S. EPA's modeling .
Initial modeling performed by LADCO has confirmed U .S
. EPA's modeling analysis of the air
quality benefits of CAIR, and the need for states to pursue additional emission reductions to
address residual nonattainment problems
. LADCO used the CAMx model, the same model used
by U.S. EPA, and an updated emissions inventory for their analysis of CAIR
. It should be noted
that this work is ongoing, and the attainment targets for emissions reductions have not yet been
fully identified . LADCO has prepared a summary of recent modeling that describes the role of
NOx emissions in causing ozone, PM2 5, and regional haze problems in the Midwest
. This
document, entitled "Assessment of Regional NOx Emissions in the Upper Midwest" (February
15, 2007) is included as Attachment A of this report
. LADCO's assessment demonstrates that
NOx emissions from sources throughout Illinois, both in nonattainment areas and in attainment
areas, contribute to ozone and PM2
.5 formation in Illinois and downwind states . LADCO's
assessment also shows that emissions from both EGU and non-EGU point sources are significant
components of Illinois' overall emission inventory, and that these sources contribute to air
21
Downwind State
County
Contribution (ppb)
WI
Kenosha
57
WI
Ozaukee
43
WI
Sheboygan
36
MI
Macomb
16
OH
Geauga
15
quality problems in the region, whether or not they are located within the boundaries of
nonattainment areas .
Table 2-2
Illinois Contribution to Downwind PM 2.5 Nonattainment Counties in 2010 Based on U .S.
EPA's Modeling in Support of the CAIR Rulemaking
Note: U.S. EPA's significance criteria is 0 .2 ug/m
.
The Illinois EPA performed a sensitivity modeling analysis to determine the extent to which
NOx emission reductions would result in ozone and PM2.5 air quality improvements in Illinois
and downwind states . This modeling used the 2009 base case developed by LADCO as the
starting point to determine the sensitivity of predicted ozone and PM2 .5 concentrations to an
assumed 30% reduction of NOx emissions within the modeling domain . The modeled 30% NOx
22
Downwind State
County
Contribution (ug/m3)
AL
Jefferson
0.21
IL
Cook
1 .04
IL
Madison
0.80
IL
St. Clair
0.83
IN
Clark
0.39
IN
Dubois
0.58
IN
Lake
1 .02
IN
Marion
0.76
IN
Vanderburgh
0 .76
KY
Fayette
0 .32
KY
Jefferson
0.38
MI
Wayne
0.42
OH
Butler
0.38
OH
Cuyahoga
0.32
OH
Franklin
0.40
OH
Hamilton
0.38
OH
Lawrence
0.21
OH
Mahoning
0.25
OH
Montgomery
0.44
OH
Scioto
0.25
OH
Stark
0.26
OH
Summit
0.30
PA
Allegheny
0.21
TN
Hamilton
0.20
WV
Cabell
0.21
WV
Kanawha
0.20
emission reduction level is arbitrary and does not represent the reductions expected from a
particular control strategy . LADCO's 2009 "base case" represents expected emissions due to
implementation of control measures that are "on-the-books", plus the effects of economic and
demographic growth by the year 2009 . Other model inputs were developed by LADCO.
Modeling results for PM2.5 are shown in Figure 2-3 for each of four quarters : January -
March;
April
-
June; July - September; and October - December
. The results are depicted graphically as
difference plots, showing the difference between the 2009 "base case" and the 30% NOx
reduction scenario. The results indicate that a 30% NOx reduction, if achieved domain-wide
from all NOx sources, will improve PM 2.5 concentrations regionally by 0
.5 ug/m3 to 1 .8 ug/m3.
Improvements are shown for all four calendar quarters. The greatest benefits (spatially) are
predicted to occur in the fourth quarter (October through December), and the smallest benefits
(spatially) are predicted to occur in the first quarter (January through March)
. Improvements are
also shown for all four quarters in Illinois, with predicted PM2 .5 reductions in the range of 0
.5
ug/m3 to about 1 .5 ug/m3 .
Photochemical modeling for ozone was performed in a similar manner comparing the 2009
LADCO "base case" to the 30% NOx reduction scenario
. For ozone, only the summertime
period of June, July, and August were modeled
. Similarly, the results are depicted as difference
plots, which show the difference in 8-hour ozone concentrations between the two scenarios
.
Figure 2-4 shows the 8-hour ozone concentration differences for two days in the June 2002
regional ozone episode. Results are shown for two selected days from the three month period
modeled. These days are considered representative of the results during periods of elevated
ozone concentrations in the region
. The results indicated that widespread improvements in 8-
hour ozone concentrations are predicted to occur from the assumed 30% NOx emission reduction
from all NOx sources in the modeling domain
. Ozone improvements in Illinois range from 2 .5
ppb to about 10 ppb .
23
Figure 2-3
Quarterly Average PM2.5 Reductions from a 30% NOx Emission Reduction
030
0.00
-0 .50
-1 .00
-130
4 .00 ,
"g/ms
Quarter 12009 OTB
w/30% addt'l NOX
Episode Average Pits Difference
5g km grid
1
January 12002 011050
Mm- -1 .12 at(nasl Ma-
.11
0
at( ,26)
Quarter 3 2009 OTB
w/30% addt'l NOX
Episode Average PM" Difference
9akm grId
07
Ju l 0020L0:00
Min- -ISO at 55 .901 Ma- 0113 at(79
.7)
24
Quarter 2 2009 OTB w/30% addt'l NOX
Episode Avenge P0425 Difference
Sakm gild
October 1 .2002050110
Min- .1 .Rat(n351MU- 0.lOata11 .9g)
07
April 1
.20020A0A0
Min- -1.90 at (60591 Mur- 0 .01 at(79.7)
Quarter 4 2009 OTB w/30% addt'l NOX
I
07
Episode AVeraga P0 25 Difference
98km geld
2 .00 00
I
ISOISO
030
M
IN
il
0.00
-0.50
-lM0
-I .50
i
4.00
1
Figure 2-4
8-hour Ozone Reductions from a 30% NOx Reduction
2009 OTB vs 2009 OTB w/30% addt'l NOX
Daily Mmdmum Ozone DXlererce
12km grid-8 hour ozone-no threshold
25
2009 OTB vs 2009 OTB w/30% addt'I NOX
Dilly Mhodmum Ozone Difference
12km grid-e hour ozone -no threshold
June 182002090w
June29 .20020L0A0
Min-
-11 .7sz(70.21%14- ssat(MAI)
kiln- -1oilm(130JI21Mmr• 7ast(*.M)
In summary, modeling performed by U.S
. EPA in support of their CAIR rulemaking suggests
that CAIR does not provide for attainment with the NAAQS in Illinois
. Demonstrating
attainment in Illinois' NAAs will likely require additional emission reductions in Illinois beyond
the reductions provided by CAIR . Air quality modeling conducted to date by the U .S
. EPA,
LADCO, and the Illinois EPA justifies the Illinois EPA's proposal to reduce NOx emissions
from RICE, turbines, and other NOx emission sources statewide as part of its overall plan to
attain the NAAQS in Illinois
. Although the modeling needed to fully identify emission reduction
targets for attainment are not yet completed, air quality assessments performed to date by
LADCO and the Illinois EPA demonstrate that PM2
.5 and ozone air quality will improve
substantially from the implementation of NOx controls from point sources in Illinois, both within
and outside the nonattainment areas
. As a result, Illinois is preparing a statewide NOx RACT
rule, and has negotiated with electric utilities to achieve substantial NOx emission reductions
which are beyond the requirements of CAIR and the Clean Air Mercury Rule (CAMR)
.
3.0 Process Description and Sources of Emissions
The proposed RICE/turbines rule is an essential part of Illinois' overall statewide NOx control
strategy
. The NOx emissions from this category accounted for approximately eight percent or
23,347 TPY of total point sources NOx emissions
(277,899 TPY) for
2002
in Illinois
.
Reductions from this source category are an essential component of Illinois' NOx emission
reduction strategy.
3.1 Stationary Reciprocating Internal Combustion Engines (RICE)
"Controlling Nitrogen Oxides Under the Clean Air Act : A Menu of Options," 10 a document
published in July
1994
by the State and Territorial Air Pollution Program Administrators
(STAPPA)/Association of Local Air Pollution Control Official (ALAPCO), summarizes how
RICE operate and how they generate NOx emissions . RICE are the stationary relatives of motor
vehicle engines, using the combustion of fuel in cylinders to drive pistons with crankshafts,
which convert the linear piston motion to rotary motion . Ignition of the fuel in reciprocating
engines may be initiated by a spark or by the heat generated in the compression stroke of a
piston. Spark ignited ("SF') engines typically bum gasoline or, in large engines, natural gas,
while compression ignition engines bum diesel oil or a dual-fuel (diesel oil-natural gas) mixture .
Reciprocating engines have either four-stroke or two-stroke operating cycles . A typical
automotive engine uses a four-stroke cycle of intake, compression, power, and exhaust . Two-
stroke engines complete the power cycle in a single engine revolution compared to two
revolutions for four-stroke engines .
A final classification of reciprocating engines that influence the choice of NOx control
alternatives is based on the engine air-to-fuel ratio and the exhaust oxygen content . Rich-bum
engines, which include four-stroke spark ignition engines, typically operate with an air-to-fuel
ratio near stoichiometric and exhaust oxygen concentrations of one percent or less . Lean-bum
engines, which include two-stroke spark ignition and all compression ignition engines, have a
lean air-to-fuel ratio and typical exhaust oxygen concentrations of greater than one percent .
26
Reciprocating engines are used throughout the United States to drive compressors, pumps,
electric generators and other equipment . One prominent use of large engines is to drive natural
gas pipeline compressor stations . Except for three engines compressing ammonia at a chemical
plant, all engines affected by the NOx SIP Call-Phase 2 rule in Illinois are used to compress
natural gas at natural gas pipeline stations . All currently operating RICE that are large enough to
be affected by the Illinois EPA proposal are either rich-burn or lean-burn engines that bum
natural gas exclusively.
RICE are significant sources of NOx because they burn large amounts of fuel at high
temperatures and pressures, which cause the nitrogen and oxygen in the air that sustains the
combustion to unite and form the various oxides of nitrogen that constitute NOx
. Thermal NOx
is the predominant mechanism by which NOx is formed in RICE
. Reducing combustion
temperatures and pressures are therefore effective in reducing NOx emissions from reciprocating
engines. Although in theory additional NOx could be formed from nitrogen found in the fuel,
virtually all RICE burn fuels containing little if any nitrogen . Therefore, fuel NOx formation is
minimal in RICE .
3.2 Stationary Turbines
The same STAPPA/ALAPCO document, 1° referenced to previously in Section 3.1
also provides
a description and sources of NOx emissions from turbines
. A gas turbine is an internal
combustion engine that operates with rotary rather than reciprocating motion
. There are three
basic phases in the operation of a turbine : compression, combustion, and conversion to power
.
Ambient air is drawn in and compressed up to 30 times ambient pressure and directed to the
combustor section where fuel is introduced, ignited, and burned
. Hot combustion gases are then
diluted with additional air from the compressor and directed to the turbine section at
temperatures up to 2,350°F
. Energy from the hot expanding exhaust gases are then recovered in
the form of a shaft horsepower, of which 50 percent is needed to drive the internal compressor,
and the balance of recovered shaft energy is available to drive external load units
.
The heat content of gases exiting the turbine can either be discarded without heat recovery
(simple cycle)
; used with a heat exchanger to preheat combustion air entering the combustor
27
(regenerative cycle) ; used with or without supplementary firing, in a heat recovery steam
generator to raise process steam temperature (cogeneration) ; or used with or without
supplementary firing to raise steam temperature for a steam turbine Rankine cycle (combined
cycle or repowering). The majority of turbines used in large stationary installations are either
peaking simple cycle, two-shaft or base load, combined cycle turbines . Smaller turbines are used
to compress gas in natural gas pipelines or to generate electricity .
The principle type of NOx formed in a turbine firing natural gas or distillate oil is thermal NOx .
Most thermal NOx is formed in high temperature stoichiometric flame pockets downstream of
fuel injectors where combustion air has mixed sufficiently with the fuel to produce the peak
temperature fuel/air interface . The maximum thermal NOx production occurs at a slightly lean-
fuel mixture because of excess oxygen available for reaction . The control of stoichiometry is
critical in achieving reduction in thermal NOx . The thermal NOx generation also decreases
rapidly as the temperature drops below the adiabatic temperature (for a given stoichiometry) .
Maximum reduction in thermal NOx generation can thus be achieved by control of both the
combustion temperature and the stoichiometry
.
Table 3-1 describes the uncontrolled NOx emissions in parts per million by volume (ppmv)
corrected to 15 percent oxygen (02) from various types of RICE and turbines .
