Section 225.100  Severability

 

If any Section, subsection or clause of this Part is found invalid, such finding must not affect the validity of this Part as a whole or any Section, subsection or clause not found invalid.

 

Section 225.120  Abbreviations and Acronyms

 

Unless otherwise specified within this Part, the abbreviations used in this Part must be the same as those found in 35 Ill. Adm. Code 211.  The following abbreviations and acronyms are used in this Part:

 

Act	Environmental Protection Act [415 ILCS 5]
ACI	activated carbon injection
AETB	Air Emission Testing Body
Agency	Illinois Environmental Protection Agency
Btu	British thermal unit
CAA	Clean Air Act (42 USC 7401 et seq.)
CAAPP	Clean Air Act Permit Program
CAIR	Clean Air Interstate Rule
CASA	Clean Air Set-Aside
CEMS	continuous emission monitoring system
CO2	carbon dioxide
CPS	Combined Pollutant Standard
CGO	converted gross electrical output
CRM	certified reference materials
CUTE	converted useful thermal energy
DAHS	data acquisition and handling system
dscm	dry standard cubic meters
EGU	electric generating unit
ESP	electrostatic precipitator
FGD	flue gas desulfurization
fpm	feet per minute
GO	gross electrical output
GWh	gigawatt hour
HI	heat input
Hg	mercury
hr	hour
ISO	International Organization for Standardization
kg	kilogram
lb	pound
MPS	Multi-Pollutant Standard
MSDS	Material Safety Data Sheet
MW	megawatt
MWe	megawatt electrical
MWh	megawatt hour
NAAQS	National Ambient Air Quality Standards
NIST	National Institute of Standards and Technology
NOx	nitrogen oxides
NTRM	NIST Traceable Reference Material
NUSA	New Unit Set-Aside
ORIS	Office of Regulatory Information Systems
O2	oxygen
PM2.5	particles less than 2.5 micrometers in diameter
QA	quality assurance
QAMO	quality-assured monitor operating
QC	quality control
RATA	relative accuracy test audit
RGFM	reference gas flow meter
SO2	sulfur dioxide
SNCR	selective noncatalytic reduction
TTBS	Temporary Technology Based Standard
TCGO	total converted useful thermal energy
UTE	useful thermal energy
USEPA	United States Environmental Protection Agency
yr	year

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.130  Definitions

 

The following definitions apply for the purposes of this Part.  Unless otherwise defined in this Section or a different meaning for a term is clear from its context, the terms used in this Part have the meanings specified in 35 Ill. Adm. Code 211.

 

"Agency" means the Illinois Environmental Protection Agency.  [415 ILCS 5/3.105]

 

"Averaging demonstration" means, with regard to Subpart B of this Part, a demonstration of compliance that is based on the combined performance of EGUs at two or more sources.

 

"Base Emission Rate" means, for a group of EGUs subject to emission standards for NO_x and SO₂ pursuant to Section 225.233, the average emission rate of NO_x or SO₂ from the EGUs, in pounds per million Btu heat input, for calendar years 2003 through 2005 (or, for seasonal NO_x, the 2003 through 2005 ozone seasons), as determined from the data collected and quality assured by the USEPA, pursuant to the 40 CFR 72 and 96 federal Acid Rain and NO_x Budget Trading Programs, for the emissions and heat input of that group of EGUs.

 

"Board" means the Illinois Pollution Control Board.  [415 ILCS 5/3.130]

 

"Boiler" means an enclosed fossil or other fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.

 

"Bottoming-cycle cogeneration unit" means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.

 

"CAIR authorized account representative" means, for the purpose of general accounts, a responsible natural person who is authorized, in accordance with 40 CFR 96, subparts BB, FF, BBB, FFF, BBBB, and FFFF to transfer and otherwise dispose of CAIR NO_x, SO₂, and NO_x Ozone Season allowances, as applicable, held in the CAIR NO_x, SO₂, and NO_x Ozone Season general account, and for the purpose of a CAIR NO_x compliance account, a CAIR SO₂ compliance account, or a CAIR NO_x Ozone Season compliance account, the CAIR designated representative of the source.

 

"CAIR designated representative" means, for a CAIR NO_x source, a CAIR SO₂ source, and a CAIR NO_x Ozone Season source and each CAIR NO_x unit, CAIR SO₂ unit and CAIR NO_x Ozone Season unit at the source, the natural person who is authorized by the owners and operators of the source and all such units at the source, in accordance with 40 CFR 96, subparts BB, FF, BBB, FFF, BBBB, and FFFF as applicable, to represent and legally bind each owner and operator in matters pertaining to the CAIR NO_x Annual Trading Program, CAIR SO₂ Trading Program, and CAIR NO_x Ozone Season Trading Program, as applicable.  For any unit that is subject to one or more of the following programs:  CAIR NO_x Annual Trading Program, CAIR SO₂ Trading Program, CAIR NO_x Ozone Season Trading Program, or the federal Acid Rain Program, the designated representative for the unit must be the same natural person for all programs applicable to the unit.

 

"Coal" means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite by the American Society for Testing and Materials (ASTM) Standard Specification for Classification of Coals by Rank D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004).

 

"Coal-derived fuel" means any fuel (whether in a solid, liquid or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.

 

"Coal-fired" means:

 

For purposes of Subpart B, or for purposes of allocating allowances under Sections 225.435, 225.445, 225.535, and 225.545, combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during a specified year;

 

Except as provided above, combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel.

 

"Cogeneration unit" means, for the purposes of Subparts C, D, and E, a stationary, fossil fuel-fired boiler or a stationary, fossil fuel-fired combustion turbine of which both of the following conditions are true:

 

It uses equipment to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and

 

It produces either of the following during the 12-month period beginning on the date the unit first produces electricity and during any subsequent calendar year after that in which the unit first produces electricity:

 

For a topping-cycle cogeneration unit, both of the following:

 

Useful thermal energy not less than five percent of total energy output; and

 

Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input if useful thermal energy produced is less than 15 percent of total energy output; or 

 

For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input.

 

"Combined cycle system" means a system comprised of one or more combustion turbines, heat recovery steam generators, and steam turbines configured to improve overall efficiency of electricity generation or steam production.

 

"Combustion turbine" means:

 

An enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and

 

If the enclosed device described in the above paragraph of this definition is combined cycle, any associated duct burner, heat recovery steam generator and steam turbine.

 

"Commence commercial operation" means, for the purposes of Subpart B of this Part, with regard to an EGU that serves a generator, to have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation.  Such date must remain the unit's date of commencement of operation even if the EGU is subsequently modified, reconstructed or repowered.  For the purposes of Subparts C, D and E, "commence commercial operation" is as defined in Section 225.150.

 

"Commence construction" means, for the purposes of Section 225.460(f), 225.470, 225.560(f), and 225.570, that the owner or owner's designee has obtained all necessary preconstruction approvals (e.g., zoning) or permits and either has:

 

Begun, or caused to begin, a continuous program of actual on-site construction of the source, to be completed within a reasonable time; or

 

Entered into binding agreements or contractual obligations, which cannot be cancelled or modified without substantial loss to the owner or operator, to undertake a program of actual construction of the source to be completed within a reasonable time.

 

For purposes of this definition:

 

"Construction" shall be determined as any physical change or change in the method of operation, including but not limited to fabrication, erection, installation, demolition, or modification of projects eligible for CASA allowances, as set forth in Sections 225.460 and 225.560.

 

"A reasonable time" shall be determined considering but not limited to the following factors: the nature and size of the project, the extent of design engineering, the amount of off-site preparation, whether equipment can be fabricated or can be purchased, when the project begins (considering both the seasonal nature of the construction activity and the existence of other projects competing for construction labor at the same time, the place of the environmental permit in the sequence of corporate and overall governmental approval), and the nature of the project sponsor (e.g., private, public, regulated).

 

"Commence operation", for purposes of Subparts C, D and E, means:

 

To have begun any mechanical, chemical, or electronic process, including, for the purpose of a unit, start-up of a unit's combustion chamber, except as provided in 40 CFR 96.105, 96.205, or 96.305, as incorporated by reference in Section 225.140.

 

For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source) after the date the unit commences operation as set forth in the first paragraph of this definition, such date will remain the date of commencement of operation of the unit, which will continue to be treated as the same unit.

 

For a unit that is replaced by a unit at the same source (e.g., repowered), after the date the unit commences operation as set forth in the first paragraph of this definition, such date will remain the replaced unit's date of commencement of operation, and the replacement unit will be treated as a separate unit with a separate date for commencement of operation as set forth in this definition as appropriate.

 

"Common stack" means a single flue through which emissions from two or more units are exhausted.

 

"Compliance account" means:

 

For the purposes of Subparts D and E, a CAIR NO_x Allowance Tracking System account, established by USEPA for a CAIR NO_x source or CAIR NO_x Ozone Season source pursuant to 40 CFR 96, subparts FF and FFFF in which any CAIR NO_x allowance or CAIR NO_x Ozone Season allowance allocations for the CAIR NO_x units or CAIR NO_x Ozone Season units at the source are initially recorded and in which are held any CAIR NO_x or CAIR NO_x Ozone Season allowances available for use for a control period in order to meet the source's CAIR NO_x or CAIR NO_x Ozone Season emissions limitations in accordance with Sections 225.410 and 225.510, and 40 CFR 96.154 and 96.354, as incorporated by reference in Section 225.140.  CAIR NO_x allowances may not be used for compliance with the CAIR NO_x Ozone Season Trading Program and CAIR NO_x Ozone Season allowances may not be used for compliance with the CAIR NO_x Annual Trading Program; or

 

For the purposes of Subpart C, a "compliance account" means a CAIR SO₂ compliance account, established by the USEPA for a CAIR SO₂ source pursuant to 40 CFR 96, subpart FFF, in which any SO₂ units at the source are initially recorded and in which are held any SO₂ allowances available for use for a control period in order to meet the source's CAIR SO₂ emissions limitations in accordance with Section 225.310 and 40 CFR 96.254, as incorporated by reference in Section 225.140.

 

"Control period" means:

 

For the CAIR SO₂ and NO_x Annual Trading Programs in Subparts C and D, the period beginning January 1 of a calendar year, except as provided in Sections 225.310(d)(3) and 225.410(d)(3), and ending on December 31 of the same year, inclusive; or

 

For the CAIR NO_x Ozone Season Trading Program in Subpart E, the period beginning May 1 of a calendar year, except as provided in Section 225.510(d)(3), and ending on September 30 of the same year, inclusive.

 

"Electric generating unit" or "EGU" means a fossil fuel-fired stationary boiler, combustion turbine or combined cycle system that serves a generator that has a nameplate capacity greater than 25 MWe and produces electricity for sale.

 

"Excepted monitoring system" means a sorbent trap monitoring system, as defined in this Section.

 

"Flue" means a conduit or duct through which gases or other matter is exhausted to the atmosphere.

 

"Fossil fuel" means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.

 

"Fossil fuel-fired" means the combusting of any amount of fossil fuel, alone or in combination with any other fuel in any calendar year.

 

"Generator" means a device that produces electricity.

 

"Gross electrical output" means the total electrical output from an EGU before making any deductions for energy output used in any way related to the production of energy.  For an EGU generating only electricity, the gross electrical output is the output from the turbine/generator set.

 

"Heat input" means, for the purposes of Subparts C, D, and E, a specified period of time, the product (in mmBtu/hr) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded and reported to USEPA by the CAIR designated representative and determined by USEPA in accordance with 40 CFR 96, subpart HH, HHH, or HHHH, if applicable, and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.

 

"Higher heating value" or "HHV" means the total heat liberated per mass of fuel burned (Btu/lb), when fuel and dry air at standard conditions undergo complete combustion and all resultant products are brought to their standard states at standard conditions. 

 

"Input mercury" means the mass of mercury that is contained in the coal combusted within an EGU.

 

"Integrated gasification combined cycle" or "IGCC" means a coal-fired electric utility steam generating unit that burns a synthetic gas derived from coal in a combined-cycle gas turbine.  No coal is directly burned in the unit during operation.

 

"Long-term cold storage" means the complete shutdown of a unit intended to last for an extended period of time (at least two calendar years) where notice for long-term cold storage is provided under 40 CFR 75.61(a)(7).

 

"Nameplate capacity" means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as of completion as specified by the person conducting the physical change.

 

"NIST traceable elemental mercury standards" means either:

 

1)         Compressed gas cylinders having known concentrations of elemental mercury, which have been prepared according to the "EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards"; or

 

2)         Calibration gases having known concentrations of elemental mercury, produced by a generator that fully meets the performance requirements of the "EPA Traceability Protocol for Qualification and Certification of Elemental Mercury Gas Generators, or an interim version of that protocol until such time as a final protocol is issued."

