PURPOSE: This proposed rulemaking will remove all
sources from the current Table I because the sulfur dioxide
(SO2) emission limits are included in other legally
binding documents (e.g., Construction Permits, Consent Agreements, etc.) and/or
emission limits are no longer necessary to comply with the 2010 1-hour
SO2 National Ambient Air Quality Standard (NAAQS). As a
result, the current Table I will be removed in its entirety, and Table II will
now be the new Table I. This proposed rulemaking will also add City Utilities
of Springfield - James River Plant, to the new Table I list of affected
SO2 sources in the rule, codifying units #1 through #5
are using natural gas exclusively. An exemption will be added to subsection
(1)(A) for units burning ultra low sulfur distillate fuel with a maximum fuel
content of fifteen (15) parts per million (ppm). Subsection (3)(D) requiring
sources in Jackson and Jefferson counties to use ultra-low sulfur distillate
fuel oil will be eliminated since it is not required by a federally approved
plan for nonattainment areas. The new Table I will be updated to more clearly
state that only indirect heating units are subject to the table emission
limits. The table in subsection (3)(C) will be replaced with a new table that
specifies state areas and specific dates to clarify the terms "existing" and
"new" in the old table, adding clarity by providing the necessary information
in the table. Additionally, subsection (5)(A) will be revised to reference
10 CSR
10-6.030, offering a single location to determine
applicable test methods. The evidence supporting the need for this proposed
rulemaking, per 536.016, RSMo, is Executive Order 17-03 Red Tape Reduction
Review and related comments.
PURPOSE: This rule establishes requirements for
emission units emitting sulfur dioxide (SO2). These
requirements maintain existing SO2 regulatory
requirements previously found in
10 CSR
10-6.260 that were in place prior to the establishment
of the June 22, 2010, one (1)-hour SO2 National Ambient
Air Quality Standards (NAAQS). The rule consolidates, streamlines, and updates
existing regulatory requirements in accordance with 536.175,
RSMo.
(1) Applicability. This
rule applies to any source that emits sulfur dioxide
(SO
2). The following exceptions apply to any source not
listed in Table I of this rule. Upon request of the director, owners or
operators must furnish the director information to confirm that an exception
criterion is met.
(A) Individual units fueled
exclusively with natural gas (as defined in
40
CFR
72.2) , liquefied petroleum gas as
defined by American Society for Testing and Materials (ASTM) International,
ultra-low sulfur distillate fuel oil with a maximum fuel sulfur content of
fifteen (15) ppm, or any combination of these fuels as of December 31, 2016,
and this exception is determined by complying with the record keeping
requirements in section (4) of this rule;
(B) Individual indirect heating units with a
rated capacity less than or equal to three hundred fifty thousand British
thermal units (350,000 Btus) per hour actual heat input; or
(C) Individual units subject to a more
restrictive SO
2 emission limit or more restrictive fuel
sulfur content limit under -
2. Any federally enforceable
permit.
(2)
Definitions. Definitions of certain terms specified in this rule may be found
in
10 CSR
10-6.020.
(3) General Provisions.
(A) SO
2 Emission
Limits. Owners or operators of sources and/or units listed in Table I of this
rule must limit their SO
2 emissions as specified.
Table I- Sources subject to SO2
emission limits
|
Source
|
Source ID
|
Emission Limit per Source (Pounds
SO2 per Million Btus Actual Heat Input)*
|
Averaging Time
|
|
Associated Electric Coop, Inc. - Chamois Plant
|
1510002
|
6.7
|
3 hours
|
|
City Utilities of Springfield - James River Plant
(Boilers #1 through #5)
|
0770005
|
Natural Gas
|
N.A.
|
|
Empire District Electric Company - Asbury
Plant
|
0970001
|
12.0
|
3 hours
|
|
New Madrid Power Plant - Marston
|
1430004
|
10.0
|
3 hours
|
|
Thomas Hill Energy Center Power Division - Thomas
Hill
|
1750001
|
8.0
|
3 hours
|
|
University of Missouri
(MU) - Columbia Power Plant
|
0190004
|
8.0
|
3 hours
|
|
Kansas City Power and Light Co. - Montrose Generating
Station
|
0830001
|
3.9
|
24 hours
|
|
Ameren Missouri - Sioux Plant
|
1830001
|
4.8
|
Daily average, 00:01 to 24:00
|
|
Doe Run Company - Buick Resource Recycling
Facility
|
0930009
|
8,650 pounds SO2/hr
|
1 -hour test repeated 3 times
|
*Applies to indirect heating units only.