Table 3-1
Uncontrolled NOx Emissions from RICE and Turbiness'"0
28
Type of Unit
Uncontrolled NOx Emissions (ppmv (ii 15% 021
Range
Average
Rich-Bum SI Engines
880 - 1090
1060
Lean-Bum SI Engines
580 - 1360
1230
Diesel Engines
820-950
880
Dual-Fuel Engines
360-780
620
Natural Gas-fired Combustion Turbine
99-430
264
Distillate Oil fired Combustion
Turbine
150 -
680
415
4.0
Technical Feasibility of Controls
For reciprocating engines and turbines both combustion controls and post-combustion catalytic
reduction technologies can be applied to reduce NOx emissions
. Combustion controls for
reciprocating engines, include air/fuel ratio adjustments, low emission combustion, and
prestratified charge
. These controls function by modifying the combustion zone air/fuel ratio,
thus influencing oxygen availability and peak flame temperature
. Ignition timing retard lowers
the peak flame temperature by delaying the onset of combustion
. For turbines water/steam
injection and dry low-NOx combustors are the combustion control technologies used to reduce
NOx emissions
. The two post-combustion control strategies that destroy NOx for RICE and
turbines are selective catalytic reduction and non-selective catalytic reduction
. U.S. EPA's
Alternative Control Techniques Document--NOx Emissions from Stationary Reciprocating
Internal Combustion Engines,
and
NOx Emissions from Gas Turbines, 9
provide additional
details on these NOx control techniques
.
4.1
Air/Fuel Ratio Adjustment
Lowering the air-to-fuel (A/F) ratio in rich-burn engines limits oxygen availability in the
cylinder, thus decreasing NOx emissions both by lowering peak flame temperature and by
producing a reducing atmosphere
. It is generally applicable to rich-bum engines and, in addition
to simple adjustment of the A/F ratio, requires the installation of a feedback controller so that
changes in load and other operating conditions may be followed
. Additional modification of
turbocharged engines may be necessary
.
Air/fuel ratio adjustment is a well-demonstrated alternative in rich-burn engines and typically
yields 10-40 percent reductions in NOx emissions
. This range is broad in part because a wide
range of existing air/fuel ratios translates into variable scope for emissions reductions using this
technique
.
In lean-bum engines, increasing the A/F ratio decreases NOx emissions
. Extra air dilutes the
combustion gases, thus lowering peak flame temperature and reducing thermal NOx formation
.
29
In order to avoid an engine's capacity being derated, air flow to the engine must be increased at
constant fuel flow, with the result that installation of a turbocharger (or modification of an
existing one) is necessary to implement this technique
. An automatic AN controller also will be
required for variable load operation
.
Air/fuel ratio adjustment is generally applicable to lean-bum engines, although space constraints
may limit the extent to which turbocharger capacity may be increased
. This control method is
most effective on fuel injected engines, in that carbureted engines do not have the same A/F in
each cylinder, thereby limiting changes in this ratio
.
Reductions in lean-bum engine NOx emissions of 5-30 percent are possible by modifying the
A/F ratio
. Achievable emissions reductions are limited by combustion instability and lean
misfire that occur as the lean flammability limit is approached, and by decreased engine
efficiency.
Air/fuel ratio adjustment is not applicable to compression ignition engines .
4.2 Ignition Timing Retard
Ignition timing retard (ITR) lowers NOx emissions by moving the ignition event to later in the
power stroke when the piston has begun to move downward
. Because the combustion chamber
volume is not at its minimum, the peak flame temperature will be reduced, thus reducing thermal
NOx formation .
ITR is applicable to all engines
. It is implemented in spark ignition engines by changing the
timing of the spark, and in compression ignition engines by changing the timing of the fuel
injection
. While timing adjustments are straightforward, replacement of the ignition system with
an electronic ignition control or injecting timing system will provide better performance with
varying engine load and conditions .
30
Emissions reductions attainable using ITR are variable, depending upon the engine design and
operating conditions, and particularly on the air/fuel ratio
. Reductions also are restricted by
limitations on the extent to which ignition may be delayed, in that excess retard results in engine
misfire
. Retard also normally results in decreased fuel efficiency
. For spark ignition engines,
achievable emissions reductions vary from 0-40 percent, and for compression ignition engines,
from 20-30 percent.
ITR results in increased exhaust temperatures, which may result in reduced exhaust valve and
turbocharger life . On diesel engines, it also may result in black smoke
.
4.3 Prestratified Charge
Prestratified charge (PSC) is a technology for injecting fuel and air into the intake manifold in
distinct "slugs", which become separate fuel and air layers upon intake into the cylinders
. This
control alternative thus creates a fuel-rich, easily ignitable mixture around the spark plug and an
overall fuel-lean mixture in the piston
. Combustion occurs at a lower temperature, thereby
producing much less thermal NOx, but without misfire even as
the low flammability limit is
approached.
PSC is applicable to carbureted, spark ignition four-stroke engines
. Engines, which are fuel-
injected or blower-scavenged, cannot use this technique
. Kits for retrofitting prestratified charge
are available for most engines and require installation of new intake manifolds, air hoses and
filters, control valves, and a control system
. Controlled emissions normally are less than 2
g/bhp-hr (140 ppm) on natural-gas-fueled engines, corresponding to emissions reductions of 80-
95 percent.
4.4 Low
Emission Combustion
Low emission combustion (LEC) is the combustion of a very fuel-lean mixture
. Under these
conditions, NOx emissions, as well as
carbon monoxide (CO) and hydrocarbons
(HC), are
severely reduced .
31
Implementation of LEC requires considerable engine modification . Rich-bum engines must be
entirely rebuilt, with addition or replacement of the turbocharger and installation of new air
intake and filtration, carburetor and exhaust systems
. The difficulty of burning very lean
mixtures results in the need to modify the combustion chamber, which implies replacing pistons,
cylinder heads, the ignition system and the intake manifold
. While small cylinder designs that
promote air-fuel mixing are available, precombustion chambers must be installed on larger
engines
. The chambers have 5-10 percent of the cylinder volume and allow ignition of a fuel-
rich mixture that ignites the lean mixture in the cylinder .
The applicability of LEC is somewhat limited
. Conversion kits are not available for all engines
and refitted engines may have degraded load-following capabilities . Achievable controlled
emissions are 1-2 g/bhp-hr (70-140 ppm) for rich-bum engines, which corresponds to an
emissions reduction of 70-90 percent, and 1
.5-3 g/bhp-hr (105-2 10 ppm) for lean-bum spark
ignition engines, or an emissions reduction of about 80-93 percent.
LEC is not effective for diesel engines, but does work for dual-fuel engines, allowing a reduction
in the fraction of diesel oil pilot fuel to 1 percent of the total, and limiting emissions to 1-2
g/bhp-hr (70-140 ppm), a decrease in emissions of 60-80 percent
. Some reductions in exhaust
opacity have been claimed when LEC is implemented on dual-fuel engines
.
4.5 Water/Steam Injection
Water/steam injection lowers peak flame temperatures by providing an inert diluent, thus limiting
thermal NOx formation
. Water maybe injected directly into the turbine combustor, or maybe
converted to steam using turbine exhaust waste heat (with a heat recovery steam generator), and
then injected into the combustor .
More steam than water must be used to achieve a comparable NOx reduction
. However, the use
of steam results in a lower energy penalty than the use of water and may even provide NOx
reductions with no energy penalty if the waste heat used to generate steam would otherwise not
be recovered.
32
Wet injection is applicable to most, if not all, turbines, and has been applied to a large number of
turbines in the United States
. Required equipment, in addition to water/steam injection nozzles,
includes a water treatment system, pumps or a steam generator, metering valves, and controls and
piping
. Untreated water will lead to deposits on turbine blades, lowering efficiency and perhaps
damaging the turbine
. Most turbine manufacturers sell water and steam injection systems
.
Controlled NOx emissions are a function of the amount of water injected and of the fuel/nitrogen
content as
wet injection limits only thermal NOx formation
. For natural gas, controlled
emissions levels of 25-75 ppm are attained with water-to-fuel ratios of about 0
.5 -
1 .5 lb steam
/lb fuel
. (Approximately 1-2 lb steam/lb fuel is needed for equivalent control, given the lower
heat capacity of steam relative to that of water
.) For distillate oil, controlled emissions of 42-
110 ppm are attained with similar water-to-fuel ratios
. These controlled emissions levels
correspond to 60-90 percent emissions reductions
.
The need to increase water-to-fuel ratios for increased emission reductions limits NOx control
capabilities
. High water-to-fuel ratios result in increased hydrocarbon and greatly increased CO
emissions
. Further, because heating injected water consumes energy, turbine fuel efficiency may
decrease
. Wet injection may increase required turbine maintenance
as a result of pressure
oscillations or erosion caused by contaminates in the feed water
.
Finally, the water treatment plant creates wastewater
. This wastewater is enriched approximately
three-fold by the dissolved minerals and pollutants that were in the raw water
.
4.6 Dry Low-NOx Combustors
Dry low-NOx combustors encompass several different technologies
. Lean premixed combustion
is the commercially available technology that affords the largest NOx reductions
. It functions by
providing a large amount of excess air to the combustion chamber, lowering peak temperatures
by dilution
. Air and fuel are premixed in lean premixed combustors to avoid the creation of local
fuel-rich, and therefore high-temperature, regions .
33
While retrofit low-NOx combustors are not available for all turbine models, they have been
installed on many turbines in the U .S
. Lean premixed combustor retrofits face varying
difficulties
. Because lean premixed combustors reduce thermal NOx generation only, they are
less effective on oil-fired than on gas-fired turbines
. Except in the case of silo combustors,
which are external to the turbine body, the retrofits may require some modification of the
combustor section of the turbine
. Water/steam injection provides comparable reductions on oil-
fired turbines without retrofit of low-NOx combustors
.
Controlled emissions levels achievable on gas-fired turbines are on the order of 25-42 ppm . On
some larger turbines, manufacturers are guaranteeing emissions of 9 ppm, and more will
approach this limit with improvements in technology
. These figures correspond to NOx
emissions reductions of 60-95 percent
. Maximum reductions are attained only at high turbine
loads
. Given reduced feel requirements at low loads, premixing would yield air/fuel mixtures
near the lean flammability limit, with resulting flame instability and high CO emissions
. Thus,
lean premixed combustors use diffusion flames at low loads
.
4.7 Non-Selective Catalytic Reduction (NSCR)
Non-selective catalytic reduction (NSCR) uses the three-way catalysts found in automotive
applications to promote the reduction of NOx to nitrogen and water . Exhaust CO and HC are
simultaneously oxidized to carbon dioxide and water in this process
.
NSCR is applicable only to rich-bum engines with exhaust oxygen concentrations below about 1
percent
. Lean-burn engine exhaust will contain insufficient CO and HC for the reduction of the
NOx present
. NSCR retrofits, in addition to the catalyst and catalyst housing, require installation
of an oxygen sensor and feedback controller to maintain an appropriate A/F ratio under variable
load conditions
. Controlled emissions achievable with NSCR are below 1 g/bhp-hr (70 ppm),
corresponding to emissions reductions greater than 90 percent
. NSCR controls are not feasible
for turbines .
10
34
4.8 Selective Catalytic Reduction
The catalyzed reduction of NOx with injected ammonia, referred to as selective catalytic
reduction (SCR), has been implemented on a number of gas, diesel, and dual-fuel engines in the
U.S
. and abroad. SCR is applicable only to lean-bum engines with greater than about one
percent exhaust oxygen, as oxygen is a reagent in the selective reduction reaction
.
Retrofitting SCR involves installation of the reactor and catalyst, appropriate ductwork, an
ammonia storage and distribution system, and a control system for variable load operation
.
Achievable emissions reductions are limited only by the amount of catalyst used, and typically
are on the order of 90 percent, yielding controlled emissions below two gfbhp-hr (140 ppm)
.
Achievable NOx emissions reductions using SCR exceed 90 percent, which corresponds to
controlled emissions below 10 ppm and 25 ppm for many gas-fired and oil-fired turbines
.
4.9 Technical Feasibility of Controls Summary
In summary, there are a number of techniques and control options available for reducing
emissions of NOx from RICE and turbines
. The degree to which these various methods reduce
NOx emissions depends upon the type of engine and the fuel used in the engine
. In their
publication "Controlling NOx Under the Clean Air Act",
10
STAPPA/ALAPCO summarizes the
potential emissions reductions from RICE and turbines
. Tables 4-1 and 4-2 describe the NOx
emissions reductions potential of the various control strategies for reciprocating engines and
turbines .
35
Table 4-1
Potential Emissions Reductions from Reciprocating 1 . C
. Engines
10
Table 4-2
Potential Emissions Reductions from Turbines
10
36
NOx Reduction Potential
(%2
Control
Rich-Burn
Gas SI
Lean-Burn
Gas SI
Diesel Dual Fuel
Air/Fuel Ratio Adjustment
10-40
5-30
N/A
N/A
Ignition Timing Retard
0-40
0-20
20 - 30 20-30
Prestratified Charge
80-90
N/A
N/A
N/A
Low Emission Combustion
70-90
80 - 93
N/A
60-80
Non-selective Catalytic Reduction
90-98
N/A
N/A
N/A
Selective Catalytic Reduction
N/A
90
80 - 90
80-90
Control
Emissions Reduction Potential (%)
Water/Steam injection
70 - 90
Low-NOx Combustors
60-90
Selective Catalytic Reduction
90
5.0
Cost Effectiveness of Controls
The U.S
. EPA has prepared a number of estimates of the cost effectiveness of controlling NOx
emissions from RICE
. The most recent and significant estimates are contained in federal ACT
documents for RICE and turbines ."