 

"NIST traceable source of oxidized mercury" means a generator that is capable of providing known concentrations of vapor phase mercuric chloride (HgCl₂), and that fully meets the performance requirements of the "EPA Traceability Protocol for Qualification and Certification of Oxidized Mercury Gas Generators, or an interim version of that protocol until such time as a final protocol is issued."

 

"Oil-fired unit" means a unit combusting fuel oil for more than 15.0 percent of the annual heat input in a specified year and not qualifying as coal-fired.

 

"Output-based emission standard" means, for the purposes of Subpart B of this Part, a maximum allowable rate of emissions of mercury per unit of gross electrical output from an EGU.

 

"Potential electrical output capacity" means 33 percent of a unit's maximum design heat input, expressed in mmBtu/hr divided by 3.413 mmBtu/MWh, and multiplied by 8,760 hr/yr.

 

"Project sponsor" means a person or an entity, including but not limited to the owner or operator of an EGU or a not-for-profit group, that provides the majority of funding for an energy efficiency and conservation, renewable energy, or clean technology project as listed in Sections 225.460 and 225.560, unless another person or entity is designated by a written agreement as the project sponsor for the purpose of applying for NO_x allowances or NO_x Ozone Season allowances from the CASA.

 

"Rated-energy efficiency" means the percentage of thermal energy input that is recovered as useable energy in the form of gross electrical output, useful thermal energy, or both that is used for heating, cooling, industrial processes, or other beneficial uses as follows:

 

For electric generators, rated-energy efficiency is calculated as one kilowatt hour (3,413 Btu) of electricity divided by the unit's design heat rate using the higher heating value of the fuel, and expressed as a percentage.

 

For combined heat and power projects, rated-energy efficiency is calculated using the following formula:

 

REE

=

((GO + UTE)/HI) ´ 100

 

Where:

 

REE	=	Rated-energy efficiency, expressed as percentage.
GO	=	Gross electrical output of the system expressed in Btu/hr.
UTE	=	Useful thermal output from the system that is used for heating, cooling, industrial processes or other beneficial uses, expressed in Btu/hr.
HI	=	Heat input, based upon the higher heating value of fuel, in Btu/hr.

 

"Repowered" means, for the purposes of an EGU, replacement of a coal-fired boiler with one of the following coal-fired technologies at the same source as the coal-fired boiler:

 

Atmospheric or pressurized fluidized bed combustion;

 

Integrated gasification combined cycle;

 

Magnetohydrodynamics;

 

Direct and indirect coal-fired turbines;

 

Integrated gasification fuel cells; or

 

As determined by the USEPA in consultation with the United States Department of Energy, a derivative of one or more of the technologies under this definition and any other coal-fired technology capable of controlling multiple combustion emissions simultaneously with improved boiler or generation efficiency and with significantly greater waste reduction relative to the performance of technology in widespread commercial use as of January 1, 2005.

 

"Rolling 12-month basis" means, for the purposes of Subpart B of this Part, a determination made on a monthly basis from the relevant data for a particular calendar month and the preceding 11 calendar months (total of 12 months of data), with two exceptions.  For determinations involving one EGU, calendar months in which the EGU does not operate (zero EGU operating hours) must not be included in the determination, and must be replaced by a preceding month or months in which the EGU does operate, so that the determination is still based on 12 months of data.  For determinations involving two or more EGUs, calendar months in which none of the EGUs covered by the determination operates (zero EGU operating hours) must not be included in the determination, and must be replaced by preceding months in which at least one of the EGUs covered by the determination does operate, so that the determination is still based on 12 months of data.

 

"Sorbent Trap Monitoring System" means the equipment required by Appendix B of this Part for the continuous monitoring of Hg emissions, using paired sorbent traps containing iodated charcoal (IC) or other suitable reagents.  This excepted monitoring system consists of a probe, the paired sorbent traps, an umbilical line, moisture removal components, an air tight sample pump, a gas flow meter, and an automated data acquisition and handling system.  The monitoring system samples the stack gas at a rate proportional to the stack gas volumetric flowrate.  The sampling is a batch process.  Using the sample volume measured by the gas flow meter and the results of the analyses of the sorbent traps, the average mercury concentration in the stack gas for the sampling period is determined in units of micrograms per dry standard cubic meter (µg/dscm).  Mercury mass emissions for each hour in the sampling period are calculated using the average Hg concentration for that period, in conjunction with contemporaneous hourly measurements of the stack gas flow rate, corrected for the stack moisture content.

 

"Total energy output" means, with respect to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.

 

"Useful thermal energy" means, for the purpose of a cogeneration unit, the thermal energy that is made available to an industrial or commercial process, excluding any heat contained in condensate return or makeup water:

 

Used in a heating application (e.g., space heating or domestic hot water heating); or

 

Used in a space cooling application (e.g., thermal energy used by an absorption chiller).

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.140  Incorporations by Reference

 

The following materials are incorporated by reference.  These incorporations do not include any later amendments or editions.

 

a)         Appendices A-1 through A-8, subpart A, and Performance Specifications 2 and 3 of appendix B of 40 CFR 60 (2005).

 

b)         40 CFR 72.2 (2005).

 

c)         40 CFR 75 (2006), Sections 2.1.1.5, 2.1.1.2, 7.7, and 7.8 of appendix A to 40 CFR 75, appendix C to 40 CFR 75, Section 3.3.5 of appendix F to 40 CFR 75 (2006).

 

d)         40 CFR 78 (2006).

 

e)         40 CFR 96, CAIR SO₂Trading Program, subparts AAA (excluding 40 CFR 96.204 and 96.206), BBB, FFF, GGG, and HHH (2006).

 

f)         40 CFR 96, CAIR NO_x Annual Trading Program, subparts AA (excluding 40 CFR 96.104, 96.105(b)(2), and 96.106), BB, FF, GG, and HH (2006).

 

g)         40 CFR 96, CAIR NO_x Ozone Season Trading Program, subparts AAAA (excluding 40 CFR 96.304, 96.305(b)(2), and 96.306), BBBB, FFFF, GGGG, and HHHH (2006).

 

h)         ASTM.  The following methods from the American Society for Testing and Materials, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken PA 19428-2959, (610) 832-9585:

 

1)         ASTM D388-77 (approved February 25, 1977), D388-90 (approved March 30, 1990), D388-91a (approved April 15, 1991), D388-95 (approved January 15, 1995), D388-98a (approved September 10, 1998), or D388-99 (approved September 10, 1999, reapproved in 2004), Classification of Coals by Rank.

 

2)         ASTM D3173-03, Standard Test Method for Moisture in the Analysis Sample of Coal and Coke (Approved April 10, 2003).

 

3)         ASTM D3684-01, Standard Test Method for Total Mercury in Coal by the Oxygen Bomb Combustion/Atomic Absorption Method (Approved October 10, 2001).

 

4)         ASTM D4840-99, Standard Guide for Sampling Chain-of-Custody Procedures (Reapproved 2004).

 

5)         ASTM D5865-04, Standard Test Method for Gross Calorific Value of Coal and Coke (Approved April 1, 2004).

 

6)         ASTM D6414-01, Standard Test Method for Total Mercury in Coal and Coal Combustion Residues by Acid Extraction or Wet Oxidation/Cold Vapor Atomic Absorption (Approved October 10, 2001).

 

7)         ASTM D6722-01, Standard Test Method for Total Mercury in Coal and Coal Combustion Residues by Direct Combustion Analysis (2001).

 

8)         ASTM D6784-02, Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method) (Approved April 10, 2002).

 

9)         ASTM D6911-03, Standard Guide for Packaging and Shipping Environmental Samples for Laboratory Analysis.

 

10)         ASTM D7036-04, Standard Practice for Competence of Air Emission Testing Bodies.

 

i)          Federal Energy Management Program, M&V Guidelines:  Measurement and Verification for Federal Energy Projects, US Department of Energy, Office of Energy Efficiency and Renewable Energy, Version 2.2, DOE/GO-102000-0960 (September 2000).

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.150  Commence Commercial Operation

 

Commence commercial operation means, for the purposes of Subparts C, D and E, with regard to a unit:

 

a)         To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in 40 CFR 96.105, 96.205, or 96.305, as incorporated by reference in Section 225.140.

 

1)        For a unit that is a CAIR SO₂ unit, CAIR NO_x unit, or a CAIR NO_x Ozone Season unit pursuant to Sections 225.305, 225.405, and 225.505, respectively, on the date the unit commences commercial operation on the later of November 15, 1990 or the date the unit commences commercial operation as defined in subsection (a) of this Section and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date will remain the unit's date of commencement of commercial operation, which will continue to be treated as the same unit.

 

2)        For a unit that is a CAIR SO₂ unit, CAIR NO_x unit, or a CAIR NO_x Ozone Season unit pursuant to Sections 225.305, 225.405, and 225.505, respectively, on the later of November 15, 1990 or the date the unit commences commercial operation as defined in subsection (a) of this Section and that is subsequently replaced by a unit at the same source (e.g., repowered), such date will remain the replaced unit's date of commencement of commercial operation, and the replacement unit will be treated as a separate unit with a separate date for commencement of commercial operation as defined in subsection (a) or (b) of this Section as appropriate.

 

b)        Notwithstanding subsection (a) of this Section and except as provided in 40 CFR 96.105, 96.205, or 96.305 for a unit that is not a CAIR SO₂ unit, CAIR NO_x unit, or a CAIR NO_x Ozone Season unit pursuant to Section 225.305, 225.405, or 225.505, respectively, on the later of November 15, 1990 or the date the unit commences commercial operation as defined in subsection (a) of this Section, the unit's date for commencement of commercial operation will be the date on which the unit becomes a CAIR SO₂ unit, CAIR NO_x unit, or CAIR NO_x Ozone Season unit pursuant to Section 225.305, 225.405, or 225.505, respectively.

 

1)        For a unit with a date for commencement of commercial operation as defined in subsection (b) of this Section and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date will remain the unit's date of commencement of commercial operation, which shall continue to be treated as the same unit.

 

2)        For a unit with a date for commencement of commercial operation as defined in subsection (b) of this Section and that is subsequently replaced by a unit at the same source (e.g., repowered), such date will remain the replaced unit's date of commencement of commercial operation, and the replacement unit will be treated as a separate unit with a separate date for commencement of commercial operation as defined in subsection (a) or (b) of this Section as appropriate.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.200  Purpose

 

The purpose of this Subpart B is to control the emissions of mercury from coal-fired EGUs operating in Illinois.

 

Section 225.202  Measurement Methods

 

Measurement of mercury must be according to the following:

 

a)         Continuous emission monitoring pursuant to Appendix B to this Part or an alternative emissions monitoring system, alternative reference method for measuring emissions, or other alternative to the emissions monitoring and measurement requirements of Sections 225.240 through 225.290, if such alternative is submitted to the Agency in writing and approved in writing by the Manager of the Bureau of Air's Compliance Section.

 

b)         ASTM D3173-03, Standard Test Method for Moisture in the Analysis Sample of Coal and Coke (Approved April 10, 2003), incorporated by reference in Section 225.140.

 

c)         ASTM D3684-01, Standard Test Method for Total Mercury in Coal by the Oxygen Bomb Combustion/Atomic Absorption Method (Approved October 10, 2001), incorporated by reference in Section 225.140.

 

d)         ASTM D5865-04, Standard Test Method for Gross Calorific Value of Coal and Coke (Approved April 1, 2004), incorporated by reference in Section 225.140.

 

e)         ASTM D6414-01, Standard Test Method for Total Mercury in Coal and Coal Combustion Residues by Acid Extraction or Wet Oxidation/Cold Vapor Atomic Absorption (Approved October 10, 2001), incorporated by reference in Section 225.140.

 

f)         ASTM D6722-01, Standard Test Method for Total Mercury in Coal and Coal Combustion Residues by Direct Combustion Analysis (2001), incorporated by reference in Section 225.140.

 

g)         ASTM D6784-02, Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method) (Approved April 10, 2002), incorporated by reference in Section 225.140.

 

h)         Emissions testing pursuant to Methods 29, 30A and 30B in appendix A-8 to 40 CFR 60.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.205  Applicability

 

The following stationary coal-fired boilers and stationary coal-fired combustion turbines, and the stationary boilers listed in Appendix A, regardless of the type of fuel combusted, are EGUs and are subject to this Subpart B:

 

a)         Except as provided in subsection (b) of this Section, a unit serving, at any time since the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

 

b)         For a unit that qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continues to qualify as a cogeneration unit, a cogeneration unit serving at any time a generator with nameplate capacity of more than 25 MWe and supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.  If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity but subsequently no longer qualifies as a cogeneration unit, the unit must be subject to subsection (a) of this Section starting on the day on which the unit first no longer qualifies as a cogeneration unit.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.210  Compliance Requirements

 

a)         Permit Requirements.