(B) Owners or operators of indirect heating
sources with a total capacity, excluding exempt units, greater than three
hundred fifty thousand British thermal units (350,000 Btus) per hour actual
heat input must limit their SO
2 emissions as follows:
1. For sources located in Missouri, other
than in Franklin, Jefferson, St. Louis, St. Charles Counties, or City of St.
Louis, no more than eight pounds (8 lbs.) of SO2 per
million Btus actual heat input averaged on any consecutive three (3)-hour time
period unless that source is listed in Table I of this rule; and
2. For sources located in Franklin,
Jefferson, St. Louis, St. Charles Counties, or City of St. Louis, no more than
two and three-tenths pounds (2.3 lbs.) of SO
2 per
million Btus actual heat input averaged on any consecutive three (3)-hour time
period unless-
A. The source is listed in
Table I of this rule; or
B. The
source has a total rated capacity of less than two thousand (2,000) million
Btus per hour and then the following restrictions apply.
(I) During the months of October, November,
December, January, February, and March of every year, no person shall burn or
permit the burning of any coal containing more than two percent (2%) sulfur or
of any fuel oil containing more than two percent (2%) sulfur. Otherwise, no
person shall burn or permit the burning of any coal or fuel oil containing more
than four percent (4%) sulfur.
(II)
Part (3)(B)2.B.(I) of this rule does not apply to any source if it can be shown
that emissions of SO2 from the source into the
atmosphere will not exceed two and three-tenths pounds (2.3 lbs.) per million
Btus actual heat input to the source.
(C) Owners or operators of sources and units
not covered under subsection (3)(A) or (3)(B) of this rule must limit the fuel
sulfur content as specified below.
|
Area of State
|
Source or unit construction date
|
Liquid fuel sulfur content in parts per million (ppm)
sulfur
|
|
Residual
|
Distillate
|
|
All
|
Began after the dates directly below in this
table
|
8,509
|
8,812
|
|
Kansas City Metropolitan Area
|
Began on or before September 28, 1968
|
34,036
|
35,249
|
|
St. Louis Metropolitan Area
|
Began on or before March 24, 1967
|
|
Springfield-Greene County Area
|
Began on or before September 24, 1971
|
|
Outstate Area
|
Began on or before February 24, 1971
|
(D)
Compliance Determination. Compliance must be determined as follows:
1. For sources and/or units listed in Table I
of this rule already subject to an SO
2 Continuous
Emission Monitoring System (CEMS) requirement, SO
2 CEMS
data; and
A. SO
2 CEMS
are not required for the following cases:
(I)
Units fueled exclusively by natural gas and not using any secondary fuel;
or
(II) Units fueled by natural gas
and only using fuel oil for less than forty-eight (48) hours annually and only
for qualifying situations (e.g., testing, maintenance, or operator training).
The forty-eight (48)-hour annual limit for the use of fuel oil as a secondary
fuel does not include qualifying curtailment events and compliance must be
demonstrated using paragraph (3)(D)2. of this rule;
B. SO2 CEMS must
follow the requirements in subsection (5)(B) of this rule;
2. For sources subject to subsection (3)(B)
or (3)(C) of this rule not required to use SO
2 CEMS for
compliance and for sources listed in Table I of this rule not required to use
SO
2 CEMS for compliance-
A. Fuel delivery records;
B. Fuel sampling and analysis;
C. Performance tests;
D. Continuous emission monitoring;
or
E. Other compliance methods
approved by the staff director and the U.S. Environmental Protection Agency and
incorporated into the state implementation plan.
(4) Reporting and Record
Keeping.
(A) Owners or operators of all
sources subject to this rule must-
1. Report
any excess emissions other than startup, shutdown, and malfunction excess
emissions already required to be reported under
10 CSR
10-6.050 to the staff director for each calendar
quarter within thirty (30) days following the end of the quarter. In all cases,
the notification must be a written report and include, at a minimum, the
following:
A. Name and location of
source;
B. Name and telephone
number of person responsible for the source;
C. Identity and description of the equipment
involved;
D. Time and duration of
the period of SO2 excess emissions;
E. Type of activity;
F. Estimate of the magnitude of the
SO2 excess emissions expressed in the units of the
applicable emission control regulation and the operating data and calculations
used in estimating the magnitude;
G. Measures taken to mitigate the extent and
duration of the SO2 excess emissions; and
H. Measures taken to remedy the situation
which caused the SO2 excess emissions and the measures
taken or planned to prevent the recurrence of these situations;
2. Maintain a list of
modifications to the source's operating procedures or other routine procedures
instituted to prevent or minimize the occurrence of any excess
SO2 emissions;
3. Maintain a record of data, calculations,
results, records, and reports from any SO2 emissions
performance test, SO2 continuous emission monitoring,
fuel deliveries, and/or fuel sampling tests; and
4. Maintain a record of any applicable
SO2 monitoring data, performance evaluations,
calibration checks, monitoring system and device performance tests, and any
adjustments and maintenance performed on these systems or devices.