9'
a U.S
. EPA's Regulatory Impacts Analysis (RIA) for the
NOx SIP Call and responses to various states' Section 126 Petitions also contained cost estimates
for controlling large RICE . 1 1
The Illinois EPA relied on these documents to estimate the cost
effectiveness of controlling Illinois NOx sources potentially affected by this proposed
rulemaking .
5.1 Cost
Effectiveness of Controls on RICE
Illinois EPA relied on U.S
. EPA's cost estimates from the ACT and NOx SIP Call documents for
RICE.s-'Z
To estimate cost effectiveness of controls, U.S
. EPA considers total capital costs and
total annual costs
. The total capital cost is the sum of the purchased equipment costs, direct
installation costs, indirect installation costs, and contingency costs
.
Annual costs consist of the
direct operating costs of materials and labor for maintenance, operation, utilities, material
replacement and disposal, and indirect operating charges including plant overhead, general
administration, and capital recovery charges
. Cost effectiveness, in dollars/ton of NOx removed,
is calculated for each control technique by dividing the total annual cost by the annual tons of
NOx removed
.
U.S
. EPA's ACT document describes the costs of various NOx controls applicable to
reciprocating RICE
. Depending on the type, size, and operating hours of the engine, the cost
effectiveness of each control varies from a few hundred to several thousands dollars per ton of
NOx removed
. The cost information in the ACT document is reported in 1993 dollars
. The
Illinois EPA used Consumer Price Index (CPI) conversion factor of 0
.765 for 1993 to arrive at
2004 dollars
. Table 5-1 summarizes the cost effectiveness of various control options for engines
equal to or greater than 500 bhp
.
37
Based on the ACT, there are a number of control options available which achieve the control
levels proposed in this rulemaking . The cost effectiveness ranges from $163 to $5,961/ton of
NOx removed, based on the total annual cost divided by total annual NOx reductions .
Table 5-1
Cost Effectiveness for Retrofit of Various NOx Controls Systems s
U.S. EPA's RIAs for the NOx SIP Call and Section 126 Petitions also contain estimates of the
cost effectiveness of NOx controls for large RICE under NOx SIP Call . , 1 The basic approach
used by U.S. EPA in estimating the potential compliance cost of the NOx SIP call to RICE was
to project costs in the absence of the rule ; project costs to comply with the rule ; and then
compare the two sets of costs . The cost to these sources in the absence of the rule is referred to
38
Type of Control
Engine Size
(bhp)
Total Capital
Cost
(Thousands of 2004
dollars)
Cost
Effectiveness
(2004
Nox
dollars/
removed)ton
of
Automatic A/F Control to Rich-Bum SI Engine
.500-8000
14.9-32 .0
567-1,080
Electronic Ignition to Rich-Bum SI Engine
500 -8000
15 .9-32 .0
469-987
A/F + Electronic Ignition to Rich-Bum SI Engine 500- 8000
30.8-63 .9
540-1,065
Prestratified Charge to Rich-Bum SI Engine
500- 8000
66.0-113.5
163-1,712
Prestratified Charge with Turbocharger to Rich-
Bum SI Engine
500- 8000 146 .4-279.7
204-2,026
NSCR to Rich-Bum Engine SI Engine
500- 8000
35.4-330.7
319-1,647
Low Emission Combustion to Medium Speed
Rich-Bum or Lean-Bum SI Engine
500 -8000 15 .6-1,947.7
464-629
Low Emission Combustion to Low Speed Rich-
Burn or Lean-Bum SI Engine
500- 8000 639 .2-4,052.3
991-2,575
Automatic A/F control to Lean-Bum SI Engine
550 - 11000
98.8-169.9
427-2,000
Electronic Ignition to Lean-Burn SI Engine
550
-
11000
15 .9-32 .0
652-1,556
A/F + Electronic Ignition to Lean-Bum SI Engine 550 - 11000
112 .4-197 .4
477-1,961
SCR to Lean-Bum SI engine
550 - 11000 457.5-1,451 .0
641-3,542
Electronic Injection to Diesel Engine
500 -8000
15 .9-101 .8
482-1,012
SCR to Diesel Engine
500- 8000
308.5-1,264.1
899-4,536
Electronic Injection to Dual-Fuel Engine
700 -8000
15 .9-32 .0
627-1,288
SCR to Dual-Fuel Engine
700-8000 333.3-1,264.1 1,165-4,745
Low-Emission Combustion to Dual-Fuel Engine
700 -8000 941 .2-5,228 .8 2,928-5,961
as the 2007 CAA baseline or 2007 base case. Total annual compliance costs and NOx emissions
changes were estimated incremental to the base case
.
The geographic scope of the NOx SIP Call cost effective analyses is the 23 jurisdictions affected
by the NOx SIP Call
. Cost per ton of NOx removed for Illinois sources will be similar. The
analyses provide results for 2007, the year in which all required emissions reduction strategies
are to be fully implemented for units affected by the NOx SIP Call . All results were presented in
1990 dollars.
The potential emission reductions and control costs to RICE and other non-EGU sources affected
by the NOx SIP Call were estimated using a model that is primarily based on data and
assumptions from ACT documents prepared by U
.S
. EPA. For sources not in the trading
program (e.g.,
RICE) the model applies control measures at individual emissions units based on a
cost ceiling calculated in terms of average cost-effectiveness
. The approach for sources outside
the trading program provides estimates of the costs for meeting each state's emissions budget
under a command-and-control scenario.
There are two types of costs incurred with the addition of NOx control technologies
: a one-time
capital cost for new equipment installation and annual operating and maintenance costs
. In
general, economies of scale exist for pollution control technologies for both capital costs and
operating and maintenance costs . Thus, the size of the unit to which controls are applied and the
utilization of the equipment on an annual basis will determine, in part, the cost of implementing
the pollution control(s) .
Table 5-2 summarizes U .S
. EPA's command-and-control analyses for RICE for 5 different cost
ceilings: $1500/ton, $2000/ton, $3000/ton, $4000/ton, and $5000/ton
. The analysis of large
RICE was conducted by selecting the most cost-effective control measure available for each
identified source that does not exceed the cost-effectiveness cut-off specified in the regulatory
alternative. Table 5-2 shows the emissions reductions achieved in the analysis for each
39
regulatory alternative
. Table 5-2 indicates that the alternatives achieve incremental reductions
from the 2007 controlled baseline of roughly 89 percent
.
Table 5-2
2007 Ozone Season NOx Emission Reductions for Large
RICE"
Table 5-3 shows the annual costs and resulting average cost-effectiveness for each of the five
assumed cost ceilings
. All of the regulatory alternatives achieve similar results and all reflect
control measures that meet U .S
. EPA's framework for highly cost-effective ozone season NOx
emission reductions . U.S
. EPA selected the $5000/ton regulatory alternative as the basis for
controlling RICE under the NOx SIP Call since this alternative provides the greatest emission
reduction while being consistent with U .S
. EPA's framework for highly cost-effective ozone
season emissions reduction
. This alternative results in an average reduction of 90 percent from
an uncontrolled 2007 baseline
.
Table 5-3
2007 Cost and Cost-Effectiveness Results for Large
Stationary RICE"
40
Regulatory
Alternative
Annual Control
Cost (million
1990$)
Annual Monitoring
and Administrative
Costs (million 1990$)
Total Annual Costs
(million 1990$)
Ozone Season Cost
Effectiveness
($/ozone season ton)
$1,500/ton
$86.9
$12.4
$99.3
$1,203
$2,000/ton
86.9
13 .3
100.2
1,213
$3,000/ton
86.9
13 .3
100.2
1,213
$4,000/ton
86.9
13 .3
100.2
1,213
$5,000/ton
87.1
13 .3
100.4
1,215
Regulatory
Alternative
Number of
Affected
Sources
2007 Baseline
Emissions
2007 Post-Control
Emissions
2007 Emission
Reductions
$1,500/ton
290
92,424
9,857
82,567
$2,000/ton
304
92,424
9,840
82,584
$3,000/ton
304
92,424
9,840
82,584
$4,000/ton
304
92,424
9,840
82,584
$5,000/ton
304
92,424
9,801
82,623
Based on U.S
. EPA's NOx SIP Call analysis, relying on the chosen regulatory alternative results
in an ozone season cost effectiveness for the large RICE of $1,215 (1990 dollars) per ton of NOx
reduced or $1,756 (adjusted to 2004 dollars) per ton of NOx reduced
.
Another reference document that the Illinois EPA relied upon in the development of this
regulatory proposal is "NOx Emissions and Control Techniques for Stationary Reciprocating
Engines" (published by U.S. EPA 2000).24
It discusses the uncontrolled and controlled levels of
NOx emissions from RICE and the cost effectiveness of LEC . U.S
. EPA obtained information
on LEC costs from several sources
. The total capital cost, annual operating cost, and cost
effectiveness projections in Table 5-4 are based on actual costs for several LEC retrofits obtained
from one engine manufacturer and one third party LEC vendor
. Other inputs include
uncontrolled NOx emissions of 16 .8 g/bhp-hr, controlled emissions of 2.0
g/bhp-hr, and capacity
utilization of 7,000 operating hours per year (prorated for the five months of the ozone season)
.
In most respects, the analysis was conducted according to the methodology of the 1993 ACT
document
. The cost data was reported in 1990 dollars, Illinois EPA adjusted the cost data to
2004 dollars based on the CPI .
Table 5-4
Costs and Cost Effectiveness of LEC Controls In 2004 Dollars
24
41
Engine
Size,
(blip)
Total
Capital
Annual
Cost
NOx Reduction (tons) Cost Effectiveness ($/ton NOx)
Annual 03 Season
Annual
03 Season
80
$231,000
$59,100
9
4
7,730
18,510
240
242,000
61,400
27
11
2,680
6,430
500
259,000
65,200
57
24
1,360
3,270
1,000
293,000
72,400
114
48
750
1,820
2,000
359,000
86,900
228
95
450
1,090
4,000
493,000
116,000
457
190
300
730
6,000
627,000
146,000
685
285
250
610
8,000
760,000
175,000
914
381
230
550
U.S
. EPA's AirControlNET4
.0 model is another reference that Illinois EPA relied to provide cost
data for NOx controls for Illinois RICE
. The AirControlNET model, Version 4 .0, is a control
strategy and costing analysis tool prepared by E .H
. Pechan & Associates, Inc for U.S . EPA,
Office of Air Quality Planning and Standards, RTP, NC
. AirControlNET model was used to
identify the costs of NOx controls for non-utility oil and gas combustion sources in Illinois
.
Table 5-5 shows the AirControlNET costs in 2004 dollars of various NOx combustion controls
available for RICE
.
Table 5-5
AirControlNET Costs of Various NOx Combustion Controls Available for Illinois RICE
5
.2 Cost Effectiveness of Controls on Turbines
Illinois EPA relied on cost data contained in U .S. EPA's ACT9
and AirControlNET for
determining cost effectiveness estimates for control of turbines
. A compilation of control costs
complied by STAPPA/ALAPCO 10
is also summarized here. U.S. EPA's ACT document
reference describes in detail the capital cost and cost effectiveness of various controls for
turbines based on 1990 dollars
. The 1990 dollar estimates have been adjusted to 2004 dollars
throughout this discussion as
described in Section 5 .1
. The cost effectiveness of two types of
controls for smaller turbines of 3
.3 MW varies from $2645 per ton of NOx on an annual basis
removed for steam injection to $3,005 per ton of NOx removed for water injection control
. For
dry low-NOx combustion, cost effectiveness was $1,532 per ton of NOx removed for a four MW
gas-fired turbine.
STAPPA/ALAPCO prepared a document which summarizes the cost of controlling various sizes
of turbines based on the cost information contained in the ACT for the turbines
. The cost
42
Unit Type
Control Type
Cost (2004$ /ton)
Rich Burn RICE-Gas, Diesel,
NSCR
496
Lean Burn RICE-Gas
LEC Medium S eed
724
Lean Bum RICE-Gas
LEC Low S eed
2,436
RICE-Gas, Diesel,
1,116
RICE-Gas
AF + IR
2,276
information in the STAPPA/ALAPCO document
1°
is reported in 1993 dollars
. Table 5-6 shows
the cost effectiveness of controlling 5 to 25 MW turbines operating 8,000 hours annually
.
Table 5-6
Cost Effectiveness for Various NOx Controls Systems for Turbines10
U.S. EPA's AirControlNET4
.0 model was also used to provide cost data for NOx controls for
turbines
. Table 5-7 shows the AirControlNET costs of various NOx combustion controls
available for Illinois RICE and turbines
.