The owner or operator of each source with one or more EGUs subject to this Subpart B at the source must apply for a CAAPP permit that addresses the applicable requirements of this Subpart B.

 

b)         Monitoring and Testing Requirements.

 

1)         Except as otherwise indicated in this Subpart, the owner or operator of each source and each EGU at the source must comply with either the monitoring requirements of Sections 225.240 through 225.290 of this Subpart B, the periodic emissions testing requirements of Section 225.239 of this Subpart B, or an alternative emissions monitoring system, alternative reference method for measuring emissions, or other alternative to the emissions monitoring and measurement requirements of Sections 225.240 through 225.290, if such alternative is submitted to the Agency in writing and approved in writing by the Manager of the Bureau of Air's Compliance Section.

 

2)         Except as otherwise indicated in this Subpart, the compliance of each EGU with the mercury requirements of Sections 225.230 and 225.237 of this Subpart B must be determined by the emissions measurements recorded and reported in accordance with either Sections 225.240 through 225.290 of this Subpart B, Section 225.239 of this Subpart B, or an alternative emissions monitoring system, alternative reference method for measuring emissions, or other alternative to the emissions monitoring and measurement requirements of Sections 225.240 through 225.290, if such alternative is submitted to the Agency in writing and approved in writing by the Manager of the Bureau of Air's Compliance Section.

 

c)         Mercury Emission Reduction Requirements

The owner or operator of any EGU subject to this Subpart B must comply with applicable requirements for control of mercury emissions of Section 225.230 or Section 225.237 of this Subpart B.

 

d)         Recordkeeping and Reporting Requirements

Unless otherwise provided, the owner or operator of a source with one or more EGUs at the source must keep on site at the source each of the documents listed in subsections (d)(1) through (d)(3) of this Section for a period of five years from the date the document is created.  This period may be extended, in writing by the Agency, for cause, at any time prior to the end of five years.

 

1)         All emissions monitoring information gathered in accordance with Sections 225.240 through 225.290 and all periodic emissions testing information gathered in accordance with Section 225.239.

 

2)         Copies of all reports, compliance certifications, and other submissions and all records made or required or documents necessary to demonstrate compliance with the requirements of this Subpart B.

 

3)         Copies of all documents used to complete a permit application and any other submission under this Subpart B.

 

e)         Liability.

 

1)         The owner or operator of each source with one or more EGUs must meet the requirements of this Subpart B.

 

2)         Any provision of this Subpart B that applies to a source must also apply to the owner and operator of such source and to the owner or operator of each EGU at the source.

 

3)         Any provision of this Subpart B that applies to an EGU must also apply to the owner or operator of such EGU. 

 

f)         Effect on Other Authorities.  No provision of this Subpart B may be construed as exempting or excluding the owner or operator of a source or EGU from compliance with any other provision of an approved State Implementation Plan, a permit, the Act, or the CAA.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.220  Clean Air Act Permit Program (CAAPP) Permit Requirements

 

a)         Application Requirements.

 

1)         Each source with one or more EGUs subject to the requirements of this Subpart B is required to submit a CAAPP permit application that addresses all applicable requirements of this Subpart B, applicable to each EGU at the source. 

 

2)         For any EGU that commenced commercial operation:

 

A)        on or before December 31, 2008, the owner or operator of such EGUs must submit an initial permit application or application for CAAPP permit modification that meets the requirements of this Section on or before December 31, 2008.

 

B)        after December 31, 2008, the owner or operator of any such EGU must submit an initial CAAPP permit application or application for CAAPP modification that meets the requirements of this Section not later than 180 days before initial startup of the EGU, unless the construction permit issued for the EGU addresses the requirements of this Subpart B.

 

b)         Contents of Permit Applications.

In addition to other information required for a complete application for CAAPP permit or CAAPP permit modification, the application must include the following information:

 

1)         The ORIS (Office of Regulatory Information Systems) or facility code assigned to the source by the U.S. Department of Energy, Energy Information Administration, if applicable.

 

2)         Identification of each EGU at the source.

 

3)         The intended approach to the monitoring requirements of Sections 225.240 through 225.290 of this Subpart B, or, in the alternative, the applicant may include its intended approach to the testing requirement of Section 225.239 of this Subpart B.

 

4)         The intended approach to the mercury emission reduction requirements of Section 225.230 or 225.237 of this Subpart B, as applicable.

 

c)         Permit Contents.

 

1)         Each CAAPP permit issued by the Agency for a source with one or more EGUs subject to the requirements of this Subpart B must contain federally enforceable conditions addressing all applicable requirements of this Subpart B, which conditions must be a complete and segregable portion of the source's entire CAAPP permit.

 

2)         In addition to conditions related to the applicable requirements of this Subpart B, each such CAAPP permit must also contain the information specified under subsection (b) of this Section.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.230  Emission Standards for EGUs at Existing Sources

 

a)         Emission Standards.

 

1)         Except as provided in Sections 225.230(b) and (d), 225.232 through 225.234, 225.239, and 225.291 through 225.299 of this Subpart B, beginning July 1, 2009, the owner or operator of a source with one or more EGUs subject to this Subpart B that commenced commercial operation on or before December 31, 2008, must comply with one of the following standards for each EGU on a rolling 12-month basis:

 

A)        An emission standard of 0.0080 lb mercury/GWh gross electrical output; or

 

B)        A minimum 90-percent reduction of input mercury.

 

2)         For an EGU complying with subsection (a)(1)(A) of this Section, the mercury emission rate during quality-assured monitor operating (QAMO) hours of the EGU for each 12-month rolling period, as monitored in accordance with this Subpart B and calculated as follows, must not exceed the applicable emission standard:

 

                               

 

Where:

 

ER	=	Mercury emissions rate of the EGU during QAMO hours for the particular 12-month rolling period, expressed in lb/GWh.
Ei	=	Mercury emissions of the EGU during QAMO hours, in lbs, in an individual month in the 12-month rolling period, as determined in accordance with the emissions monitoring provisions of this Subpart B.
Oi	=	Gross electrical output of the EGU during QAMO hours, in GWh, in an individual month in the 12-month rolling period, as determined in accordance with Section 225.263 of this Subpart B.

 

3)         For an EGU complying with subsection (a)(1)(B) of this Section, the actual control efficiency for mercury emissions achieved by the EGU for each 12-month rolling period, as monitored in accordance with this Subpart B and calculated as follows, must meet or exceed the applicable efficiency requirement:

 

 

Where:

 

CE	=	Control efficiency for mercury emissions of the EGU during QAMO hours for the particular 12-month rolling period, expressed as a percent.
Ei	=	Mercury emissions of the EGU, in lbs during QAMO hours, in an individual month in the 12-month rolling period, as determined in accordance with the emissions monitoring provisions of this Subpart B.
Ii	=	Amount of mercury in the fuel fired in the EGU during QAMO hours, in lbs, in an individual month in the 12-month rolling period, as determined in accordance with Section 225.265 of this Subpart B.  Ii is determined by multiplying the amount of mercury in the fuel fired in the EGU in month i by the number of QAMO hours in that month, and dividing that product by the number of EGU operating hours in that month.

 

b)         Alternative Emission Standards for Single EGUs.

 

1)         As an alternative to compliance with the emission standards in subsection (a) of this Section, the owner or operator of the EGU may comply with the emission standards of this Subpart B by demonstrating that the actual emissions of mercury from the EGU are less than the allowable emissions of mercury from the EGU on a rolling 12-month basis. 

 

2)         For the purpose of demonstrating compliance with the alternative emission standards of this subsection (b), for each rolling 12-month period, the emissions of mercury from the EGU, as monitored in accordance with this Subpart B, must not exceed the allowable emissions of mercury from the EGU, as further provided by the following formulas:

 

 

 

 

 

 

Where:

 

E12	=	Mercury emissions of the EGU during QAMO hours for the particular 12-month rolling period.
A12	=	Allowable mercury emissions of the EGU during QAMO hours for the particular 12-month rolling period.
Ei	=	Mercury emissions of the EGU during QAMO hours in an individual month in the 12-month rolling period.
Ai	=	Allowable mercury emissions of the EGU during QAMO hours in an individual month in the 12-month rolling period, based on either the input mercury to the unit (AInput i) or the electrical output from the EGU (AOutput i), as selected by the owner or operator of the EGU for that given month. Ai is determined by multiplying the allowable mercury emissions based on either input mercury or electrical output in month i by the number of QAMO hours in that month, and dividing that product by the number of EGU operating hours in that month.
AInput i	=	Allowable mercury emissions of the EGU in an individual month based on the input mercury to the EGU, calculated as 10.0 percent (or 0.100) of the input mercury to the EGU.
AOutput i	=	Allowable mercury emissions of the EGU in a particular month based on the electrical output from the EGU, calculated as the product of the output based mercury limit, i.e., 0.0080 lb/GWh, and the electrical output from the EGU, in GWh.

 

3)         If the owner or operator of an EGU does not conduct the necessary sampling, analysis, and recordkeeping, in accordance with Section 225.265 of this Subpart B, to determine the mercury input to the EGU, the allowable emissions of the EGU must be calculated based on the electrical output of the EGU.

 

c)         If two or more EGUs are served by common stacks and the owner or operator conducts monitoring for mercury emissions in the common stacks, as provided for by Sections 1.14 through 1.18 of Appendix B to this Part, such that the mercury emissions of each EGU are not determined separately, compliance of the EGUs with the applicable emission standards of this Subpart B must be determined as if the EGUs were a single EGU.

 

d)         Alternative Emission Standards for Multiple EGUs.

 

1)         As an alternative to compliance with the emission standards of subsection (a) of this Section, the owner or operator of a source with multiple EGUs may comply with the emission standards of this Subpart B by demonstrating that the actual emissions of mercury from all EGUs at the source during QAMO hours are less than the allowable emissions of mercury from all EGUs at the source on a rolling 12-month basis. 

 

2)         For the purposes of the alternative emission standard of subsection (d)(1) of this Section, for each rolling 12-month period, the actual emissions of mercury from all the EGUs at the source during QAMO hours, as monitored in accordance with this Subpart B, must not exceed the sum of the allowable emissions of mercury from all the EGUs at the source, as further provided by the following formulas:

 

 

 

 

 

 

Where:

 

ES	=	Sum of the mercury emissions of the EGUs at the source during QAMO hours.
AS	=	Sum of the allowable mercury emissions of the EGUs at the source during QAMO hours.
Ei	=	Mercury emissions of an individual EGU at the source during QAMO hours, as determined in accordance with subsection (b)(2) of this Section.
Ai	=	Allowable mercury emissions of an individual EGU at the source during QAMO hours, as determined in accordance with subsection (b)(2) of this Section.
n	=	Number of EGUs covered by the demonstration.

 

3)         If an owner or operator of a source with two or more EGUs that is relying on this subsection (d) to demonstrate compliance fails to meet the requirements of this subsection (d) in a given 12-month rolling period, all EGUs at such source covered by the compliance demonstration are considered out of compliance with the applicable emission standards of this Subpart B for the entire last month of that period.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.232  Averaging Demonstrations for Existing Sources

 

a)         Through December 31, 2013, as an alternative to compliance with the emission standards of Section 225.230(a) of this Subpart B, the owner or operator of an EGU may comply with the emission standards of this Subpart B by means of an Averaging Demonstration (Demonstration) that demonstrates that the emissions of mercury from the EGU and other EGUs at the source and other EGUs at other sources covered by the Demonstration are less than the allowable emissions of mercury from all EGUs covered by the Demonstration on a rolling 12-month basis. 

 

b)         The EGUs at each source covered by a Demonstration must also comply with one of the following emission standards on a source-wide basis for the period covered by the Demonstration:

 

1)         An emission standard of 0.020 lb mercury/GWh gross electrical output; or

 

2)         A minimum 75 percent reduction of input mercury.

 

c)         For the purpose of this Section, compliance must be demonstrated using the equations in Section 225.230(a)(2), (a)(3), or (d)(2), as applicable, addressing all EGUs at the sources covered by the Demonstration, rather than by using only the EGUs at one source.

 

d)         Limitations on Demonstrations.

 

1)         The owners or operators of more than one existing source with EGUs can only participate in Demonstrations that include other existing sources that they own or operate.

 

2)         Single Existing Source Demonstrations

 

A)        The owner or operator of only a single existing source with EGUs (i.e., City, Water, Light & Power, City of Springfield, ID 167120AAO; Kincaid Generating Station, ID 021814AAB; and Southern Illinois Power Cooperative/Marion Generating Station, ID 199856AAC) can only participate in Demonstrations with other such owners or operators of a single existing source of EGUs.

 

B)        Participation in Demonstrations under this Section by the owner or operator of only a single existing source with EGUs must be authorized through federally enforceable permit conditions for each such source participating in the Demonstration.