(B) Owners or operators of sources
using SO
2 CEMS for compliance must also-
1. If SO2 CEMS is
already used to satisfy other requirements (other than only to demonstrate
compliance with this rule), continue to follow all correlating
SO2 CEMS requirements; or
2. If SO2 CEMS is used
only to demonstrate compliance with this rule, the SO2
CEMS and any necessary auxiliary monitoring equipment must follow the
requirements in subsection (5)(B) of this rule.
(C) Owners or operators of sources using fuel
delivery records for compliance must also maintain the fuel supplier
certification information to certify all fuel deliveries. Bills of lading
and/or other fuel delivery documentation containing the following information
for all fuel purchases or deliveries are deemed acceptable to comply with the
requirements of this rule:
1. The name,
address, and contact information of the fuel supplier;
2. The type of fuel (bituminous or
sub-bituminous coal, diesel, #2 fuel oil, etc.);
3. The moisture content of the coal (if
applicable);
4. The sulfur content
or maximum sulfur content expressed in percent sulfur by weight or in ppm
sulfur; and
5. The heating value of
the fuel.
(D) Owners or
operators of sources using fuel sampling and analysis for compliance must also
follow the requirements in subsection (5)(D) of this rule.
(E) Owners or operators of sources using
SO2 emissions performance tests for compliance must also
follow the requirements in subsection (5)(A) of this rule.
(F) All required reports and records must be
retained on-site for a minimum of five (5) years and made available within five
(5) business days upon written or electronic request by the director.
(G) Owners or operators of sources subject to
this rule must furnish the director all data necessary to determine compliance
status.
(5) Test Methods.
(A) Owners or operators of sources must use
one (1) or more of the following 40 CFR
60 test methods as specified in
10 CSR
10-6.030(22):
1. Method 1: Sample and velocity traverses
for stationary sources;
2. Method
2: Determination of stack gas velocity and volumetric flow rate (Type S pitot
tube);
3. Method 3: Gas analysis
for the determination of dry molecular weight;
4. Method 4: Determination of moisture
content in stack gases;
5. Method
6: Determination of Sulfur Dioxide Emissions from Stationary Sources;
6. Method 6A: Determination of Sulfur
Dioxide, Moisture, and Carbon Dioxide from Fuel Combustion Sources;
7. Method 6B: Determination of Sulfur Dioxide
and Carbon Dioxide Daily Average Emissions from Fossil Fuel Combustion
Sources;
8. Method 6C:
Determination of Sulfur Dioxide Emissions from Stationary Sources (Instrumental
Analyzer Procedure); and
9. Method
8: Determination of sulfuric acid mist and sulfur dioxide emissions from
stationary sources.
(B)
Owners or operators of sources using an SO
2 CEMS for
demonstrating compliance with this rule must follow the requirements in 40 CFR
75 and/or 40 CFR
60, Appendices B and F. 40 CFR
75 promulgated as of June 30,
2018 is hereby incorporated by reference in this rule, as published by the
Office of the Federal Register. Copies can be obtained from the U.S. Publishing
Office Bookstore, 710 N. Capitol Street NW, Washington, DC 20401. This rule
does not incorporate any subsequent amendments or additions. 40 CFR
60,
Appendices B and F are as specified in
10 CSR
10-6.030(22).
(C) Owners or operators of secondary lead
smelters must operate an SO
2 CEMS as follows:
1. The SO
2 CEMS must
be certified by the owner or operator in accordance with 40 CFR
60 Appendix B,
Performance Specification 2 and Section 60.13 as specified in
10 CSR
10-6.030(22) as is pertinent to
SO
2 continuous emission monitors as adopted by reference
in
10 CSR
10-6.070.
2. The span of SO2
continuous emission monitors must be set at an SO2
concentration of one-fifth percent (0.20%) by volume.
(D) Owners or operators of sources must use
fuel sampling and analysis to determine sulfur weight percent, or equivalent,
of fuel(s) used to operate fuel emission sources and/or units regulated by this
rule in accordance with
10 CSR
10-6.040.
(E) The heating value of the fuel must be
determined as specified in
10 CSR
10-6.040. The actual heat input must be determined by
multiplying the heating value of the fuel by the amount of fuel burned during
the source test period.
(F) Owners
or operators of sources may use an alternative test method that provides
results at least the same accuracy and precision as the replaced method, and is
approved in advance by the staff director, the EPA, and incorporated into the
state implementation plan.