Table 5-7
AirControINET Costs of Various NOx Combustion Controls Available for Turbines
In summary, the Illinois EPA believes that retrofit costs of controlling sources at proposed
levels
will be $496 to $2,436 per ton of NOx reduced for RICE and $712 to $2,189 per ton of NOx
reduced for turbines in 2004 dollars
. It should be recognized that reducing NOx emissions by
combustion controls on RICE and turbines may increase carbon monoxide emissions in some
43
Unit Type
Control Type
Cost (2004$ /ton)
Turbines- N.Gas
Dry Low-NOx
712
Turbines- N.Gas
Steam Injection
1,508
Turbines- N.Gas
Water Injection
2,189
Turbines- Oil
Water Injection
1,870
Type of Control
Turbine
Size
(MW)
Total
Capital Cost
(thousands of 2004
dollars)
Cost Effectiveness
(2004 dollars/ ton of
NOx removed)
Water Injection for Gas-Fired 5-25
711-1,490
902-2,327
Water Injection for Oil-Fired
5-25
745-1,582
732-1,699
Steam Injection for Gas-Fired
5-25
928-2,105
993-2,614
Steam Injection for Oil-Fired
5-25
974-2,261
680-1,699
Low-NOx Combustor for Gas-
Fired
5-25
630-1,438
314-1,046
SCR for Gas-Fired
5-25
748-2,013
1,606-3,203
SCR for Oil-Fired
5-25
748-2,018
1,072-2,039
cases
. Illinois EPA believes that the increases in CO emissions are not significant from an air
quality perspective, but may be high enough to trigger Prevention of Significant Deterioration
(PSD) permitting requirements in some cases .
44
6.0 Existing and Proposed Regulations
6.1 Existing Illinois Regulations
In Part 217 of 35 Illinois Administrative Code, Illinois provides NOx limitations for certain fuel
combustion emission units, such as boilers and certain process emission units which use or
produce nitric acid. Because the Illinois air pollution regulations at 35 Ill . Adm . Code 211 .2470
define "fuel combustion emission units" as boilers, furnaces, and other units that operate by
indirect heat transfer, NOx emissions from reciprocating engines are not regulated in Illinois
since they employ direct heat transfer . Also, pursuant to 35 Ill. Adm. Code 201 .146, RICE of
less than 1,118 kW (1,500 bhp) are currently exempt from permit requirements
. Larger non-
EGU turbines greater than or equal to 250 mmBtu/hr capacities are regulated under 35 Il
. Adm.
Code 217, Subpart U, which is the NOx SIP Call trading program for such units
. Currently, there
is no regulation to control NOx emissions from smaller turbines less than 250 mmBtu/hr
capacities. The owner or operator of any new RICE and turbines is subject to new source review
requirements and must meet any applicable New Source Performance Standards (NSPS) set by
U.S. EPA.
6.2 Other States' Regulations
Tables 6-1 and 6-2 contain summaries of the NOx control requirements in other states
. Several
states have promulgated rules limiting NOx emissions from RICE
. According to the
STAPPA/ALAPCO document 10,
Connecticut, Louisiana, New Jersey, New York, Rhode Island,
and Texas have established NOx limits based on the RACT requirements for NAAs
. Typical
NOx RACT limits are 1 .5 - 3.0 g/bhp-hr (105-210 ppm) for gas-fired rich- and lean-bum
engines, and 8-9 g/bhp-hr (584-660) for oil-fired lean-bum engines . In California, NOx
emissions limits for RICE are based on the BART NOx limits
. NOx limits in California's
Ventura Bay Area County Air Quality Management Districts (AQMD), Santa Barbara County
AQMD, and South Coast AQMD are more stringent than RACT, and are set at 0
.6 -
1
.9 g/bhp-hr
(42 - 133 ppm) for lean-bum engines, 0
.4 - 0.8 g/bhp-hr (28 - 70 ppm) for rich-bum engines, and
1 .1 - 8.4 g/bhp-hr (80-613 ppm) for diesel engines
. The size cut-off for engines to apply controls
varies from 50 bhp to 500 bhp in the states mentioned above .
45
Table 6-1
NOx Control Requirements for RICE in Other States
Note
: 1) NOx SIP Call requires 82 to 90 percent control on large engines that emitted one ton of NOx in any
1995 ozone season day .5
2) 1 g/hp-hr = 73 PPM conversion factor was used to convert g/hp-hr to ppmv at 15 percent 0
2 on a dry
basis.
46
State
Engine Size
Controlled (HP)
Control Level (g/hp-hr)
Gas-fired Rich Burn
Gas-fred Lean Burn
Compression Ignited
Liquid Fired
Texas
13
500 and greater
2 g/hp-hr (146 PPM)
under all operating
conditions
2 g/hp-hr (146 PPM)* at full load, 5
g/hp-hr (365 PPM) at 80-100% load
for new SI or CI dual fuel engines
manufactured after June 18, 1992 ; 5
g/hp-hr for older units at all loads, 8
g/hp-hr (584 PPM) at 80-100% load
11
.
g/hp-hr (803 PPM)
Indiana
14
NOx SIP Call
NOx SIP Call
NOx SIP Call
NOx SIP Call
Connecticut
15
?3 MMBtu/hr
(1175 HP)
2.5 g/hp-hr (183 PPM)
8 g/hp-hr (584 PPM)
Alabama
16
NOx SIP Call NOx SIP Call
NOx SIP Call
NOx SIP Call
New York'
200 HP in Severe
Ozone Area and
400 HP in rest of
State
2 g/hp-hr (146 PPM)
through March 31, 2005
& 1
.5 g/hp-hr (110 PPM)
after April 1, 2005
3 g/hp-hr (220 PPM) through March
31 , 2005 & 1
.5 g hp-hr (110 PPM)
after April 1, 2005
9 g/hp-hr (657 PPM)
through March 31, 2005
& 2.3 g/hp-hr (168 PPM)
after April 1, 2005
New Jerseys
2500 HP
1 .5 g/hp-hr (110 PPM)
2.5 g/hp-hr (182 PPM)
8 g/hp-hr (584 PPM)
Pennsylvania"
153 ton
NOx/Season
1 .5 g/hp-hr (110 PPM)
for >2,400 HP
3 g/hp-hr (220 PPM) for > 2,400 HP
2'3 g/hp-hr (168 PPM)
for >4,400 HP
Maryland20
N.G. Pipeline
engines > 15%
capacity factor
Limits of 300 pound/hr
for a facility with 5 or
less engines, and 566
lb/hr for a facility with
more than 5 engines
Antelope Valley Air
Quality Management
District(AVAQMD)
21
50 HP stationary
and 100 HP for
portable
Electric motor, 36 PPM
for stationary and 80
PPM for portable
Up to 770 PPM for >100
HP but less than 400 HP;
535 PPM for > 400HP
San Joanquin Valley
Unified Air Pollution
Control District
(SJVUAPCD)22
50 HP
50 PPM or 90% red. For
waste gas/field gas
engine and 25 PPM or
96% red . for others
75 PPM or 85% red for two stroke
gaseous fuel < I OOHPfor o
engine and 65
PPM for other
65 PPM or 90%
reduction
El Dorado County Air
Pollution Control
District
(EDCAPCD)23
50 HP
25 PPM to 50 PPM
based on compliance
dates
65 PPM to 125 PPM based on
compliance date
600 PPM to 700 PPM
based on compliance
date
IEPA Proposed
500 HP
150 PPM
210 PPM except 365 for
Worthington engines
660 PPM
Table 6-2
NOx Control Requirements for Turbines in Other States
6.3 Proposed Illinois Regulations
The Illinois EPA considered other states NOx regulations, STAPPA/ALAPCO
recommendations, and U
.S
. EPA guidance documents in its proposal to establish reasonable
levels of NOx controls for reciprocating engines and turbines in Illinois
. Size thresholds for the
units affected by the proposed regulation are based on their PTE for NOx on an annual basis
.
Illinois EPA is proposing to control NOx emissions from sources that have a PTE of 100 TPY or
more of NOx aggregated from all the affected units at the source . The proposed regulation
applies to RICE of 500 bhp capacities and above, and to stationary turbines of capacities equal to
or greater than 3 .5 MW. The proposed regulation does not apply to emergency standby engines
;
engines used in research and testing for the purposes of performance verification and testing of
engines
; engines/turbines regulated under 35 Ill. Adm. Code 217, Subpart W; engines/turbines
47
State
Turbine Size Controlled (HP)
Control Level
Texas"
2500 HP (0.37 MW)
3 g/hp-hr (0 .82 lb/MMbtu) (220 PPM)
Indiana 1°
250 MMBtu/hr (=25 MW)
Budget allowances under NOx Emissions Trading
Program
C
Up to 100 MMBtu/hr (=l0 MW)
55 PPM for Gas-fired, 75 PPM for Oil-fired
< 100 MMBtu/hr
0.9 lb/MMBtu (224 to 245 PPM)
N
210 MMBtu/hr (=1 MW)
RACT, For Simple Cycle 50 PPM for gas, 100
PPM for oil; for combined cycle 42 PPM for gas
and 65 PPM for oil
N
230 MMBtu/hr (=3 MW)
For simple cycle gas-fired 0.2 lb/MMBtu (50
PPM), for oil-fired 0.4 lb/MMBtu (109 PPM) ; for
combined cycle gas-fired 0 .15 lb/MMBtu (37
PPM), and for oil-fired 0 .35 lb/MMBtu (95 PPM)
Maryland20
2Capacity factor 15%
42 PPM for gas burning and 65 PPM for oil
burning
South Coast Air
Quality
Management
District
(SCAQMD)26
20.3 MW
9 PPM to 25 PPM depending on the size and type
IEPA Proposed 23.5 MW
42 for gas-fired and 96 PPM for oil-fired
used for agricultural purpose
; and certain portable engines
. Sources can avoid the proposed
control requirement by staying below source-wide NOx emissions of 100 tpy from all affected
units or if the total operating rate for all affected engines is less than eight million bhp per year
and all affected turbines is less than 20 thousand MW-hr per year
.
Illinois EPA relied upon the U
.S
. EPA's ACT, TSDs for the NOx SIP Call, and
STAPPA/ALAPCO guidance documents
8-12
to propose levels of controls for various types of
units
. All of the proposed controls levels are based on the retrofit techniques available for each
category of affected unit
. From review of the TSDs12'12,22
and the comments received from the
affected sources during outreach, Illinois EPA determined that LEC controls on Worthington
engines can achieve NOx emissions of 308-420 ppmv as compared to other spark-ignited lean
bum engine that can achieve NOx emissions below 210 ppmv
. Therefore, an average limit of
365 ppmv is proposed for Worthington engines
. Although, post-combustion controls, such as
SCR, are available and can achieve the greatest reductions, the proposed control levels do not
require SCR as a compliance method
.
Section 182(f) of the CAA introduced the requirement for existing major stationary sources of
NOx in NAAs to install and operate RACT to control NOx emissions
. The statewide NOx
control levels proposed in this submittal are considered reasonable, attainable, and cost-effective
.
The NOx emissions levels are prescribed in ppmv corrected to 15 percent
02
on a dry basis . The
NOx limits for engines are 150 ppmv for spark-ignited rich-burn, 210 ppmv for spark-ignited
lean-bum, 365 ppmv for Worthington engines and 660 ppmv for diesel engines and for turbines
the NOx limits are 42 ppmv for gas-fired and 96 ppmv for liquid-fired
. An owner or operator
may comply with the control requirements by averaging the emissions of affected units that
commenced operation on or before January 1, 2002, unless the unit is a replacement unit, in
which case such a unit may be included even if it commenced operation after January 1, 2002
.
Compliance with the emission limits will be determined on both an ozone season (May 1, to
September 30) and an annual (January I to December 31) basis each year
. For units included in
an averaging plan, and units using Continuous Emissions Monitoring Systems (CEMS),
compliance with the emission limits must be demonstrated each year
. For all other unites,
48
compliance will be demonstrated on a periodic basis using stack tests and portable monitoring
systems.
Illinois EPA reviewed the U.S. EPA's TSDs
12.22
and determined that most engines and turbines
can reasonably achieve the proposed NOx emission limitations
. However, some engines or
turbines may have difficulty in achieving the proposed limits
. Therefore, Illinois is also
proposing a NOx emissions averaging option to assist sources in complying with the regulations
.
To take advantage of this flexible approach, a company must submit an averaging plan which
lists all of its units that will be included under this option . The total sum of the actual NOx
emissions from each engine or turbine in an averaging plan (based on stack tests results and
annually monitored data) must be less than the total sum of the allowable NOx emissions from
those engine and turbines in the averaging plan based on the respective control level proposed . If
sources, which are using an averaging plan, replace their fuel combusting units with electric
motors, the allowable NOx emissions from the affected units that were replaced should be used
in the averaging calculations and the actual NOx emissions for the electric motors are considered
zero . The allowable NOx emissions from the electric motor is determined by multiplying the
total bhp-hrs generated by the motor (blip rate of motor x operating hours) by the allowable NOx
emission rate of the replaced unit in lbs/mmBtu and converting the pounds of NOx emissions
using the factor of 0 .00077 mmBtu/bhp-hr
. The conversion factor was derived by using a
standard conversion factor of one bhp-hr equals to 2545 .1 Btu and engine thermal efficiency of
33%.
For a replacement unit which is not electric, the allowable NOx emission rate to be used in the
averaging plan prior to its compliance date will be the higher of the applicable uncontrolled NOx
emission rate from the U .S. EPA's AP-42 document or the actual NOx emission rate as
determined by testing or monitoring . On and after the applicable compliance date for the
replacement unit, the allowable NOx emission rate will be the allowable applicable NOx
emission concentration limit specified in the proposed rule .