 

e)         A source may be included in only one Demonstration during each rolling 12-month period.

 

f)         The owner or operator of EGUs using Demonstrations to show compliance with this Subpart B must complete the determination of compliance for each 12-month rolling period no later than 60 days following the end of the period.

 

g)         If averaging is used to demonstrate compliance with this Subpart B, the effect of a failure to demonstrate compliance will be that the compliance status of each source must be determined under Section 225.230 of this Subpart B as if the sources were not covered by a Demonstration. 

 

h)         For purposes of this Section, if the owner or operator of any source that participates in a Demonstration with an owner or operator of a source that does not maintain the required records, data, and reports for the EGUs at the source, or that does not submit copies of such records, data, or reports to the Agency upon request, then the effect of this failure will be deemed to be a failure to demonstrate compliance and the compliance status of each source must be determined under Section 225.230 of this Subpart B as if the sources were not covered by a Demonstration.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.233  Multi-Pollutant Standards (MPS)

 

a)         General

 

1)         As an alternative to compliance with the emissions standards of Section 225.230(a), the owner of eligible EGUs may elect for those EGUs to demonstrate compliance pursuant to this Section, which establishes control requirements and standards for emissions of NO_x and SO₂, as well as for emissions of mercury.

 

2)         For the purpose of this Section, the following requirements apply:

 

A)        An eligible EGU is an EGU that is located in Illinois and which commenced commercial operation on or before December 31, 2004; and

 

B)        Ownership of an eligible EGU is determined based on direct ownership, by the holding of a majority interest in a company that owns the EGU or EGUs, or by the common ownership of the company that owns the EGU, whether through a parent-subsidiary relationship, as a sister corporation, or as an affiliated corporation with the same parent corporation, provided that the owner has the right or authority to submit a CAAPP application on behalf of the EGU.

 

3)         The owner of one or more EGUs electing to demonstrate compliance with this Subpart B pursuant to this Section must submit an application for a CAAPP permit modification to the Agency, as provided in Section 225.220, that includes the information specified in subsection (b) and which clearly states the owner's election to demonstrate compliance pursuant to this Section 225.233.

 

A)        If the owner of one or more EGUs elects to demonstrate compliance with this Subpart pursuant to this Section, then all EGUs it owns in Illinois as of July 1, 2006, as defined in subsection (a)(2)(B), must be thereafter subject to the standards and control requirements of this Section, except as provided in subsection (a)(3)(B).  Such EGUs must be referred to as a Multi-Pollutant Standard (MPS) Group.

 

B)        Notwithstanding the foregoing, the owner may exclude from an MPS Group any EGU scheduled for permanent shutdown that the owner so designates in its CAAPP application required to be submitted pursuant to subsection (a)(3), with compliance for such units to be achieved by means of Section 225.235.

 

4)         Notwithstanding any contrary provision in this subsection (a), on and after January 1, 2019:

 

A)        The following EGUs shall be merged into a new MPS Group: Baldwin Units 1, 2, and 3; Coffeen Units 1 and 2; Duck Creek Unit 1; E.D. Edwards Units 2 and 3; Havana Unit 9; Hennepin Units 1 and 2; Joppa Units 1, 2, 3, 4, 5, and 6; and Newton Unit 1.  If one or more of the above EGUs are transferred to a different owner, such EGU or EGUs will become a separate MPS Group on and after the date of transfer.  For purposes of this Section, "transfer" means sale, conveyance, transfer, or other change in ownership of an EGU; and

 

B)        No other EGUs except for those listed in subsection (a)(4)(A) are subject to the requirements of this Section. 

 

5)       When an EGU is subject to the requirements of this Section, the requirements apply to all owners or operators of the EGU.

 

b)         Notice of Intent

The owner of one or more EGUs that intends to comply with this Subpart B by means of this Section must notify the Agency of its intention by December 31, 2007.  The following information must accompany the notification:

 

1)         The identification of each EGU that will be complying with this Subpart B by means of the multi-pollutant standards contained in this Section, with evidence that the owner has identified all EGUs that it owned in Illinois as of July 1, 2006 and which commenced commercial operation on or before December 31, 2004;

 

2)         If an EGU identified in subsection (b)(1) is also owned or operated by a person different than the owner submitting the notice of intent, a demonstration that the submitter has the right to commit the EGU or authorization from the responsible official for the EGU accepting the application;

 

3)         The Base Emission Rates for the EGUs, with copies of supporting data and calculations;

 

4)         A summary of the current control devices installed and operating on each EGU and identification of the additional control devices that will likely be needed for the each EGU to comply with emission control requirements of this Section, including identification of each EGU in the MPS group that will be addressed by subsection (c)(1)(B), with information showing that the eligibility criteria for this subsection (b) are satisfied; and

 

5)         Identification of each EGU that is scheduled for permanent shutdown, as provided by Section 225.235, which will not be part of the MPS Group and which will not be demonstrating compliance with this Subpart B pursuant to this Section.

 

c)         Control Technology Requirements for Emissions of Mercury

 

1)         Requirements for EGUs in an MPS Group

 

A)        For each EGU in an MPS Group other than an EGU that is addressed by subsection (c)(1)(B) for the period beginning July 1, 2009 (or December 31, 2009 for an EGU for which an SO2 scrubber or fabric filter is being installed to be in operation by December 31, 2009), and ending on December 31, 2014 (or such earlier date that the EGU is subject to the mercury emission standard in subsection (d)(1)), the owner or operator of the EGU must install, to the extent not already installed, and properly operate and maintain one of the following emission control devices:

 

i)          A Halogenated Activated Carbon Injection System, complying with the sorbent injection requirements of subsection (c)(2) of this Section, except as may be otherwise provided by subsection (c)(4), and followed by a Cold-Side Electrostatic Precipitator or Fabric Filter; or

 

ii)         If the boiler fires bituminous coal, a Selective Catalytic Reduction (SCR) System and an SO₂ Scrubber.

 

B)        An owner of an EGU in an MPS Group has two options under this subsection (c).  For an MPS Group that contains EGUs smaller than 90 gross MW in capacity, the owner may designate any such EGUs to be not subject to subsection (c)(1)(A).  Or, for an MPS Group that contains EGUs with gross MW capacity of less than 115 MW, the owner may designate any such EGUs to be not subject to subsection (c)(1)(A), provided that the aggregate gross MW capacity of the designated EGUs does not exceed 4% of the total gross MW capacity of the MPS Group.  For any EGU subject to one of these two options, unless the EGU is subject to the emission standards in subsection (d)(2), beginning on January 1, 2013, and continuing until such date that the owner or operator of the EGU commits to comply with the mercury emission standard in subsection (d)(2), the owner or operator of the EGU must install and properly operate and maintain a Halogenated Activated Carbon Injection System that complies with the sorbent injection requirements of subsection (c)(2), except as may be otherwise provided by subsection (c)(4), and followed by either a Cold-Side Electrostatic Precipitator or Fabric Filter.  The use of a properly installed, operated, and maintained Halogenated Activated Carbon Injection System that meets the sorbent injection requirements of subsection (c)(2) is defined as the "principal control technique."

 

2)         For each EGU for which injection of halogenated activated carbon is required by subsection (c)(1), the owner or operator of the EGU must inject halogenated activated carbon in an optimum manner, which, except as provided in subsection (c)(4), is defined as all of the following:

 

A)        The use of an injection system designed for effective absorption of mercury, considering the configuration of the EGU and its ductwork;

 

B)        The injection of halogenated activated carbon manufactured by Alstom, Norit, or Sorbent Technologies, Calgon Carbon's FLUEPAC CF Plus, or Calgon Carbon's FLUEPAC MC Plus, or the injection of any other halogenated activated carbon or sorbent that the owner or operator of the EGU has demonstrated to have similar or better effectiveness for control of mercury emissions; and

 

C)        The injection of sorbent at the following minimum rates, as applicable:

 

i)          For an EGU firing subbituminous coal, 5.0 lbs per million actual cubic feet or, for any cyclone-fired EGU that will install a scrubber and baghouse by December 31, 2012, and which already meets an emission rate of 0.020 lbs mercury/GWh gross electrical output or at least 75 percent reduction of input mercury, 2.5 lbs per million actual cubic feet;

 

ii)         For an EGU firing bituminous coal, 10.0 lbs per million actual cubic feet for any cyclone-fired EGU that will install a scrubber and baghouse by December 31, 2012, and which already meets an emission rate of 0.020 lbs mercury/GWh gross electrical output or at least 75 percent reduction of input mercury, 5.0 lbs per million actual cubic feet;

 

iii)        For an EGU firing a blend of subbituminous and bituminous coal, a rate that is the weighted average of the above rates, based on the blend of coal being fired; or

 

iv)        A rate or rates set lower by the Agency, in writing, than the rate specified in any of subsections (c)(2)(C)(i), (c)(2)(C)(ii), or (c)(2)(C)(iii) on a unit-specific basis, provided that the owner or operator of the EGU has demonstrated that such rate or rates are needed so that carbon injection will not increase particulate matter emissions or opacity so as to threaten noncompliance with applicable requirements for particulate matter or opacity.

 

D)        For the purposes of subsection (c)(2)(C), the flue gas flow rate  shall be the gas flow rate in the stack for all units except for those equipped with activated carbon injection prior to a hot-side electrostatic precipitator; for units equipped with activated carbon injection prior to a hot-side electrostatic precipitator, the flue gas flow rate shall be the gas flow rate at the inlet to the hot-side electrostatic precipitator, which shall be determined as the stack flow rate adjusted through the use of Charles' Law for the differences in gas temperatures in the stack and at the inlet to the electrostatic precipitator (V_esp = V_stack x T_esp/T_stack, where V = gas flow rate in acf and T = gas temperature in Kelvin or Rankine).

 

3)         The owner or operator of an EGU that seeks to operate an EGU with an activated carbon injection rate or rates that are set on a unit-specific basis pursuant to subsection (c)(2)(C)(iv) must submit an application to the Agency proposing such rate or rates, and must meet the requirements of subsections (c)(3)(A) and (c)(3)(B), subject to the limitations of subsections (c)(3)(C) and (c)(3)(D):

 

A)        The application must be submitted as an application for a new or revised federally enforceable operating permit for the EGU, and it must include a summary of relevant mercury emission data for the EGU, the unit-specific injection rate or rates that are proposed, and detailed information to support the proposed injection rate or rates; and

 

B)        This application must be submitted no later than the date that activated carbon must first be injected.  For example, the owner or operator of an EGU that must inject activated carbon pursuant to subsection (c)(1)(A) must apply for unit-specific injection rate or rates by July 1, 2009.  Thereafter, the owner or operator of the EGU may supplement its application; and

 

C)        Any decision of the Agency denying a permit or granting a permit with conditions that set a lower injection rate or rates may be appealed to the Board pursuant to Section 39 of the Act; and

 

D)        The owner or operator of an EGU may operate at the injection rate or rates proposed in its application until a final decision is made on the application, including a final decision on any appeal to the Board.

 

4)         During any evaluation of the effectiveness of a listed sorbent, an alternative sorbent, or other technique to control mercury emissions, the owner or operator of an EGU need not comply with the requirements of subsection (c)(2) for any system needed to carry out the evaluation, as further provided as follows:

 

A)        The owner or operator of the EGU must conduct the evaluation in accordance with a formal evaluation program submitted to the Agency at least 30 days prior to commencement of the evaluation;

 

B)        The duration and scope of the evaluation may not exceed the duration and scope reasonably needed to complete the desired evaluation of the alternative control technique, as initially addressed by the owner or operator in a support document submitted with the evaluation program;

 

C)        The owner or operator of the EGU must submit a report to the Agency no later than 30 days after the conclusion of the evaluation that describes the evaluation conducted and which provides the results of the evaluation; and

 

D)        If the evaluation of the alternative control technique shows less effective control of mercury emissions from the EGU than was achieved with the principal control technique, the owner or operator of the EGU must resume use of the principal control technique.  If the evaluation of the alternative control technique shows comparable effectiveness to the principal control technique, the owner or operator of the EGU may either continue to use the alternative control technique in a manner that is at least as effective as the principal control technique, or it may resume use of the principal control technique.  If the evaluation of the alternative control technique shows more effective control of mercury emissions than the control technique, the owner or operator of the EGU must continue to use the alternative control technique in a manner that is more effective than the principal control technique, so long as it continues to be subject to this subsection (c).

 

5)         In addition to complying with the applicable recordkeeping and monitoring requirements in Sections 225.240 through 225.290, the owner or operator of an EGU that elects to comply with this Subpart B by means of this Section must also comply with the following additional requirements:

 

A)        For the first 36 months that injection of sorbent is required, it must maintain records of the usage of sorbent, the flue gas flow rate from the EGU (and, if the unit is equipped with activated carbon injection prior to a hot-side electrostatic precipitator, flue gas temperature at the inlet of the hot-side electrostatic precipitator and in the stack), and the sorbent feed rate, in pounds per million actual cubic feet of flue gas, on a weekly average;

 

B)        After the first 36 months that injection of sorbent is required, it must monitor activated sorbent feed rate to the EGU, gas flow rate in the stack, and, if the unit is equipped with activated carbon injection prior to a hot-side electrostatic precipitator, flue gas temperature at the inlet of the hot-side electrostatic precipitator and in the stack.  It must automatically record this data and the sorbent carbon feed rate, in pounds per million actual cubic feet of flue gas, on an hourly average; and

 

C)        If a blend of bituminous and subbituminous coal is fired in the EGU, it must keep records of the amount of each type of coal burned and the required injection rate for injection of activated carbon, on a weekly basis.

 

6)         Until June 30, 2012, as an alternative to the CEMS or excepted monitoring system (sorbent trap system) monitoring, recordkeeping, and reporting requirements in Sections 225.240 through 225.290, the owner or operator of an EGU may elect to comply with the emissions testing, monitoring, recordkeeping, and reporting requirements in Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), (i)(3) and (4), and (j)(1).

 

7)         In addition to complying with the applicable reporting requirements in Sections 225.240 through 225.290, the owner or operator of an EGU that elects to comply with this Subpart B by means of this Section must also submit quarterly reports for the recordkeeping and monitoring conducted pursuant to subsection (c)(5).

 

d)         Emission Standards for Mercury

 

1)         For each EGU in an MPS Group that is not addressed by subsection (c)(1)(B), beginning January 1, 2015 (or such earlier date when the owner or operator of the EGU notifies the Agency that it will comply with these standards) and continuing thereafter, the owner or operator of the EGU must comply with one of the following standards on a rolling 12-month basis:

 

A)        An emission standard of 0.0080 lb mercury/GWh gross electrical output; or

 

B)        A minimum 90-percent reduction of input mercury.

 

2)         For each EGU in an MPS Group that has been addressed under subsection (c)(1)(B), beginning on the date when the owner or operator of the EGU notifies the Agency that it will comply with these standards and continuing thereafter, the owner or operator of the EGU must comply with one of the following standards on a rolling 12-month basis:

 

A)        An emission standard of 0.0080 lb mercury/GWh gross electrical output; or

 

B)        A minimum 90-percent reduction of input mercury.

 

3)         Compliance with the mercury emission standard or reduction requirement of this subsection (d) must be calculated in accordance with Section 225.230(a) or (d), or Section 225.232 until December 31, 2013.

 

4)         Until June 30, 2012, as an alternative to demonstrating compliance with the emissions standards in this subsection (d), the owner or operator of an EGU may elect to comply with the emissions testing requirements in Section 225.239(a)(4) and (b), (c), (d), (e), (f), (g), (h), (i), and (j).

 

e)         Emission Standards for NO_x and SO₂

 

1)         NO_x Emission Standards

 

A)        Beginning in calendar year 2012 and continuing through calendar year 2018, for the EGUs in each MPS Group, the owner and operator of the EGUs must comply with an overall NO_x annual emission rate of no more than 0.11 lb/mmBtu or an emission rate equivalent to 52 percent of the Base Annual Rate of NO_x emissions, whichever is more stringent.

 

B)        Beginning in the 2012 ozone season and continuing through the 2018 ozone season, for the EGUs in each MPS Group, the owner and operator of the EGUs must comply with an overall NO_x seasonal emission rate of no more than 0.11 lb/mmBtu or an emission rate equivalent to 80 percent of the Base Seasonal Rate of NO_x emissions, whichever is more stringent.

 

C)        Except as otherwise provided in subsections (f), (g), and (h), beginning in calendar year 2019 and continuing in each calendar year thereafter, the owner and operator of the EGUs in an MPS Group must not cause or allow to be discharged into the atmosphere combined annual NO_x emissions in excess of 19,000 tons from all EGUs.

 

D)        Except as otherwise provided in subsections (f), (g), and (h), beginning in calendar year 2019 and continuing in each calendar year thereafter, from May 1 to September 30 the owner and operator of the EGUs in an MPS Group must not cause or allow to be discharged into the atmosphere combined NO_x emissions in excess of 11,500 tons from all EGUs.

 

E)        On and after January 1, 2019, the owner and operator of any of Baldwin Units 1 and 2, Coffeen Units 1 and 2, Duck Creek Unit 1, E.D. Edwards Unit 3, and Havana Unit 9 must comply with the following:

 

i)          Operate each existing selective catalytic reduction (SCR) control system on each EGU in accordance with good operating practices and at all times when the unit it serves is in operation, provided that such operation of the SCR control system is consistent with the technological limitations, manufacturers' specifications, and good engineering and maintenance practices for the SCR control system.  During any such period in which the SCR is not operational, the owner and operator must minimize emissions to the extent reasonably practicable.  All NO_x emissions from each EGU, regardless of whether the SCR is operational or non-operational, must be included in determining compliance with the emission standards set forth under subsections (e)(1)(C), (e)(1)(D), (f)(1), (g)(1), and (h)(1), as applicable.

 

ii)         From May 1 through September 30, comply with a combined NO_x average emission rate of no more than 0.10 lb/mmBtu.  Averaging is only allowed among EGUs in the same MPS Group.

 

2)         SO₂ Emission Standards

 

A)        Beginning in calendar year 2013 and continuing in calendar year 2014, for the EGUs in each MPS Group, the owner and operator of the EGUs must comply with an overall SO₂ annual emission rate of 0.33 lb/mmBtu or a rate equivalent to 44 percent of the Base Rate of SO₂ emissions, whichever is more stringent.

 

B)        Beginning in calendar year 2015 and continuing through calendar year 2018, for the EGUs in each MPS Group, the owner and operator of the EGUs must comply with an overall annual emission rate for SO₂ of 0.25 lbs/mmBtu or a rate equivalent to 35 percent of the Base Rate of SO₂ emissions, whichever is more stringent.

 

C)        Except as otherwise provided in subsection (f), (g), and (h), beginning in calendar year 2019 and continuing in each calendar year thereafter, the owner and operator of the EGUs in an MPS Group must not cause or allow to be discharged into the atmosphere combined annual SO₂ emissions in excess of 34,500 tons from all EGUs.

 

D)        Beginning in calendar year 2019 and continuing in each calendar year thereafter, the owner and operator of Joppa Units 1, 2, 3, 4, 5, and 6 must not cause or allow to be discharged into the atmosphere combined annual SO₂ emissions in excess of 19,860 tons from such EGUs.

 

f)         Transfer of EGUs in an MPS Group

 

1)         If EGUs in an MPS Group are transferred to a different owner:

 

A)        For the MPS Group from which EGUs are transferred: The combined emissions limitations for the MPS Group set forth in this Section, as applicable, must be adjusted by subtracting from those limitations the applicable allocation amounts set forth in Columns A, B, and C in subsection (f)(2) that are attributable to the transferred EGUs.  The owner and operator of the MPS Group must comply with the adjusted emissions limitations beginning with the year in which the transfer occurs.

 

B)        For a new MPS Group consisting of the acquired EGUs:

 

i)          The owner and operator of the EGUs in an MPS Group must not cause or allow to be discharged into the atmosphere combined annual NO_x emissions in excess of the applicable annual NO_x limitation from all EGUs.  The applicable annual NO_x limitation shall be the sum of the allocation amounts attributable to all EGUs in the MPS Group set forth in Column A of subsection (f)(2).

 

ii)         From May 1 through September 30, the owner and operator of the EGUs in an MPS Group must not cause or allow to be discharged into the atmosphere combined NO_x emissions in excess of the applicable seasonal NO_x limitation from all EGUs.  The applicable seasonal NO_x limitation shall be the sum of the allocation amounts attributable to all EGUs in the MPS Group set forth in Column B of subsection (f)(2).

 

iii)        The owner and operator of the EGUs in an MPS Group must not cause or allow to be discharged into the atmosphere combined annual SO₂ emissions in excess of the applicable annual SO₂ limitation from all EGUs.  The applicable annual SO₂ limitation shall be the sum of the unit allocation amounts attributable to all EGUs in the MPS Group set forth in Column C of subsection (f)(2).

 

iv)        Notwithstanding subsections (f)(1)(B)(i) through (iii), if all the EGUs set forth under subsection (a)(4)(A) are transferred to the same owner on the same date, the owner and operator of the EGUs in the new MPS Group must comply with the emission limitations under subsection (e); the allocation amounts in subsection (f)(2) shall not apply.

 

C)        The owner and operator of the EGUs as of the last day of the applicable compliance period must demonstrate compliance with the emission standards of this Section for the entire applicable compliance period.  In determining compliance, such owner and operator must include in their calculations emissions from the EGUs for the entire applicable compliance period; the prior owner and operator shall not include in their calculations emissions from the EGUs for the applicable compliance period.

 

D)        Nothing in this subsection (f) relieves owners and operators of EGUs in an MPS Group from any of the other requirements set forth in this Section, including the mercury standards in subsection (d).

 

2)         Allocation Amounts in the Event of Transfer of EGUs

 

		Column A.	Column B.	Column C.
		Nox Allocation Amount (TPY in the Event of Transfer	NOx Allocation Amount (May1 through Sept 30 Tons) in the Event of Transfer	SO2 Allocation Amount (TPY) in the Event of Transfer
A)	Baldwin	4,570	2,700	3,760
B)	Havana	1,370	810	940
C)	Hennepin	1,140	675	3,760
D)	Coffeen	1,520	900	150
E)	Duck Creek	1,070	630	150
F)	Edwards	2,280	1,350	6,300
G)	Joppa	3,960	2,340	11,290
H)	Newton	2,050	1,215	6,300

 

3)         If EGUs in an MPS Group are transferred to a different owner:

 

A)        The transferring owner must notify the Agency's Bureau of Air, Compliance Section, in writing within seven days after the date of transfer.  The notification must include the following information:

 

i)          Name and address of the transferring owner and operator;

 

ii)         List of the EGUs transferred;

 

iii)        For the remaining EGUs in the MPS Group, calculations pursuant to subsection (f)(1)(A) demonstrating the adjusted combined annual NO_x emissions limitation, the adjusted combined NO_x emissions limitation from May 1 through September 30, and the adjusted combined annual SO₂ emissions limitation that are applicable to the MPS Group;

 

iv)        Name and address of the new owner and operator; and

 

v)         Date of transfer. 

 

B)        The acquiring owner must notify the Agency's Bureau of Air, Compliance Section, in writing within seven days after the date of transfer.  The notification must include the following information:

 

i)          Name and address of the acquiring owner and operator;

 

ii)         Name and address of the transferring owner and operator;

 

iii)        List of the EGUs acquired;

 

iv)        Calculations pursuant to subsection (f)(1)(B) demonstrating the combined annual NO_x emissions limitation, the combined NO_x emissions limitation from May 1 through September 30, and the combined annual SO₂ emissions limitation that are applicable to the acquiring owner and operator's MPS Group; and

 

v)         Date of transfer. 

 

g)         Permanent Shutdown of EGUs in an MPS Group

 

1)         If one or more EGUs in an MPS Group are permanently shut down:

 

A)        Such EGU or EGUs are no longer part of an MPS Group and no longer subject to the requirements of this Section.

 

B)        The combined emissions limitations for the MPS Group set forth in this Section, as applicable, must be adjusted by subtracting from those limitations the applicable allocation amounts set forth in Columns A, B, and C in subsection (g)(2) that are attributable to the shut-down EGU or EGUs.  The owner and operator of the MPS Group must comply with the adjusted emissions limitations, beginning with the compliance period or periods during which the permanent shutdown occurs.  For the purposes of this Section, "permanent shutdown" occurs on the date the owner or operator of the EGUs submits a written request to the Agency to modify its operating permit to reflect the shutdown of the EGU or EGUs, or to withdraw the permit for the source.  In determining compliance with the adjusted emission limitations, the owner and operator must include in their calculations emissions from the shut-down EGU or EGUs for the entire applicable compliance period.

 

C)        Nothing in this subsection (g) relieves owners and operators of EGUs in an MPS Group from any of the other requirements set forth in this Section, including the mercury standards in subsection (d).