49
For a unit that is replaced with purchased power, the allowable NOx emission rate will be the
applicable NOx emissions concentration specified in the proposed rule
. The actual hours of
operation to be used will be the annual hours of operation for the replaced unit averaged over the
three-year period prior to the date of purchasing power
. Purchased power units may be included
in an emission averaging plan for no more than five years
.
Tables 6-3
and 6-4
provide examples of how the proposed averaging plan will work
. Table 6-3
shows an example plan which includes four engines and one turbine
. In this example, actual
NOx emissions of 812,965
pounds are greater than the allowable NOx emissions of
804,666
pounds
; therefore, the source is not in compliance with the proposed rule
. Table 6-4
shows that
by adjusting the operating hours of each engine and turbine, the actual NOx emissions of
783,316
pounds, therefore the company achieves compliance without any penalty in fuel consumption and
total bhp-hrs in a year
.
Table 6-3
Example of Averaging Plan-Case
1
Table 6-4
Example of Averaging Plan-Case
2
50
Engines
Rated
bhp
Allow.
NOx
Limit
(PPM)
Actual
NOx
Limit
(PPM)
Fuel Use
(mmBtu/yr)
Hours
of
Oper
.
Bhp-hrs
x10'
Allow. NOx
(lb)
Actual
NOx
(lb)
Engine 1
3,000
150
175
114,750
4,500
15,000
63,410
73,979
Engine 2
3,500
210
220
133,875
4,500
17,500
103,570
108,502
Engine 3
4,000
660
700
156,400
4,600
20,000
401,231
425,548
Engine 4
4,500
210
150
232,475
6,078
22,500
179,851
128,465
Turbine 5
5,361
42
50
227,843
5,000
26,805
35,253
41,968
Total
865,343
24,678 101,805
783,316
778,463
Engines
Rated
bhp
Allow.
NOx
Limit
(PPM)
Actual
NOx
Limit
(PPM)
Fuel Use
(mmBtu/yr)
Hours
of
.
Oper.
Bhp-hrs
x10'
Allow. NOx
(lb)
Actual NOx
(lb)
Engine 1
3,000
150
175
127,500
5,000
15,000
70,456
82,199
Engine 2
3,500
210
220
148,750
5,000
17,500
115,078
120,558
Engine 3
4,000
660
700
170,000
5,000
20,000
436,121
462,553
Engine 4
4,500
210
150
191,250
5,000
22,500
147,958
105,684
Turbine 5
5,361
42
50
227,843
5,000
26,805
35,253
41,968
Total
865,343
25,000 101,805
804,866
812,962
Owners or operators of reciprocating engines impacted by the NOx SIP Call are required to
comply with the proposed rule on or before May 1, 2007 . An owner or operator of any affected
engine not subject to the NOx SIP Call, and affected turbines located in Cook, DuPage, Grundy,
Kane, Kendall, Lake, McHenry, Will, Jersey, Madison, Monroe, Randolph, or St
. Clair counties
(NAA counties) are required to comply with the rule by January 1, 2009
. All affected engines
rated at 1,500 bhp or more and turbines rated at 5 MW (6,702 bhp) or more that are neither
subject to the NOx SIP Call nor located in the NAA counties are required to comply with the rule
on and after January 1, 2011 . All other affected engines rated at 2500 bhp but less than 1,500
bhp and turbines rated z3 .5 MW but less than 5 MW that are neither subject to the NOx SIP Call
nor located in the above mentioned NAA Counties are required to comply with the rule on and
after January 1, 2012. Table 6-5 summarizes the compliance schedule dates for various types of
affected units .
The January 1, 2009 compliance date of the proposed rule was chosen to obtain the greatest
amount of NOx emissions in NAAs in Illinois EPA's efforts to reach attainment by U .S . EPA's
prescribed attainment dates of June 2010 for the new ozone and
PM2.5 NAAQS
. 2s
. 29 (70 FR-
71612) (70 FR 65984)
The January 1, 2011 compliance date of the proposed rule was chosen to further assist in
minimizing transport of NOx emissions into NAAs and thereby improve air quality
. Modeling
by U.S. EPA and LADCO indicates that additional reductions will be necessary to reach
attainment for the ozone and PM2 .5 NAAQS. In addition, outreach discussions with impacted
sources indicates that obtaining control equipment and technical support for installation could
create long delivery time and delays with increased market demands
. These less impacting NOx
sources were given additional compliance times to alleviate the potential equipment backlog for
the larger and more local NOx sources.
Similarly, the January 1, 2012 date was chosen to also allow these smaller NOx sources more
time to comply and alleviate some of the market demand for control equipment and technical
staff for larger and local NOx sources .
51
Table 6-5
Compliance Schedule for Affected Units
The proposed regulations provides for the limited use of CAIR NOx allowances to comply with
the emission limitations
. The use of CAIR NOx allowances are limited to documented
unforeseen or anomalous operating scenarios inconsistent with historical operations for a
particular ozone season or calendar year
. This compliance option can not be used more than
twice in any five-year rolling period and also can not be used by the affected NOx SIP Call units
.
The owner or operator shall surrender one NOx allowance for each ton or portion of a ton of
NOx emissions on an annual basis by which actual emissions exceed allowed emissions
.
An owner or operator of an engine or a turbine subject to the proposed control limits shall
perform a compliance performance test once every five years to demonstrate compliance with the
rule
. For engines subject to the NOx SIP Call, the initial compliance test must be performed by
May 1, 2007
. For all other affected units, an initial compliance test must be performed by the
later of the applicable compliance date or within the first 876 hours of operation
. In addition, all
affected units must be tested once every five years thereafter
. Section 217 .394 of the proposal
provides methods and procedures for testing and monitoring of the performance of an affected
unit
. The test methods provided are approved by the U .S
. EPA as set forth in 40 CFR 60 .
Pursuant to proposed Section 217
.396, an owner or operator of an affected unit is required to
maintain the required records such as, but not limited to
:
•
Records to identify impacted engines, calendar date of records ;
•
Type and quantity of fuel used on a monthly basis,
52
Affected Units
Compliance Date
NOx SIP Call Units
May 1, 2007
RICE and Turbines Located in NAA Counties
January 1, 2009
RICE 21,500 bhp and Turbines 25 MW located in
Attainment Counties
January 1, 2011
All Other RICE 2500 bhp but < 1,500 bhp
and Turbines ?3.5 MW but < 5 MW located in
Attainment Counties
January 1, 2012
• Results of monitoring performed on the affected unit and reported deviations, a log of
inspection and maintenance performed ;
•
Copies of the calculations used to demonstrate compliance with ozone season and annual
control period limits;
•
Number of operating hours, periods of malfunction and repairs ; and
•
Corrective action taken to meet limits or control levels for a period of five years at the
source at which the affected unit is located .
Proposed Section 217 .396 also provides reporting requirements such as, but not limited to
:
•
Notifying the Illinois EPA 30 days and five days prior to testing ;
•
Submitting results of tests to the Illinois EPA within 30 days ;
•
Reporting any monitored exceedances of the applicable NOx concentration ;
•
Amending the applicable permit within 90 days of shutting down the unit
;
•
Notifying the Illinois EPA by October 31 if the averaging plan cannot demonstrate
compliance for any ozone season;
•
Reporting annually by January 30 the total mass of allowable and actual NOx emissions
for the ozone season and annual control period from all affected units in the averaging
plan;
•
Providing annually by January 30 the information required to determine actual NOx
emissions; and
•
Providing annually by January 30 the calculations that demonstrate the total actual NOx
emissions are less than the total allowable NOx emissions .
53
7.0
Potentially Affected Sources
7.1 Sources Affected by the NOx SIP Call
To determine the impacted sources resulting from the NOx SIP Call, the Illinois EPA used the
U.S
. EPA's corrected 1995 base year inventory (March 2, 2000) that contained the NOx
emissions sources for each of the affected states
. A computer search of the corrected 1995 NOx
inventory revealed that there were 28 internal combustion reciprocating engines located in
Illinois that emitted more than one ton of NOx per day during the ozone season in 1995, which is
the applicability level of the NOx SIP Call
. Of these 28 impacted engines, three are located at a
chemical manufacturing company and are used to compress ammonia gas, and 25 are located at
natural gas pipeline facilities to run compressors
. Attachment B to this TSD lists those units
impacted by the NOx SIP Call and specifies the required NOx emissions reductions from each
impacted unit needed to meet the requirements of the NOx SIP Call
.
7.2
Other Potentially Affected Sources
To determine potentially affected engines and turbines besides those impacted by the NOx SIP
Call, the Illinois EPA reviewed its 2004 inventory of RICE and turbines
. Illinois EPA removed
the units that were subject to 35 Ill
. Adm. Code 217, Subpart W, NOx
. regulations for EGU .
Remaining was a total of 1,200 RICE and 205 turbines in 2004 NOx inventory that have the
potential to be affected by the proposed regulations
.
The Illinois EPA estimates that NOx emissions from these potentially affected units in Illinois
were 27,366 TPY and 13,536 tons per ozone season
. The Illinois EPA estimates that of the
1,200 potentially affected RICE in Illinois, 202 RICE would be impacted by the proposed rule
based on 2004 operating rates
. Of the 205 potentially affected gas turbine units, 36 would be
impacted when 2004 operating rates are accounted for
. These estimates are conservative and are
based on the assumption that sources that do not operate more than eight million bhp-hrs in a
year or 20,000 MW-hrs in a year will have their permit revised to limit their operations to take
advantage of exemption levels
. Also, the Illinois EPA based its estimates conservatively by
using the estimated normal operation of the each unit and did not base it on the PTE estimates
54
which would increase the number of impacted sources considerable
. A list of impacted sources
of this proposal is included in the Attachment C to this TSD .
Current Illinois regulations do not require sources to obtain permits to operate RICE with a
capacity of less than 1,500 bhp . Therefore, the Illinois NOx inventory does not include all the
engines from 500 to 1,500 bhp that may be affected by this proposal . To identify potentially
affected sources and to estimate NOx emissions reductions from sources, with smaller engines,
the, the Illinois EPA, with the assistance of the Department of Commerce and Economic
Opportunity (DCEO), conducted a statewide survey of industries and businesses and mailed
10,025 survey forms to determine how many engines in the 500 to 1,500 bhp size range are in
Illinois . Out of 10,025 surveys, only 458 were returned and, of those, only 8 reported having
RICE in the range of 500 to 1500 bhp . Assuming the same proportion of affected engines per
number of responses applies to those that did not respond to the survey, the Illinois EPA
estimates that there are approximately 175 units that have the potential to be affected by the
proposed rule . The Illinois EPA further assumed that many of these units would qualify for
exemptions and therefore, only approximately 44 engines would be impacted by this proposal
.
Table 7-1 summarizes the number of impacted sources of this proposal using this very
conservative methodology .
Table 7-1
Number of Affected Sources
55
Unit Type
Potentially Affected
Impacted
IC Engines 21,500 bhp
1,200
202
Non-EGU Turbines 2
205
36
IC Engines 2500 bhp & < 1,500 bhp
175
44
Total
1,580
282
8.0 NOx Emissions Reductions
8.1
Reductions from Sources Affected by the NOx SIP Call
The Illinois EPA used U.S . EPA's 1995 NOx SIP Call emission inventory to determine NOx
emissions from those sources impacted by the federal rulemaking . Daily NOx emissions from the
impacted units were multiplied by 153 to obtain the ozone season NOx emissions . Since the
NOx SIP Call NOX "budget" was based on the projected 2007 ozone season, the 1995 seasonal
NOx emissions were multiplied by a NOx growth factor for each affected unit to forecast the
2007 ozone season NOx emissions . U.S
. EPA relied on the economic growth projection model
(EGAS) to provide the growth factors for each emission unit for Illinois sources . Total projected
2007 seasonal NOx emissions from these 28 sources were calculated to be 6,618 tons .
The Illinois EPA applied a control efficiency of 82 percent to the 2007 seasonal NOx emissions
to the uncontrolled 2007 seasonal NOx emissions to obtain the 2007 seasonal which is consistent
with U.S
. EPA's modeling to obtain the total 2007 season NOx emissions for affected units . The
required control on these engines will reduce 2007 base emissions by 5,422 tons per season, to a
controlled level of 1,196 tons per season. Attachment B to this TSD identifies the 28 emission
units potentially impacted by the proposed regulation and the required NOx emissions reduction
to comply with NOx SIP Call Phase II requirements . Based on the average uncontrolled level
NOx emission rate of 16 .8 g/bhp-hr as reported in the U .S . EPA's TSD 12 and a controlled NOx
emission rate of 3 g/bhp-hr (210 ppmv), the Illinois EPA's proposal meets the NOx SIP Call
emissions reduction requirement for natural gas-fired RICE .