 

2)         Allocation Amounts in the Event of Shutdown of EGUs

 

		Column A.		Column B.		Column C.
		Nox Allocation Amount (TPY) for Shutdown		NOx Allocation (May 1 through Sept 30 Tons) for Shutdown		SO2 Allocation Amount (TPY) for Shutdown
A)	Baldwin 1		1,560	920	1,290
B)	Baldwin 2		1,450	860	1,200
C)	Baldwin 3		1,560	920	1,270
D)	Havana 9		1,370	810	940
E)	Hennepin 1		270	160	910
F)	Hennepin 2		870	500	2,860
G)	Coffeen 1		570	340	60
H)	Coffeen 2		960	560	90
I)	Duck Creek 1		1,070	630	150
J)	Edwards 2		960	560	2,640
K)	Edwards 3		1,330	780	3,660
L)	Joppa 1		660	390	1,880
M)	Joppa 2		660	390	1,880
N)	Joppa 3		660	390	1,880
O)	Joppa 4		660	390	1,880
P)	Joppa 5		660	390	1,880
Q)	Joppa 6		660	390	1,880
R)	Newton 1		2,050	1,215	6,300

 

3)         If one or more EGUs in an MPS Group are permanently shut down, the owner must notify the Agency's Bureau of Air, Compliance Section, in writing within seven days after the date of shutdown.  Such notification must include the following information:

 

A)        Name and address of the owner and operator;

 

B)        List of the EGUs permanently shut down;

 

C)        For the remaining EGUs in the MPS Group, calculations pursuant to subsection (g)(1)(B) demonstrating the adjusted combined annual NO_x emissions limitation, the adjusted combined NO_x emissions limitation from May 1 through September 30, and the adjusted combined annual SO₂ emissions limitation that are applicable to the MPS Group; and

 

D)        Date of permanent shutdown, which is the date the owner or operator submitted a written request to the Agency to modify its operating permit to reflect the shutdown or to withdraw the permit for the source.

 

h)         Temporary shutdown of EGUs in an MPS Group

 

1)         If one or more EGUs in an MPS Group do not operate to produce electricity for sale during an entire compliance period or periods:

 

A)        The combined emissions limitations for the MPS Group set forth in this Section, as applicable, must be adjusted by subtracting from those limitations the applicable allocation amounts set forth in Columns A, B, and C in subsection (h)(2) that are attributable to the temporarily shut-down EGU or EGUs.

 

B)        The owner and operator of the MPS Group must comply with the adjusted emissions limitations for that compliance period or periods. 

 

C)        Nothing in this subsection (h) relieves owners and operators of EGUs in an MPS Group from any of the other requirements set forth in this Section, including the mercury standards in subsection (d).

 

2)         Allocation amounts in the event of temporary shutdown of EGUs:

 

		Column A.	Column B.	Column C.
		NOx Allocation Amount (TPY) for Temporary Shutdown	NOx Allocation Amount (May1 through Sept 30 Tons) for Temporary Shutdown	SO2 Allocation Amount (TPY) for Temporary Shutdown
A)	Baldwin 1	1,560	920	1,290
B)	Baldwin 2	1,450	860	1,200
C)	Baldwin 3	1,560	920	1,270
D)	Havana 9	1,370	810	940
E)	Hennepin 1	270	160	910
F)	Hennepin 2	870	500	2,860
G)	Coffeen 1	570	340	60
H)	Coffeen 2	960	560	90
I)	Duck Creek 1	1,070	630	150
J)	Edwards 2	960	560	2,640
K)	Edwards 3	1,330	780	3,660
L)	Joppa 1	660	390	1,880
M)	Joppa 2	660	390	1,880
N)	Joppa 3	660	390	1,880
O)	Joppa 4	660	390	1,880
P)	Joppa 5	660	390	1,880
Q)	Joppa 6	660	390	1,880
R)	Newton 1	2,050	1,215	6,300

 

3)         If one or more EGUs in an MPS Group do not operate to produce electricity for sale during an entire compliance period, the owner or operator must notify the Agency's Bureau of Air, Compliance Section, in writing within seven days after the end of each compliance period.  The notification must include the following information:

 

A)        Name and address of the owner and operator;

 

B)        List of the EGUs temporarily shut down;

 

C)        For the remaining EGUs in the MPS Group, calculations pursuant to subsection (g)(1)(B) demonstrating the adjusted combined annual NO_x emissions limitation, the adjusted combined NO_x emissions limitation from May 1 through September 30, and the adjusted combined annual SO₂ emissions limitation that are applicable to the MPS Group for the pertinent compliance period; and

 

D)        Date that the EGU or EGUs stopped operating.

 

i)          Requirements for NO_x and SO₂ Allowances.

 

1)         The owner or operator of EGUs in an MPS Group must not sell or trade to any person or otherwise exchange with or give to any person NO_x allowances allocated to the EGUs in the MPS Group for vintage years 2012 and beyond that would otherwise be available for sale, trade, or exchange as a result of actions taken to comply with the standards in subsection (e).  Such allowances that are not retired for compliance must be surrendered to the Agency on an annual basis, beginning in calendar year 2013.  This provision does not apply to the use, sale, exchange, gift, or trade of allowances among the EGUs in an MPS Group.

 

2)         The owners or operators of EGUs in an MPS Group must not sell or trade to any person or otherwise exchange with or give to any person SO₂ allowances allocated to the EGUs in the MPS Group for vintage years 2013 and beyond that would otherwise be available for sale or trade as a result of actions taken to comply with the standards in subsection (e).  Such allowances that are not retired for compliance, or otherwise surrendered pursuant to a consent decree to which the State of Illinois is a party, must be surrendered to the Agency on an annual basis, beginning in calendar year 2014.  This provision does not apply to the use, sale, exchange, gift, or trade of allowances among the EGUs in an MPS Group.

 

3)         The provisions of this subsection (i) do not restrict or inhibit the sale or trading of allowances that become available from one or more EGUs in a MPS Group as a result of holding allowances that represent over-compliance with the NO_x or SO₂ standard in subsection (e), once such a standard becomes effective, whether such over-compliance results from control equipment, fuel changes, changes in the method of operation, unit shutdowns, or other reasons.

 

4)         For purposes of this subsection (i), NO_x and SO₂ allowances mean allowances necessary for compliance with Sections 225.310, 225.410, or 225.510, 40 CFR 72, or Subparts AA and AAAA of 40 CFR 96, or any future federal NO_x or SO₂ emissions trading programs that modify or replace these programs. This Section does not prohibit the owner or operator of EGUs in an MPS Group from purchasing or otherwise obtaining allowances from other sources as allowed by law for purposes of complying with federal or state requirements, except as specifically set forth in this Section.

 

5)         By March 1, 2010, and continuing each year thereafter, the owner or operator of EGUs in an MPS Group must submit a report to the Agency that demonstrates compliance with the requirements of this subsection (i) for the previous calendar year, and which includes identification of any allowances that have been surrendered to the USEPA or to the Agency and any allowances that were sold, gifted, used, exchanged, or traded because they became available due to over-compliance.  All allowances that are required to be surrendered must be surrendered by August 31, unless USEPA has not yet deducted the allowances from the previous year.  A final report will be submitted to the Agency by August 31 of each year, verifying that the actions described in the initial report have taken place or, if such actions have not taken place, an explanation of all changes that have occurred and the reasons for such changes.  If USEPA has not deducted the allowances from the previous year by August 31, the final report will be due, and all allowances required to be surrendered must be surrendered, within 30 days after such deduction occurs.

 

j)          Recordkeeping

On and after January 1, 2019, and continuing each year thereafter, the owner and operator of the EGUs in an MPS Group must keep and maintain all records necessary to demonstrate compliance with this Section, including but not limited to those listed in subsections (j)(1) and (j)(2).  Copies of such records must be kept at the source and maintained for at least five years from the date the document is created and must be submitted by the owner and operator to the Agency within 30 days after receipt of a written request by the Agency.

 

1)         All emissions monitoring information gathered in accordance with 40 CFR 75.

 

2)         Copies of all reports and compliance certifications required under subsection (k) of this Section.

 

k)         Reporting

 

1)         Prior to January 1, 2019, compliance with the NO_x and SO₂ emission standards must be demonstrated in accordance with Sections 225.310, 225.410, and 225.510.  The owner or operator of EGUs must complete the demonstration of compliance before March 1 of the following year for annual standards and before November 1 for seasonal standards, by which date a compliance report must be submitted to the Agency.

 

2)         On and after January 1, 2019, and continuing each year thereafter, the owner and operator of the EGUs in an MPS Group must demonstrate compliance with the applicable requirements set forth in this subsection (k)(2). 

 

A)        Beginning in 2020, and continuing each year thereafter, the owner and operator of EGUs in an MPS Group must submit to the Agency's Bureau of Air, Compliance Section, a report demonstrating compliance with the annual emissions standards in subsections (e)(1)(C), (e)(2)(C), (e)(2)(D), (f)(1), (g)(1), and (h)(1), as applicable, and with the requirements of subsection (e)(1)(E)(i), as applicable, on or before March 1 of each year.  The compliance report must include the following for the preceding calendar year:

 

i)          Actual emissions of each pollutant, expressed in tons, for each individual EGU in the MPS Group.

 

ii)         Combined actual emissions of each pollutant, expressed in tons, for all EGUs in the MPS Group.

 

iii)        Combined actual emissions of SO₂, expressed in tons, for all Joppa EGUs.

 

iv)        A statement indicating whether each existing SCR control system on Baldwin Units 1 and 2, Coffeen Units 1 and 2, Duck Creek Unit 1, E.D. Edwards Unit 3, and Havana Unit 9 was operated in accordance with good operating practices and at all times when the unit it serves was in operation, consistent with the technological limitations, manufacturers' specifications, and good engineering and maintenance practices for the SCR control system.

 

v)         A statement indicating whether the EGUs in an MPS Group were operated in compliance with the requirements of this Section.

 

vi)        A certification by a responsible official that states the following:

 

I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted.  Based on my inquiry of the person or persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete.  I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.

 

B)        By November 1 of each year, the owner and operator of EGUs in an MPS Group must submit to the Agency's Bureau of Air, Compliance Section, a report demonstrating compliance with the seasonal emissions standards under subsections (e)(1)(D), (e)(1)(E)(ii), (f)(1), (g)(1), and (h)(1), as applicable.  The compliance report must include the following for the preceding May 1 through September 30:

 

i)          Actual emissions of NO_x, expressed in tons, for each individual EGU in the MPS Group.

 

ii)         Combined actual emissions of NO_x, expressed in tons, of all EGUs in the MPS Group.

 

iii)        NO_x average emission rate (lbs/mmBtu) for each of Baldwin Units 1 and 2; Coffeen Units 1 and 2; Duck Creek Unit 1; E.D. Edwards Unit 3; and Havana Unit 9, as applicable. 

 

iv)        Combined NO_x average emission rate (lbs/mmBtu) for Baldwin Units 1 and 2; Coffeen Units 1 and 2; Duck Creek Unit 1; E.D. Edwards Unit 3; and Havana Unit 9, as applicable under subsection (e)(1)(E)(ii). 

 

v)         A statement indicating whether the EGUs in an MPS Group were operated in compliance with the requirements of this Section.

 

vi)        A certification by a responsible official that states the following:

 

I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted.  Based on my inquiry of the person or persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete.  I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.

 

3)         For each EGU in an MPS Group, the owner or operator must notify the Agency of deviations from any of the requirements of this Section within 30 days after discovery of the deviations.  At a minimum, these notifications must include a description of the deviations, a discussion of the possible cause of the deviations, and a description of any corrective actions and preventative measures taken.

 

4)         Within 30 days after the beginning of a period during which the SCR control system on any of Baldwin Unit 1, Baldwin Unit 2, Coffeen Unit 1, Coffeen Unit 2, Duck Creek Unit 1, E.D. Edwards Unit 3, or Havana Unit 9 is not operated when the EGU it serves is in operation, the owner and operator must notify the Agency's Bureau of Air, Compliance Section, in writing.  This notification must include, at a minimum, a description of why the SCR control system was not operated, the time frames during which the SCR control system was not operated, and the steps taken to minimize emissions during those time frames.

 

l)          EGU Shutdowns

 

1)         By September 23, 2019, the owner or operator of the EGUs in the MPS group specified in subsection (a)(4)(A) must submit documentation to the regional transmission operator, Midcontinent Independent System Operator (MISO), that meets all applicable regulatory requirements necessary to obtain MISO approval to permanently cease operating one or more EGUs from that MPS Group with an aggregate capacity of at least 2,000 MW (calculated on a nameplate basis) of coal-fired electric generation.

 

2)         The owner or operator must permanently cease operating each coal-fired EGU identified in the documentation within 60 days after receiving notification from MISO that the owner or operator may cease operating that unit, but in no event later than December 31, 2019, except as follows:

 

A)        If MISO determines that operation of a coal-fired EGU is required to continue to operate to maintain transmission reliability, the owner or operator may continue operating the EGU but must use its best efforts to resolve the reliability requirement with MISO and cease operation of the EGU as soon as practicable.

 

B)        If MISO has not yet approved the cessation of operation of an EGU by December 31, 2019, the owner or operator may continue operating the EGU but must continue to seek a resolution with MISO until such time as MISO approves the cessation of operation of the unit.