8.2 Reductions from Other Affected Sources
As described in Section 7 .2, the Illinois EPA estimated that the total 2004 NOx emissions from
the 202 RICE and 36 turbines potentially affected by this proposal to be 19,936 TPY and 8,491
tons per ozone season. The Illinois EPA applied an 82 percent control level to gas-fired engines,
25 percent control efficiency to diesel engines, and 60 percent control efficiency to turbines to
estimate NOx emissions reductions from the proposed rule . No control was applied to a turbine
which is subject to NSPS for NOx emissions . When fully implemented in 2012, the proposed
56
rule will achieve estimated NOx emissions reductions from affected sources (including NOx SIP
Call impacted engines) of 15,199 tons per year and 6,427 tons per ozone season from RICE
greater than 1,500 bhp and turbines greater than 3
.5 MW as shown in Tables 8-1, 8-2 and 8-3 .
Table 8-1
Estimated NOx Emissions Reductions from Affected RICE
Table 8-2
Estimated NOx Emissions Reductions from Affected Turbines
Table 8-3
Estimated NOx Emissions Reductions from
Affected RICE and Turbines
57
Uncontrolled NOx
NOx Emissions Reductions
Year
(tons/yr)
(tons/season)
(tons/yr)
(tons/season)
2009
8,654
3,651
6,515
2,742
2011
17,385
7,420
13,203
5,612
2012
19,936
8,491
15,199
6,427
2012 Small units
3,256
1,357
2,670
1,113
2012 Total
23,192
9,848
17,869
7,540
Uncontrolled NOx
NOx
Emissions Reductions
Year
(tons/yr) (tons/season)
(tons/yr)
(tons/season)
2009
7,874
3,314
6,257
2,634
2011
15,725
6,707
12,415
5,278
2012
18,276
7,777
14,412
6,093
2012 Small units
3,256
1,357
2,670
1,113
2012 Total
21,532
9,134
17,082
7,206
Uncontrolled NOx
NOx Emissions Reductions
Year
(tons/yr) (tons/season)
(tons/yr)
(tons/season)
2009
780
337
259
108
2011
1,524
657
705
300
2012
1,660
714
787
334
To estimate NOx emissions reductions from the smaller RICE, between 500 bhp and 1,500 bhp,
the Illinois EPA assumed the average capacity of the impacted RICE to be 1,000 bhp and the
estimated operating schedule to be 4,000 hours per year
. At a NOx emission rate of 16.8
g/bhp-
hr, the estimated 2004 NOx emissions were determined to be 3,256 tons NOx per year
. At a
control efficiency of 82 percent, the NOx reduction from these engines will be 2,670 TPY and
1,113 tons per ozone season in 2012
. Table 8-1, 8-2, and 8-3 show the estimated NOx emissions
reductions from "small units" with their corresponding total NOx emissions reductions
.
As shown in Table 8-3, this proposal will provide NOx emissions reductions of 17,869 TPY and
7,540 tons per ozone season when fully implemented in 2012
. This equates to a reduction in NOx
emissions of 65 percent on an annual basis and 55 percent during the ozone season from all RICE
and turbines in Illinois
.
58
9.0 Summary
This Technical Support Document presents the rationale, the documentation, and the
methodology relied on by the Illinois EPA in the development of its proposed regulation to
control NOx emissions from reciprocating internal combustion engines (RICE) and turbines
.
NOx emissions are a contributor to fine particulate matter (PM2 .5) and ozone levels in areas of
Illinois that are designated as nonattainment areas (NAAs) for these pollutants . Reciprocating
internal combustion engines and turbines are a source category that accounts for eight percent or
23,347 TPY of total point source NOx emissions in Illinois . The proposed regulation is being
submitted to the Illinois Pollution Control Board to satisfy the requirements of the 2004 NOx SIP
Call Phase II, the CAA Section 110 requirements for NOx RACT on major sources, and
as
a SIP
control strategy to assist Illinois in reaching attainment of the 8-hour ozone and PM2
.
5 NAAQS
.
U.S. EPA's final NOx SIP Call published on April 21, 2004, requires RICE that emit more than
one ton per day of NOx emissions during the ozone season to reduce their NOx emissions by 82
percent for gas-fired and 90 percent for other liquid-fired engines relative to 1995 levels . The
required control level for large non-EGU turbines is 60 percent below their projected 2007
uncontrolled level. This regulatory proposal, if adopted, requires Illinois RICE and turbines
impacted by the NOx SIP Call to comply with the NOx reduction requirements by May 1, 2007,
thereby satisfying this federal obligation .
This proposal is also intended to address the CAA requirement for NOx RACT for RICE and
turbines in 8-hour ozone and PM2 .5 NAAs
. Section 110 of the CAA mandates that the State of
Illinois adopt a SIP containing adequate provisions to assure attainment of the primary and
secondary NAAQS within its boundaries . The proposed regulation requires affected units at a
source with the potential to emit (PTE) 100 tons per year (TPY) of NOx to apply control
technology that is economically reasonable and technologically feasible
. In addition to RICE and
turbine regulations, Illinois EPA is in the process of developing statewide regulations to control
other NOx source categories, as
needed, to satisfy the CAA requirement for NOx RACT.
59
Furthermore, Section 1 10(a)(2)(D) of the CAA prohibits major stationary sources from emitting
air pollutants that prevent any other state from attaining the NAAQS . Sufficient modeling has
been conducted to date, by the U .S. EPA, LADCO, and the Illinois EPA, to justify the Illinois
EPA's proposals to reduce NOx emissions from RICE, turbines, and other NOx emission sources
statewide as part of its overall plan to attain the NAAQS in Illinois and to mitigate any transport
of NOx emissions to downwind states .
In the submitted rule, Illinois EPA is proposing to control NOx emissions statewide from sources
that have a PTE of 100 TPY or more of NOx aggregated from all the affected units at the source .
The proposed regulation applies to RICE of 500 bhp capacities and above, and to stationary
turbines of capacities equal to or greater than 3 .5 MW. The proposed regulation does not apply
to emergency standby engines ; engines used in research and testing for the purposes of
performance verification and testing of engines ; engines/turbines regulated under 35 Ill . Adm.
Code 217, Subpart W ; engines/turbines used for agricultural purposes ; and certain portable
engines
. Sources can avoid the proposed control requirement by staying below source-wide NOx
emission levels of 100 TPY from all affected units or by operating all affected engines less than
eight million brake-hp-hr and all affected turbines less than 20 thousand MW-hr per year .
Staggered compliance dates are proposed in the Illinois rule submittal
. Owners or operators of
reciprocating engines impacted by the NOx SIP Call are required to comply with the proposed
rule by May 1, 2007. An owner or operator of any affected turbine or engine not subject to the
NOx SIP Call and located in an ozone or PM2 . 5 NAA, must comply with the rule by January 1,
2009
. All affected engines rated at 1,500 bhp or more and turbines rated at 5 MW (6,702 bhp) or
more that are neither subject to the NOx SIP Call nor located in the NAA counties are required
to comply with the rule by January 1, 2011 . All other affected engines and turbines are required
to comply with the rule by January 1, 2012 . From outreach discussions, this approach was
recommended to help alleviate anticipated equipment and material delays, as well as demands on
technical staffing needed for installation and testing of new controls, without sacrificing critical
emission reductions .
60
Illinois EPA is also proposing a NOx emissions averaging option to assist sources in complying
with the regulations . To take advantage of this flexible approach, a company must submit an
averaging plan which lists all of its units that will be included under this option . The total sum of
the actual NOx emissions from each engine or turbine in an averaging plan (based on stack tests
results and annually monitored data) must be less than the total sum of the allowable NOx
emissions from those engine and turbines in the averaging plan based on the respective control
level proposed .
The proposed regulations will reduce NOx emissions by 5,422 tons per ozone season in 2007
ozone control season and satisfy the U .S
. EPA's NOx SIP Call Phase II requirements for RICE .
In addition, the proposed regulation will impact approximately 202 RICE (NOx SIP Call engines
included) and 36 turbines in Illinois when fully implemented in 2012 . When fully implemented,
the proposed rule will reduce the statewide NOx emissions from RICE by approximately 17,082
TPY and 7,206 tons per ozone control season at a cost effectiveness of $496 to $2,436 per ton of
NOx (in 2004 dollars). Emissions from gas turbines will be reduced by approximately 787 TPY
and 334 tons per ozone season at a cost effectiveness of $712 to $2,189 per ton of NOx (in 2004
dollars). This equates to 65 percent NOx emissions reduction annually and 55 percent NOx
emissions reduction in the ozone season from the RICE and turbines in Illinois
. From a
perspective of only affected units, the proposed rule, if adopted will result in a 77 percent NOx
emissions reductions annually and seasonally .
61
10.0 References
1 .
National Ambient Air Quality Standards for Ozone, 62 FR 38855, July 18, 1997, (Ozone
Standards)
.
2. National Ambient Air Quality Standards for Particulate Matter, 62
FR 38652, July 18, 1997,
(PM2.5
Standards).
3. The Clean Air Act (CAA), 42 U .S .C. 7401 et seq.
4. Finding of Significant Contribution and Rulemaking for Certain States in the Ozone
Transport Assessment Group Region for Purposes of Reducing Regional Transport of
Ozone; Rule. Part II, Environmental Protection Agency, 63 FR 57356, Tuesday, October 27,
1998 .
5.
Interstate Ozone Transport : Response to Court Decisions on the NOx SIP Call, NOx SIP
Call Technical Amendments, and Section 126 Rules; Final Rule . 69 FR 21603, April 21,
2004.
6. Technical Support Document for Final Clean Air Interstate Rule, Air Quality Modeling, U .S.
EPA, Research Triangle Park, NC, March 2005
.
7. LADCO, Attainment Strategy Options, Draft, October 28, 2005
.
8.
Alternative Control Techniques Document--NOx Emissions from Stationary Reciprocating
Internal Combustion Engines EPA-453/R-93-032, July 1993, U .S. EPA, OAQPS, RTP, NC
27711 .
9. Alternative Control Techniques Document_ NOx Emissions from Stationary Gas Turbines,
EPA-453/R-93-007, January 1993, U .S. EPA, OAQPS, Research Triangle Park, NC 27711
.
10
. Controlling Nitrogen Oxides Under the Clean Air Act
: A Menu of Options, July 1994, State
and Territorial Air Pollution Program Administrators/Association of Local Air Pollution
Control Officials.
11
. Regulatory Impacts Analysis for the NOx SIP Call, FIP, and Section 126 Petitions, Volume
1
: Costs and Economic Impacts, EPA-452/R-98-003, September 1998, U .S. EPA, Office of
Air and Radiation, Washington, DC20460 .
12
. Stationary Reciprocating Internal Combustion Engines Technical Support Document for
NOx SIP Call, October 2003, Doug Grano/Bill Neuffer, EPA, OAR, OAQPS, OPSG
.
13
. Texas Administrative Code. Title 30, Rule 106.512
: Stationary Engines and Turbines .
62
14. Indiana Department of Environmental Management, Office of Air Quality, Section 9 .326
IAC 10-5
. Rule 5 Nitrogen Oxide Reduction Program for Internal Combustion Engines
(ICE).
15. Document Prepared by the State of Connecticut, Department of Environmental Protection
.
Sec. 22a-174-22 Control of Nitrogen Oxides Emissions .
16. Alabama Department of Environmental Management. Air Division, Chapter 335-3-8,
Nitrogen Oxides Emissions
.
17
. New York State, Department of Environmental Conservation Rule and Regulations, Subpart
227.2, Reasonable Available Control Technology (RACT) for Oxides of Nitrogen (NOx) .
18. New Jersey State Department of Environmental Protection, New Jersey Administrative Code
Title 7, Chapter 27, Subchapter 19 : Control and Prohibition of Air Pollution from Oxides of
Nitrogen.
19
. Pennsylvania Department of Environmental Protection, Air Quality Regulations, Small
Source of NOx Cement Kilns and Large Internal Combustion Engines, 25 PA Code CHS
121,129 and 145
.
20. Code of Maryland Regulations . Title 26 Department of the Environment . Subtitle 11 Air
Quality, Chapter 09 : Control of Fuel-Burning Equipment, Stationary Internal Combustion
Engines, and Certain Fuel-Burning Installation .
21 . Antelope Valley Air Quality Management District . Rule 1110.2
: Emissions from Stationary,
Non-Road & Portable Internal Combustion Engines .
22 . San Joaquin Valley Unified Air Pollution Control District Rule 4702
: Internal Combustion
Engines - Phase 2.
23 . El Dorado County Air Pollution Control District Rule 233
: Stationary Internal Combustion
Engines.
24. Stationary Reciprocating Internal Combustion Engines, Updated Information on NOx
Emissions and Control Techniques, Revised Final Report, EPA Contract No
. 68-D-026,
Work Assignment No. 2-28,EC/R Project No. ISD-228, September 1, 2000
.
25
. South Coast Air Quality Management District, Rule 1134 -Emissions of Oxides of
Nitrogen from Stationary Gas Turbines
.
26. Air Quality Designations and Classifications for fine Particles (PM2.5)
National Ambient Air
Quality Standards, 70 FR 943, January 5, 2005 .
63
27. 8-hour Ozone National Ambient Air Quality Standards, 69 FR 23858, April 30, 2004.