 

C)        The owner or operator must permanently cease operating an EGU referenced in subsection (l)(2)(A) or (B) no later than 30 days after receipt of MISO's notification that the owner or operator may cease operating the unit.

 

3)         The owner or operator of the EGUs in the MPS Group must submit the following notifications to the Agency's Bureau of Air, Compliance Section, to demonstrate compliance with this subsection (l):

 

A)        By October 7, 2019, the owner or operator must submit a notification to the Agency containing the date that the owner or operator submitted the documentation required by subsection (l)(1) to MISO and a certification that the owner or operator has designated in that documentation EGUs from the MPS Group with an aggregate capacity of at least 2,000 MW of coal-fired electric generation for permanent cessation of operations.

 

B)        Within 30 days after the owner's or operator's receipt of MISO's response regarding whether an EGU in the MPS Group may cease operations or is required to continue to operate to maintain transmission reliability, but for responses received on or before December 31, 2019, in no event later than January 7, 2020, the owner or operator must notify the Agency of MISO's decision and identify each EGU to which the decision applies.  If an EGU is required to continue operation, the notification to the Agency must also describe the status of resolving the transmission reliability requirement.  If MISO has not yet responded regarding one or more EGUs by December 31, 2019, the owner or operator must notify the Agency by January 7, 2020, identifying each EGU still awaiting a response.  The owner or operator must update the Agency on the status of either resolving any transmission reliability requirement or receipt of MISO's response by the end of each calendar month until MISO approves the cessation of operation.

 

C)        Within seven days after the permanent cessation of operations of an EGU under this subsection (l), the owner or operator must submit a notification to the Agency identifying the EGU in the MPS Group that has permanently ceased operation, the nameplate capacity of that EGU, and the date the EGU permanently ceased operations. 

 

(Source:  Amended at 43 Ill. Reg. 9754, effective August 23, 2019)

 

Section 225.234   Temporary Technology-Based Standard for EGUs at Existing Sources

 

a)         General.

 

1)         At a source with EGUs that commenced commercial operation on or before December 31, 2008, for an EGU that meets the eligibility criteria in subsection (b) of this Section, the owner or operator of the EGU may temporarily comply with the requirements of this Section through June 30, 2015, as an alternative to compliance with the mercury emission standards in Section 225.230, as provided in subsections (c), (d), and (e) of this Section.

 

2)         An EGU that is complying with the emission control requirements of this Subpart B by operating pursuant to this Section may not be included in a compliance demonstration involving other EGUs during the period that is operating pursuant to this Section. 

 

3)         The owner or operator of an EGU that is complying with this Subpart B by means of the temporary alternative emission standards of this Section is not excused from any of the applicable monitoring, recordkeeping, and reporting requirements set forth in Sections 225.240 through 225.290. 

 

4)         Until June 30, 2012, as an alternative to the CEMS (or an excepted monitoring system) monitoring, recordkeeping, and reporting requirements in Sections 225.240 through 225.290, the owner or operator of an EGU may elect to comply with the emissions testing, monitoring, recordkeeping, and reporting requirements in Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), (i)(3) and (4), and (j)(1).

 

b)         Eligibility.

To be eligible to operate an EGU pursuant to this Section, the following criteria must be met for the EGU:

 

1)         The EGU is equipped and operated with the air pollution control equipment or systems that include injection of halogenated activated carbon and either a cold-side electrostatic precipitator or a fabric filter.

 

2)         The owner or operator of the EGU is injecting halogenated activated carbon in an optimum manner for control of mercury emissions, which must include injection of Alstom, Norit, Sorbent Technologies, Calgon Carbon's FLUEPAC CF Plus, Calgon Carbon's FLUEPAC MC Plus, or other halogenated activated carbon that the owner or operator of the EGU has demonstrated to have similar or better effectiveness for control of mercury emissions, at least at the following rates set forth in subsections (b)(2)(A) through (b)(2)(D) of this Section, unless other provisions for injection of halogenated activated carbon are established in a federally enforceable operating permit issued for the EGU, using an injection system designed for effective absorption of mercury, considering the configuration of the EGU and its ductwork.  For the purposes of this subsection (b)(2), the flue gas flow rate shall be the flow rate in the stack for all units except for those equipped with activated carbon injection prior to a hot-side electrostatic precipitator; for units equipped with activated carbon injection prior to a hot-side electrostatic precipitator, the flue gas flow rate shall be the gas flow rate at the inlet to the hot-side electrostatic precipitator, which shall be determined as the stack flow rate adjusted through the use of Charles' Law for the differences in gas temperatures in the stack and at the inlet to the electrostatic precipitator (V_esp = V_stack x T_esp/T_stack, where V = gas flow rate in acf and T = gas temperature in Kelvin or Rankine).

 

A)        For an EGU firing subbituminous coal, 5.0 lbs per million actual cubic feet.

 

B)        For an EGU firing bituminous coal, 10.0 lbs per million actual cubic feet.

 

C)        For an EGU firing a blend of subbituminous and bituminous coal, a rate that is the weighted average of the above rates, based on the blend of coal being fired.

 

D)        A rate or rates set on a unit-specific basis that are lower than the rate specified above to the extent that the owner or operator of the EGU demonstrates that such rate or rates are needed so that carbon injection would not increase particulate matter emissions or opacity so as to threaten compliance with applicable regulatory requirements for particulate matter or opacity.

 

3)         The total capacity of the EGUs that operate pursuant to this Section does not exceed the applicable of the following values:

 

A)        For the owner or operator of more than one existing source with EGUs, 25 percent of the total rated capacity, in MW, of all the EGUs at the existing sources that it owns or operates, other than any EGUs operating pursuant to Section 225.235 of this Subpart B.

 

B)        For the owner or operator of only a single existing source with EGUs (i.e., City, Water, Light & Power, City of Springfield, ID 167120AAO; Kincaid Generating Station, ID 021814AAB; and Southern Illinois Power Cooperative/Marion Generating Station, ID 199856AAC), 25 percent of the total rated capacity, in MW, of the all the EGUs at the existing sources, other than any EGUs operating pursuant to Section 225.235.

 

c)         Compliance Requirements.

 

1)         Emission Control Requirements.

The owner or operator of an EGU that is operating pursuant to this Section must continue to maintain and operate the EGU to comply with the criteria for eligibility for operation pursuant to this Section, except during an evaluation of the current sorbent, alternative sorbents or other techniques to control mercury emissions, as provided by subsection (e) of this Section.

 

2)         Monitoring and Recordkeeping Requirements.

In addition to complying with all applicable monitoring and recordkeeping

 requirements in Sections 225.240 through 225.290 or Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), and i(3) and (4), the owner or operator of an EGU operating pursuant to this Section must also:

 

A)        Through December 31, 2012, it must maintain records of the usage of activated carbon, the flue gas flow rate from the EGU (and, if the unit is equipped with activated carbon injection prior to a hot-side electrostatic precipitator, flue gas temperature at the inlet of the hot-side electrostatic precipitator and in the stack), and the activated carbon feed rate, in pounds per million actual cubic feet of flue gas, on a weekly average.

 

B)        Beginning January 1, 2013, it must monitor activated carbon feed rate to the EGU, gas flow rate in the stack, and, if the unit is equipped with activated carbon injection prior to a hot-side electrostatic precipitator, flue gas temperature at the inlet of the hot-side electrostatic precipitator and in the stack.  It must, automatically record this data and the activated carbon feed rate, in pounds per million actual cubic feet of flue gas, on an hourly average.  

 

C)        If a blend of bituminous and subbituminous coal is fired in the EGU, it must maintain records of the amount of each type of coal burned and the required injection rate for injection of halogenated activated carbon, on a weekly basis.

 

3)         Notification and Reporting Requirements.

In addition to complying with all applicable reporting requirements in Sections 225.240 through 225.290 or Section 225.239(f)(1), (f)(2), and (j)(1), the owner or operator of an EGU operating pursuant to this Section must also submit the following notifications and reports to the Agency:

 

A)        Written notification prior to the month in which any of the following events will occur: 

 

i)          The EGU will no longer be eligible to operate under this Section due to a change in operation;

 

ii)         The type of coal fired in the EGU will change; the mercury emission standard with which the owner or operator is attempting to comply for the EGU will change; or

 

iii)        Operation under this Section will be terminated.

 

B)        Quarterly reports for the recordkeeping and monitoring or emissions testing conducted pursuant to subsection (c)(2) of this Section.

 

C)        Annual reports detailing activities conducted for the EGU to further improve control of mercury emissions, including the measures taken during the past year and activities planned for the current year.

 

d)         Applications to Operate under the Technology-Based Standard

 

1)         Application Deadlines.

 

A)        The owner or operator of an EGU that is seeking to operate the EGU pursuant to this Section must submit an application to the Agency no later than three months prior to the date on which compliance with Section 225.230 of this Subpart B would otherwise have to be demonstrated.  For example, the owner or operator of an EGU that is applying to operate the EGU pursuant to this Section on June 30, 2010, when compliance with applicable mercury emission standards must be first demonstrated, must apply by March 31, 2010 to operate under this Section.

 

B)        Unless the Agency finds that the EGU is not eligible to operate pursuant to this Section or that the application for operation pursuant to this Section does not meet the requirements of subsection (d)(2) of this Section, the owner or operator of the EGU is authorized to operate the EGU pursuant to this Section beginning 60 days after receipt of the application by the Agency.

 

C)        The owner or operator of an EGU operating pursuant to this Section must reapply to operate pursuant to this Section:  

 

i)          If it operated the EGU pursuant to this Section 225.234 during the period of June 2010 through December 2012 and it seeks to operate the EGU pursuant to this Section 225.234 during the period from January 2013 through June 2015.

 

ii)         If it is planning a physical change to or a change in the method of operation of the EGU, control equipment or practices for injection of activated carbon that is expected to reduce the level of control of mercury emissions.

 

2)         Contents of Application.

An application to operate an EGU pursuant to this Section 225.234 must be submitted as an application for a new or revised federally enforceable operating permit for the EGU, and it must include the following documents and information:

 

A)        A formal request to operate pursuant to this Section showing that the EGU is eligible to operate pursuant to this Section and describing the reason for the request, the measures that have been taken for control of mercury emissions, and factors preventing more effective control of mercury emissions from the EGU.

 

B)        The applicable mercury emission standard in Section 225.230(a) with which the owner or operator of the EGU is attempting to comply and a summary of relevant mercury emission data for the EGU.

 

C)        If a unit-specific rate or rates for carbon injection are proposed pursuant to subsection (b)(2) of this Section, detailed information to support the proposed injection rates.

 

D)        An action plan describing the measures that will be taken while operating under this Section to improve control of mercury emissions.  This plan must address measures such as evaluation of alternative forms or sources of activated carbon, changes to the injection system, changes to operation of the unit that affect the effectiveness of mercury absorption and collection, changes to the particulate matter control device to improve performance, and changes to other emission control devices.  For each measure contained in the plan, the plan must provide a detailed description of the specific actions that are planned, the reason that the measure is being pursued and the range of improvement in control of mercury that is expected, and the factors that affect the timing for carrying out the measure, together with the current schedule for the measure. 

 

e)         Evaluation of Alternative Control Techniques for Mercury Emissions.

 

1)         During an evaluation of the effectiveness of the current sorbent, alternative sorbent, or other technique to control mercury emissions, the owner or operator of an EGU operating pursuant to this Section need not comply with the eligibility criteria for operation pursuant to this Section as needed to carry out an evaluation of the practicality and effectiveness of such technique, subject to the following limitations:

 

A)        The owner or operator of the EGU must conduct the evaluation in accordance with a formal evaluation program that it has submitted to the Agency at least 30 days prior to beginning the evaluation.

 

B)        The duration and scope of the formal evaluation program must not exceed the duration and scope reasonably needed to complete the desired evaluation of the alternative control technique, as initially addressed by the owner or owner in a support document that it has submitted with the formal evaluation program pursuant to subsection (e)(1)(A) of this Section.

 

C)        Notwithstanding 35 Ill. Adm. Code 201.146(hhh), the owner or operator of the EGU must obtain a construction permit for any new or modified air pollution control equipment to be constructed as part of the evaluation of the alternative control technique.

 

D)        The owner or operator of the EGU must submit a report to the Agency, no later than 90 days after the conclusion of the formal evaluation program describing the evaluation that was conducted, and providing the results of the formal evaluation program.