28. Final Rule to Implement the 8-Hour Ozone National Ambient Air Quality Standard, 70 FR
71612, November 29, 2005 .
29. Proposed Rule to Implement the fine Particle National Ambient Air Quality Standards, 70
FR 65984, November 1, 2005 .
30. Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air
Interstate Rule)
; Revisions to Acid Rain Program
; Revisions to the NOx SIP Call, 70 FR
25162, May 12, 2005 .
64
Attachment A
Assessment of Regional NOx Emissions in the Upper Midwest
Prepared by the
Lake Michigan Air Directors' Consortium
February 15, 2007
65
Assessment of Regional NOx Emissions in the Upper Midwest
The purpose of this document is to summarize the results of air quality analyses performed by the
Lake Michigan Air Directors Consortium (LADCO) for NOx emissions
. NOx emissions are a
precursor to ozone and PM2
.5 (particulate nitrate) concentrations
. The following sections review
NOx emissions for two base years (2002 and 2005) and three projected future years (2009, 2012,
and 2015), and the effect of NOx emissions on ozone and PM2
.5 concentrations and regional haze
levels
.
NOx Emissions
NOx emissions are summarized by year and source sector for the 5-state LADCO region in
Figure 1, and by state and source sector for 2009 in Figure 2
.
0
aI-
4c
0
wE
2002
2005
2009
2012
2015
Figure 1
. NOx emissions for 5-state LADCO region (tons per day)
IL
o flea
•
On mad
•
o road
•
N ., GU
•
GU
00%
80%
90%
40%
20%
0%
0 Area
•
On-road
•
Nonroad
•
Nun-EGU
•
EGU
IN
M
OH
WI
IL
IN
M
OH
WI
Figure 2
. NOx emissions by state for 2009
-
absolute amounts (left) and percentages (right)
Mobile sources (on-road and off-road) make-up the largest source sector
: about 60% of the
regional emissions in the base years (2002, 2005) and future years (2009, 2012, 2015)
. NOx
emissions from on-road sources will decrease by almost 40% between 2002 and 2009 due to
federal motor vehicle control programs .
Point sources (EGUs and non-EGUs) make-up the next largest source sector
: about 35% of the
regional emissions in the base years and future years
. EGU emissions will decrease by more than
66
60% between 2002 and 2009 due to the NOx SIP Call and CAIR . Nevertheless, EGUs still
make-up 20% of the regional emissions in the future years . Non-EGUs make-up 15% of the
regional emissions in the future years. Important non-EGU source categories include ICI boilers
(5% of the regional emissions), IC engines (3%), cement manufacturing (1
.3%), metal production
(1 .3%), and petroleum refineries (1%)
.
Area sources make-up a small percentage of the regional NOx emissions : less than 5% .
The absolute amount of NOx emissions varies by state, although the relative percentage of each
source sector is similar, except for Indiana . (Note, there is a higher percentage of point source
NOx emissions in Indiana, compared to the other four LADCO States .)
Ozone
A photochemical grid model (CAMx) was applied to provide source contribution information
.
Specifically, the model estimated the impact of 18 geographic source regions (which are
identified in Figure 3) and 6 source sectors (EGU point, non-EGU point, on-road, off-road, area,
and biogenic sources) at each ozone monitoring site in the region .
Figure 3
. Source regions (left) and key monitoring sites (right) for ozone modeling analysis
Modeling results for 2012 (with "on the books" controls) are provided in Figure 4 for several key
monitoring sites . For each monitoring site, there are two graphs
: one showing sector-level
contributions, and one showing source region and sector-level contributions in terms of
percentages
. (Note, in the sector-level graph, the contribution from NOx emissions are shown in
blue, and from VOC emissions in green
. For EGUs, several higher emitting facilities were
tracked individually and their collective contribution is shown as the red portion of the EGU bar
.)
The sector-level results show that on-road and nonroad NOx emissions generally have the largest
contributions at the key monitor locations (> 15% each)
. EGU and non-EGU NOx emissions are
also important contributors (> 10% each)
. The source group contributions vary by receptor
67
location due to emissions inventory differences . The source region results show that nearby
emissions generally have the highest impacts (e.g., the Chicago nonattainment area contributes
25-40% in the Lake Michigan area, and Cleveland nonattainment counties and other Ohio
counties contribute 20 - 30% and about 15%, respectively, in northeastern Ohio) .
68
5B
45
M - Cook : (V03E10321) K2012R4Sb_APCA nopig
Biog
ECU ran=CU
mr
onroad
Scbr
WI - Kamska : (5505900191) K2012R4S1 APCA_nopyg
Slog
oontb
VOC
BC - T0P529GU,
mntrb _
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Indiana
∎ 1
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d
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f 1
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69
0
IL
-
Cook : (T203U0321) K20RR4SL AICA aopig
.cbr
-
Biog -
ECU
nonECU
onro.d -
.w. -
BC
A¢
.nt
WI - Kanosba : (5505900191) K2012R4SU APCA_mplg
.cloy
_
Brag -
PGU _ nonELU
- onro.d
BC
m4x
_
Slog -
- nonsCU
of my
onro.d -
ma -
BC
SD
I rnnl
Figure 4a Model-based ozone source apportionment results for sites in the Lake Michigan area
- Cook
County, IL (top), Kenosha County, WI (middle), and Door County, WI (bottom)
C
C~n,n 1
K I nd igc
35
Indiana
Bonn
∎ 1
Vncow;
IN
30
BI Cbi NA r9
111
∎
5
Id Ca NA
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U
∎ W
D
IS
bboil NA
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20
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MI - Macanb : (2609900091) K2012R4Sb_APCA - mpig
r
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MI -
A1legan : (2600500031) K2012R4S1 AICA -nopig
conblb _
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o
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(2600500031) K20RR4S1 AICA nopig
.actor
Biog
-
ECU - nonEGU
. onrod -
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off me
33
N .nt
MI -
Macamb : (2609900091) K2012R4SbAPCA nopig
.actor _ Biog - ECU _ nonECU
..
g- I
anroad _
ms -
BC
I
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0
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H - Geaoge : (3905500041) K2012R45t APCA nopig
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alas -
PC
I'll .,
1 .11-1
1
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EGU oonECV dy-m. onroed
n
1C
20
40
50
Sector
Figure 4b
. Model-based ozone source apportionment results for Holland, MI (top), Detroit, MI (middle), and
Cleveland, OH (bottom)
MO - St.Ch bs :
(291831I102t K2012R4Sb_APCA nopig
B'og
wndb -
NOX
VOC
BC - TOP52 ECt7.
EGO nonHGII
o f me enrol
Scbr
IN - Hamiioo :
(180571001) K2012R4Sb_APCA_oapig
wntnb -
NO%
VOC
BC - T 52 ECU
non6U off my
onrod
Scbr
OH -
Hamilton : (39060006
; K2012R4Sb_A1CA nopig
womb -
HO%
VOC
-
BC -
IOP52 ECIb
q
MfichignOhio
VOINOW1
Indian ~~
Olin . II
Wwonitn I
Ill Oh' NA I
IM Chi NA
Wu
NA
Detroit NA
Clew NA
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S"II
VISTASWSTM
II
∎ ∎
MANE-VU I
a2
-1 t1
IA-MW II
Cnm .
BC
Sing
nonEGU
mr onrod
BC
Sctor
Figure 4c
. Model-based ozone source apportionment results for St
. Louis, MO (top), Indianapolis, IN
(middle), and
Cincinnati,
OH (bottom)
71
MO - St.Cbaybs :
(291831002 ; K2012R4S1 APCA
.Plg
B'cg -
ECU
nanBGU
off me
no
mad _
.. . -
BC
Pmnl
OH .- Hamilton
: (3906111006 ; K2012R4Sb_APCA_nOpig
Be
01
P c.ni
IN - Hamilton .
(18057100Th K2012R4Sk_AICA_nopig
SO
BO
nctar -
Biag -
HCU
_nECU
o8 me
omvd -
site -
BC
ON. MI ∎
Mohyn
Indian.
UN- . 11
W, . ,n
N Chi NA
LN_Chi NA
W _NA
Detroit NA
On_NA
Kentucky
I
WwtMrgin'.
-
∎
-oun
VISTAS
II
I
MANE-VU
! -
B?FAP WBAP
IA MN
C-de
BC
111II
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BC
0
w
tO
wgion
Omo
Mchign
Indiana I
WiconIllinoi
.
IOW
III Chi NA
lad_Chi
_NA
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b
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Minour
MAT1E-WVISTAS
∎ ∎
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.
BC
PM2.5
PM2.5
is comprised of several chemical species, including ammonium sulfate, ammonium
nitrate, organic carbon, elemental carbon, and soil
. NOx emissions contribute to the formation of
ammonium nitrate
. Figure 5 shows the chemical composition of PM2
.5 across the region .
Ammonium nitrate concentrations are greater in northern cities
(e.g.,
Chicago and Detroit)
compared to more southern cities
(e.g., St. Louis).
Figure S. PM2.5
chemical composition in the LADCO region
- 2004 data
A photochemical grid model (CAMx) was applied to provide source contribution information
.
Specifically, the model estimated the impact of 18 geographic source regions (which are
identified in Figure 6) and 6 source sectors (EGU point, non-EGU point, on-road, off-road, area,
and ammonia sources) at each PM2.5
monitoring site in the region
.
AO
Detroit
A County
l
Pr
SIeuGenville
Cincinnati
Granite Cit
Figure 6
. Source regions (left) and key monitoring sites
(right) for
A^
PMz 5 modeling analysis
72
Modeling results for 2012 (with "on the books" controls) are provided in Figure 7 for several key
monitoring sites in the region. For each monitoring site, there are two graphs
: one showing
species- and sector-level contributions, and one showing source region and species-level
contributions in terms of absolute modeled values .
The species- and sector-level results show that on-road and nonroad NOx emissions generally
have the largest contributions to nitrate concentrations . EGU and non-EGU NOx emissions are
also important contributors . The source group contributions vary by receptor location due to
emissions inventory differences.
The source region results show that emissions from nearby/local sources are large contributors to
PM2.5 concentrations . There is also a sizable regional contribution .
73
IL - Caok
: (370311052) K20IIR4SU
Spd.e
I. - Madison : (2718167) K20I2R4Sb
BCU
nanE
auud
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-
nh3
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nB my
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MI - VAyne : (18630033) K20IIR4St
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S04
NH4 - NO3 _ Ikx -
BC _ F81M _ BC
R. - Cmk : (170317052) K2012R4St
74
Connnlntiion Iudm3)
Figure 7a
. Model-based PM2
.5 source apportionment results for sites in Chicago, IL (top), Granite
City, IL (middle), and Detroit, MI (bottom)
CI:MAP_WAAPN-0-MAIM-VUndChi
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-
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aead - - BC _ AMA
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peal NA
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75
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(390350038) K20RR4Sb
I
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OH - Hamilton : (39061I)0N) K2022R1Sh
104
MN
-
NO3
-
FOC - BC
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5 CS
- K.7
u/..3
a
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a
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Figure 7b
. Model-based PMLS source apportionment results for Cleveland, OH (top), Cincinnati, OH
(middle), and Steubenviile, OH (bottom)
Regional Haze
A photochemical grid model (CAMx) was applied to provide source contribution information .
Specifically, the model estimated the impact of 18 geographic source regions (which are
identified in Figure 8) and 6 source sectors (EGU point, non-EGU point, on-road, off-road, area,
and ammonia sources) at each visibility/haze monitoring site in the region .
76
canoe pea (VU)
•
Isle Ro}al(NP)
Figure 8. Source regions (left) and key monitoring sites (right) for haze modeling analysis
Modeling results for 2018 (with "on the books" controls) are provided in Figure 9 for three key
monitoring sites (Class I areas) in and near the region . For each monitoring site, there are two
graphs: one showing species- and sector-level contributions, and one showing source region and
species-level contributions in terms of absolute modeled values .
The species- and sector-level results show that on-road and nonroad NOx emissions generally
have the largest contributions to nitrate concentrations . EGU and non-EGU NOx emissions are
also important contributors
. The source group contributions vary by receptor location due to
emissions inventory differences .
The source region results show that emissions from a number of nearby states contribute to
regional haze levels .
s-cin
SBNES -
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904
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MK NO3 I t S FWM
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.
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D
.troit NA
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6ntucky
Rmuyly nis
k4now
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bxa
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C-BC
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wchi
Indian
a
.n
Illinois
we
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t.
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DNroit NA
v Imrginis
TNUCky
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P WRAP
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n
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5
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PPBM A90A BSOA tB 0
0
5
10
15
OJ
35
30
35
b
Spans
Extinction (1'Mm)
Figure 9
. Model-based regional haze source apportionment results for Boundary Waters, MN (top),
Seney, MI (middle), and Mammoth Cave, KY (bottom)
cookie
804
NH - W3
- -POX - HE
Mio
hOchSin
Indian.
M
i
~/
w nlninoisnmin
∎
MinnMinn SIRW
D.Dolt NA
WYMiginia
ISntucky
I
IANR4~°
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Canada
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I
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10
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BAM ASOA BSOA TOP30
Summary
This document provides information on sources of NOx emissions and the effect of NOx
emissions on ozone and PM2.5
concentrations and regional haze levels
. Several key findings
should be noted
:
•
Mobile sources make-up about 60% of the regional 2009/2012 NOx emissions
.
LADCO's contractor is evaluating candidate NOx control measures for on-road
and nonroad sources
. The preliminary results indicate several concerns for these
control measures
: (a) relatively small reductions
(i.e.,
an example scenario
analysis showed only about a 3-4% reduction in mobile source NOx emissions),
(b) uncertain effectiveness
(i.e.,
many control programs are voluntary), and (c)
high costs (i.e.,
the example scenario analysis costs exceed several billion dollars)
.
•
Point sources (EGUs and non-EGUs) make-up about 35% of the 2009/2012 NOx
emissions
. Even though EGU emissions will decrease dramatically due to the
NOx SIP Call and CAIR, EGUs still make-up 20% of the regional 2009/2012
NOx emissions
. Furthermore, a significant percentage of the power generation in
the region is expected to reflect only limited (combustion) controls
. Application
of more advanced controls
(e.g.,
SNCR or SCR), which are proven technologies,
can achieve further reductions in EGU NOx emissions
•
Non-EGUs make-up 15% of the regional 2009/2012 NOx emissions
. Important
source categories include ICI boilers (5% of the regional 2009/2012 NOx
emissions), IC engines
(3%),
cement manufacturing (1 .3%),
metal production
(1
.3%), and petroleum refineries (1%) .
For these source categories, there are
known control technologies which can achieve reductions in NOx emissions from
several dozen units with either no controls or only limited (combustion) controls
.
78
Attachment B
List of Sources Affected by the NOx SIP Call
79
List of Sources Affected byy the NOx SIP Call
80
Plant ID
Plant Name
Point ID
Segment Description of the Unit
NOx
Reduction
(Tons/season)
027807AAC
NATURAL GAS
PIPELINE CO . OF
AMERICA 8310
730103540041
1
Engine 10-Eng
176
041804AAC
PANHANDLE EASTERN
PIPELINE
73010573009
9
Engine 1213
173
041804AAC
PANHANDLE EASTERN
PIPELINE
73010573010
10
Engine 1214
167
041804AAC
PANHANDLE EASTERN
PIPELINE
73010573011
11
Engine 1215
153
041804AAC
PANHANDLE EASTERN
PIPELINE
73010573012
12
Engine 1216
169
041804AAC
PANHANDLE EASTERN
PIPELINE
73010573013
13
Engine 1217
171
073816AAA
NATURAL GAS
PIPELINE CO OF
AMERICA
851000140011
1
Engine # 12
209
073816AAA
NATURAL GAS
PIPELINE CO OF
AMERICA
851000140012
2
Engine # 13
211
073816AAA
NATURAL GAS
PIPELINE CO OF
AMERICA
851000140013
3
Engine # 14
211
073816AAA
NATURAL GAS
PIPELINE CO OF
AMERICA
851000140014
Engine # 15
195
073816AAA
NATURAL GAS
PIPELINE CO OF
AMERICA
851000140041
1
Engine # 9
141
073816AAA
NATURAL GAS
PIPELINE CO OF
AMERICA
851000140051
1
Engine # 10
261
085809AAA
ROYSTER-CLARK
NITROGEN
730700330101
1
Clark Compressor C-02A
242
085809AAA
ROYSTER-CLARK
NITROGEN
730700330102
2
Clark Compressor C-02B
242
085809AAA
ROYSTER-CLARK
NITROGEN
730700330103
3
Clark Compressor C-02C
242
093802AAF
ANR PIPELINE CO
E-108
I
Engine E-1008
215
113817AAA NICOR GAS
730105440021
1
Engine EC21
149
113817AAA NICOR GAS
730105440031
1
Engine IC1 1
299
113821AAA NICOR GAS
730105430021
Compressor EC21
317
113821AAA NICOR GAS
730105430051
1
Compressor CC22
211
149820AAB
PANHANDLE EASTERN
PIPELINE
7301057199G
3
Engine 1014
159
81
149820AAB
PANHANDLE EASTERN
PIPELINE
73010571991
1
Engine 1015
172
149820AAB
PANHANDLE EASTERN
PIPELINE
7301057199J
1
Engine 1016
172
149820AAB
PANHANDLE EASTERN
PIPELINE
7301057199K
I
Engine 1017
169
167801AAA
PANHANDLE EASTERN
PIPELINE
87090038001
1
Engine 1015
152
167801AAA
PANHANDLE EASTERN
PIPELINE
87090038002
1
Engine 1016
166
167801AAA
PANHANDLE EASTERN
PIPELINE
87090038004
1
Engine 1017
124
167801AAA
PANHANDLE EASTERN
PIPELINE
87090038005
1
Engine 1018
154
Total
5,422
Attachment C
List of Impacted RICE
82
List of Impacted RICE
83
Plant ID
Plant Name
Emission
Point
No. of
Units
091811AAB
Natural Gas Pipeline Co of America
0038
2
091811AAB
Natural Gas Pipeline Co of America
0005
1
093802AAF
ANR Pipeline Co
0003
1
127855AAB
Trunkline Gas Co
0004
1
191803AAA
Trunkline Gas Co
0010
1
0316000EV
University of Illinois At Chicago
0009
1
073816AAA
Natural Gas Pipeline Company of America
0015
1
I47802AAB
Natural Gas Pipeline of America
0002
2
027807AAC
Natural Gas Pipeline Co of America
0003
1
027807AAC
Natural Gas Pipeline Co of America
0010
1
085809AAA
Royster Clark
0010
3
127855AAB
Trunkline Gas Co
0008
1
091811AAB
Natural Gas Pipeline Co of America
0034
1
093802AAF
ANR Pipeline Co
0004
1
141050AAV
Rochelle Municipal Diesel Plant
0003
1
141050AAV
Rochelle Municipal Diesel Plant
0012
1
0316000EV
University of Illinois At Chicago
0011
2
073816AAA
Natural Gas Pipeline Company of America
0001
4
073816AAA
Natural Gas Pipeline Company of America
0004
1
113817AAA
Nicor Gas
0002
1
127855AAB
Trunkline Gas Co
0005
1
113821AAA
NicorGas
0002
1
113821AAA
Nicor Gas
0005
1
113817AAA
Nicor Gas
0001
1
167801AAA
Panhandle Eastern Pipe Line Co
0001
2
105822AAD
Nicor Gas
0017
1
197800ABU
Trunkline Gas Co
0001
5
149820AAB
Panhandle Eastern Pipe Line Co
0003
1
027807AAC
Natural Gas Pipeline Co of America
0001
6
027807AAC
Natural Gas Pipeline Co of America
0002
1
149820AAB
Panhandle Eastern Pipe Line Co
0006
1
I49820AAB
Panhandle Eastern Pipe Line Co
0007
1
041804AAC
Panhandle Eastern Pipe Line Co
0014
1
041804AAC
Panhandle Eastern Pipe Line Co
0013
1
041804AAC
Panhandle Eastern Pipe Line Co
0015
1
141050AAV
Rochelle Municipal Diesel Plant
0011
1
141050AAV
Rochelle Municipal Diesel Plant
0001
1
141050AAV
Rochelle Municipal Diesel Plant
0002
1
105822AAD
Nicor Gas
0028
3
147802AAB
Natural Gas Pipeline of America
0001
7
041804AAC
Panhandle Eastern Pipe Line Co
0012
1
041804AAC
Panhandle Eastern Pipe Line Co
0011
1
127855AAB
Trunkline Gas Co
0003
2
041808AAF
Trunkline Gas Co
0001
1
191803AAA
Trunkline Gas Co
0007
1
84
191803AAA
Trunkline Gas Co
0006
1
191803AAA
Trunkline Gas Co
0005
1
191803AAA
Trunkline Gas Co
0004
1
113821AAA
Nicor Gas
0001
1
197809ACP
KMS Joliet Power Partners LP
0001
4
105818AAA
Nicor Gas
0005
1
I49820AAB
Panhandle Eastern Pipe Line Co
0002
2
127855AAB
Trunkline Gas Co
0001
3
073815AAC
ANR Pipeline Co
0007
1
191803AAA
Trunkline Gas Co
0001
1
191803AAA
Trunkline Gas Co
0003
1
191803AAA
Trunkline Gas Co
0002
1
149820AAB
Panhandle Eastern Pipe Line Co
0001
6
041804AAC
Panhandle Eastern Pipe Line Co
0010
1
041804AAC
Panhandle Eastern Pipe Line Co
0008
1
041804AAC
Panhandle Eastern Pipe Line Co
0009
1
041804AAC
Panhandle Eastern Pipe Line Co
0006
1
041804AAC
Panhandle Eastern Pipe Line Co
0007
1
041801 AAB
Natural Gas Pipeline Co Station 203
0004
1
019065AAN
Rantoul Electric Generating Plant
0010
8
041808AAF
Trunkline Gas Co
0002
4
105818AAA
Nicor Gas
0001
1
041804AAC
Panhandle Eastern Pipe Line Co
0002
1
167801AAA
Panhandle Eastern Pipe Line Co
0008
2
I05060AAI
Caterpillar Inc
0021
1
041808AAF
Trunkline Gas Co
0003
2
073815AAC
ANR Pipeline Co
0002
1
073815AAC
ANR Pipeline Co
0001
1
073815AAC
ANR Pipeline Co
0006
1
073815AAC
ANR Pipeline Co
0004
1
073815AAC
ANR Pipeline Co
0003
1
019065AAN
Rantoul Electric Generating Plant
0011
8
073815AAC
ANR Pipeline Co
0008
1
105822AAD
Nicor Gas
0029
2
093802AAF
ANR Pipeline Co
0002
1
105818AAA
Nicor Gas
0018
1
093802AAF
ANR Pipeline Co
0001
2
137867AAA
Panhandle Eastern Pipeline Co
0005
1
0316000EV
University of Illinois At Chicago
0010
1
113817AAA
Nicor Gas
0003
1
105822AAD
Nicor Gas
0019
1
141050AAV
Rochelle Municipal Diesel Plant
0006
1
141050AAV
Rochelle Municipal Diesel Plant
0008
1
105818AAA
Nicor Gas
0017
1
105060AAI
Caterpillar Inc
0030
3
137867AAA
Panhandle Eastern Pipeline Co
0006
1
167801AAA
Panhandle Eastern Pipe Line Co
0002
3
019813AAA
Peoples Gas Light & Coke Co
0070
4
141050AAV
Rochelle Municipal Diesel Plant
0004
1
85
137867AAA
Panhandle Eastern Pipeline Co
0004
2
051808AAB
Natural Gas Pipeline Co
0018
2
043065ADG
Nicor Gas
0003
4
051808AAB
Natural Gas Pipeline Co
0021
1
091811AAB
Natural Gas Pipeline Co of America
0040
1
091811AAB
Natural Gas Pipeline Co of America
0048
5
I37867AAA
Panhandle Eastern Pipeline Co
0003
2
105060AAI
Caterpillar Inc
0031
1
095020ABS
Archer Daniels Midland Co
0028
6
09181 IAAB
Natural Gas Pipeline Co of America
0047
4
105822AAD
Nicor Gas
0018
1
051808AAB
Natural Gas Pipeline Co
0020
1
051808AAB
Natural Gas Pipeline Co
0019
1
0198I3AAA
Peoples Gas Light & Coke Co
0071
2
093802AAF
ANR Pipeline Co
0014
1
041801AAB
Natural Gas Pipeline Co Station 203
0006
3
091811AAB
Natural Gas Pipeline Co of America
0028
2
105822AAD
Nicor Gas
0020
1
105822AAD
Nicor Gas
0022
1
105822AAD
Nicor Gas
0023
1
Total Engines
202
List of Impacted Turbines
86
Plant ID
Plant Name
Emission
Point
No. of
Units
143065AJE
Archer Daniels Midland Co
0027
2
019010ADA
University of Illinois
0042
2
031003ADA
Alsip Paper Condominium Assn
0002
1
043801AAJ
Gas Recovery Services of Illinois, Inc
0001
3
143810AAG
Ameren Energy Medina Valley Cogen LLC
0001
3
197817AAA
Natural Gas Pipeline Co of America
0020
1
0316000KE
Calumet Peaking Facility
0001
8
197899AAC
PPL University Park LLC
0001
1
197899AAC
PPL University Park LLC
0002
1
197899AAC
PPL University Park LLC
0003
1
197899AAC
PPL University Park LLC
0004
1
197899AAC
PPL University Park LLC
0005
197899AAC
PPL University Park LLC
0006
1
197899AAC
PPL University Park LLC
0007
1
197899AAC
PPL University Park LLC
0008
1
197899AAC
PPL University Park LLC
0009
1
197899AAC
PPL University Park LLC
0010
1
197899AAC
PPL University Park LLC
0011
1
197899AAC
PPL University Park LLC
0012
1
043801AAJ
Gas Recovery Services of Illinois, Inc
0002
1
197800AAA
Exxon Mobil
0043
1
085809AAG
Northern Natural Gas Co
0001
1
085809AAG
Northern Natural Gas Co
0002
1
Total Turbines
36