 

2)         If the evaluation of the alternative control technique shows less effective control of mercury emissions from the EGU than achieved with the prior control technique, the owner or operator of the EGU must resume use of the prior control technique.  If the evaluation of the alternative control technique shows comparable control effectiveness, the owner or operator of the EGU may either continue to use the alternative control technique in an optimum manner or resume use of the prior control technique.  If the evaluation of the alternative control technique shows more effective control of mercury emissions, the owner or operator of the EGU must continue to use the alternative control technique in an optimum manner, if it continues to operate pursuant to this Section.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.235  Units Scheduled for Permanent Shut Down

 

a)         The emission standards of Section 225.230(a) are not applicable to an EGU that will be permanently shut down as described in this Section:

 

1)         The owner or operator of an EGU that relies on this Section must complete the following actions before June 30, 2009:

 

A)        Have notified the Agency that it is planning to permanently shut down the EGU by the applicable date specified in subsection (a)(3) or (4) of this Section.  This notification must include a description of the actions that have already been taken to allow the shut down of the EGU and a description of the future actions that must be accomplished to complete the shut down of the EGU, with the anticipated schedule for those actions and the anticipated date of permanent shut down of the unit.

 

B)        Have applied for a construction permit or be actively pursuing a federally enforceable agreement that requires the EGU to be permanently shut down in accordance with this Section.

 

C)        Have applied for revisions to the operating permits for the EGU to include provisions that terminate the authorization to operate the unit in accordance with this Section.       

 

2)         The owner or operator of an EGU that relies on this Section must, before June 30, 2010, complete the following actions:

 

A)        Have obtained a construction permit or entered into a federally enforceable agreement as described in subsection (a)(1)(B) of this Section; or

 

B)        Have obtained revised operating permits in accordance with subsection (a)(1)(C) of this Section.

 

3)         The plan for permanent shut down of the EGU must provide for the EGU to be permanently shut down by no later than the applicable date specified below:

 

A)        If the owner or operator of the EGU is not constructing a new EGU or other generating unit to specifically replace the existing EGU, by December 31, 2010.

 

B)        If the owner or operator of the EGU is constructing a new EGU or other generating unit to specifically replace the existing EGU, by December 31, 2011.

 

4)         The owner or operator of the EGU must permanently shut down the EGU by the date specified in subsection (a)(3) of this Section, unless the owner or operator submits a demonstration to the Agency before the specified date showing that circumstances beyond its reasonable control (such as protracted delays in construction activity, unanticipated outage of another EGU, or protracted shakedown of a replacement unit) have occurred that interfere with the plan for permanent shut down of the EGU, in which case the Agency may accept the demonstration as substantiated and extend the date for shut down of the EGU as follows:

 

A)        If the owner or operator of the EGU is not constructing a new EGU or other generating unit to specifically replace the existing EGU, for up to one year, i.e., permanent shut down of the EGU to occur by no later than December 31, 2011; or

 

B)        If the owner or operator of the EGU is constructing a new EGU or other generating unit to specifically replace the existing EGU, for up to 18 months, i.e., permanent shutdown of the EGU to occur by no later than June 30, 2013; provided, however, that after December 31, 2012, the existing EGU must only operate as a back-up unit to address periods when the new generating units are not in service.

 

b)         Notwithstanding Sections 225.230 and 225.232, any EGU that is not required to comply with Section 225.230 pursuant to this Section must not be included when determining whether any other EGUs at the source or other sources are in compliance with Section 225.230.

 

c)         If an EGU, for which the owner or operator of the source has relied upon this Section in lieu of complying with Section 225.230(a) is not permanently shut down as required by this Section, the EGU must be considered to be a new EGU subject to the emission standards in Section 225.237(a) beginning in the month after the EGU was required to be permanently shut down, in addition to any other penalties that may be imposed for failure to permanently shut down the EGU in accordance with this Section.

 

d)         An EGU that has completed the requirements of subsection (a) of this Section is exempt from the monitoring and testing requirements in Sections 225.239 and 225.240.

 

e)         An EGU that is scheduled for permanent shut down pursuant to Section 225.294(b) is exempt from the monitoring and testing requirements in Sections 225.239 and 225.240.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.237  Emission Standards for New Sources with EGUs

 

a)         Standards.

 

1)         Except as provided in Sections 225.238 and 225.239, the owner or operator of a source with one or more EGUs, but that previously had not had any EGUs that commenced commercial operation before January 1, 2009, must comply with one of the following emission standards for each EGU on a rolling 12-month basis: 

 

A)        An emission standard of 0.0080 lb mercury/GWh gross electrical output; or

 

B)        A minimum 90 percent reduction of input mercury.

 

2)         For this purpose, compliance may be demonstrated using the equations in Section 225.230(a)(2), (a)(3), or (b)(2).

 

b)         The initial 12-month rolling period for which compliance with the emission standards of subsection (a)(1) of this Section must be demonstrated for a new EGU will commence on the date that the initial performance testing commences under 40 CFR 60.8.  The CEMS (or an excepted monitoring system) monitoring required by this Subpart B for mercury emissions from the EGU must be certified prior to this date.  Thereafter, compliance must be demonstrated on a rolling 12-month basis based on calendar months.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.238   Temporary Technology-Based Standard for New Sources with EGUs

 

a)         General.

 

1)         At a source with EGUs that previously had not had any EGUs that commenced commercial operation before January 1, 2009, for an EGU that meets the eligibility criteria in subsection (b) of this Section, as an alternative to compliance with the mercury emission standards in Section 225.237, the owner or operator of the EGU may temporarily comply with the requirements of this Section, through December 31, 2018, as further provided in subsections (c), (d), and (e) of this Section.

 

2)         An EGU that is complying with the emission control requirements of this Subpart B by operating pursuant to this Section may not be included in a compliance demonstration involving other EGUs at the source during the period that the temporary technology-based standard is in effect. 

 

3)         The owner or operator of an EGU that is complying with this Subpart B pursuant to this Section is not excused from applicable monitoring, recordkeeping, and reporting requirements of Sections 225.240 through 225.290. 

 

4)         Until June 30, 2012, as an alternative to the CEMS (or excepted monitoring system) monitoring, recordkeeping, and reporting requirements in Sections 225.240 through 225.290, the owner or operator of an EGU may elect to comply with the emissions testing, monitoring, recordkeeping, and reporting requirements in Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), (i)(3) and (4), and (j)(1).

 

b)         Eligibility.

To be eligible to operate an EGU pursuant to this Section, the following criteria must be met for the EGU:

 

1)         The EGU is subject to Best Available Control Technology (BACT) for emissions of sulfur dioxide, nitrogen oxides, and particulate matter, and the EGU is equipped and operated with the air pollution control equipment or systems specified below, as applicable to the category of EGU:

 

A)        For coal-fired boilers, injection of sorbent or other mercury control technique (e.g., reagent) approved by the Agency.

 

B)        For an EGU firing fuel gas produced by coal gasification, processing of the raw fuel gas prior to combustion for removal of mercury with a system using a sorbent or other mercury control technique approved by the Agency.

 

2)         For an EGU for which injection of a sorbent or other mercury control technique is required pursuant to subsection (b)(1) of this Section, the owner or operator of the EGU is injecting sorbent or other mercury control technique in an optimum manner for control of mercury emissions, which must include injection of Alstom, Norit, Sorbent Technologies, Calgon Carbon’s FLUEPAC CF Plus, Calgon Carbon's FLUEPAC MC Plus,or other sorbent or other mercury control technique that the owner or operator of the EGU demonstrates to have similar or better effectiveness for control of mercury emissions, at least at the rate set forth in the appropriate of subsections (b)(2)(A) through (b)(2)(C) of this Section, unless other provisions for injection of sorbent or other mercury control technique are established in a federally enforceable operating permit issued for the EGU, with an injection system designed for effective absorption of mercury.  For the purposes of this subsection (b)(2), the flue gas flow rate shall be the gas flow rate in the stack for all units except for those equipped with activated carbon injection prior to a hot-side electrostatic precipitator; for units equipped with activated carbon injection prior to a hot-side electrostatic precipitator, the flue gas flow rate shall be the gas flow rate at the inlet to the hot-side electrostatic precipitator, which shall be determined as the stack flow rate adjusted through the use of Charles' Law for the differences in gas temperatures in the stack and at the inlet to the electrostatic precipitator (V_esp = V_stack x T_esp/T_stack, where V = gas flow rate in acf and T = gas temperature in Kelvin or Rankine).

 

A)        For an EGU firing subbituminous coal, 5.0 pounds per million actual cubic feet.

 

B)        For an EGU firing bituminous coal, 10.0 pounds per million actual cubic feet.

 

C)        For an EGU firing a blend of subbituminous and bituminous coal, a rate that is the weighted average of the above rates, based on the blend of coal being fired.

 

D)        A rate or rates set on a unit-specific basis that are lower than the rate specified in subsections (b)(2)(A), (B), and (C) of this Section, to the extent that the owner or operator of the EGU demonstrates that such rate or rates are needed so that sorbent injection or other mercury control technique would not increase particulate matter emissions or opacity so as to threaten compliance with applicable regulatory requirements for particulate matter or opacity or cause a safety issue.

 

c)         Compliance Requirements.

 

1)         Emission Control Requirements.

The owner or operator of an EGU that is operating pursuant to this Section must continue to maintain and operate the EGU to comply with the criteria for eligibility for operation under this Section, except during an evaluation of the current sorbent, alternative sorbents, or other techniques to control mercury emissions, as provided by subsection (e) of this Section.

 

2)         Monitoring and Recordkeeping Requirements.

In addition to complying with all applicable monitoring and recordkeeping requirements in Sections 225.240 through 225.290 or Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), and (i)(3) and (4), the owner or operator of a new EGU operating pursuant to this Section must also:

 

A)        Monitor sorbent feed rate to the EGU,  gas flow rate in the stack, and,  if the unit is equipped with activated carbon injection prior to a hot-side electrostatic precipitator, flue gas temperature at the inlet of the hot-side electrostatic precipitator and in the stack.  It must automatically record this data and the sorbent feed rate, in pounds per million actual cubic feet of flue gas at the injection point, on an hourly average.

 

B)        If a blend of bituminous and subbituminous coal is fired in the EGU, maintain records of the amount of each type of coal burned and the required injection rate for injection of sorbent, on a weekly basis.

 

C)        If a mercury control technique other than sorbent injection is approved by the Agency, monitor appropriate parameter for that control technique as specified by the Agency.

 

3)         Notification and Reporting Requirements.

In addition to complying with all applicable reporting requirements of Sections 225.240 through 225.290 or Section 225.239(f)(1) and (2) and (j)(1), the owner or operator of an EGU operating pursuant to this Section must also submit the following notifications and reports to the Agency:

 

A)        Written notification prior to the month in which any of the following events will occur:  the EGU will no longer be eligible to operate under this Section due to a change in operation; the type of coal fired in the EGU will change; the mercury emission standard with which the owner or operator is attempting to comply for the EGU will change; or operation under this Section will be terminated.

 

B)        Quarterly reports for the recordkeeping and monitoring or emissions testing conducted pursuant to subsection (c)(2) of this Section.

 

C)        Annual reports detailing activities conducted for the EGU to further improve control of mercury emissions, including the measures taken during the past year and activities planned for the current year.

 

d)         Applications to Operate under the Technology-Based Standard.

 

1)         Application Deadlines.

 

A)        The owner or operator of an EGU that is seeking to operate the EGU pursuant to this Section must submit an application to the Agency no later than three months prior to the date that compliance with Section 225.237 would otherwise have to be demonstrated. 

 

B)        Unless the Agency finds that the EGU is not eligible to operate pursuant to this Section or that the application for operation under this Section does not meet the requirements of subsection (d)(2) of this Section, the owner or operator of the EGU is authorized to operate the EGU pursuant to this Section beginning 60 days after receipt of the application by the Agency.

 

C)        The owner or operator of an EGU operating pursuant to this Section must reapply to operate pursuant to this Section if it is planning a physical change to or a change in the method of operation of the EGU, control equipment, or practices for injection of sorbent or other mercury control technique that is expected to reduce the level of control of mercury emissions.          

 

2)         Contents of Application.

An application to operate pursuant to this Section must be submitted as an application for a new or revised federally enforceable operating permit for the new EGU, and it must include the following information:

 

A)        A formal request to operate pursuant to this Section showing that the EGU is eligible to operate pursuant to this Section and describing the reason for the request, the measures that have been taken for control of mercury emissions, and factors preventing more effective control of mercury emissions from the EGU.

 

B)        The applicable mercury emission standard in Section 225.237 with which the owner or operator of the EGU is attempting to comply and a summary of relevant mercury emission data for the EGU.

 

C)        If a unit-specific rate or rates for sorbent or other mercury control technique injection are proposed pursuant to subsection (b)(2) of this Section, detailed information to support the proposed injection rates.

 

D)        An action plan describing the measures that will be taken while operating pursuant to this Section to improve control of mercury emissions.  This plan must address measures such as evaluation of alternative forms or sources of sorbent or other mercury control technique, changes to the injection system, changes to operation of the unit that affect the effectiveness of mercury absorption and collection, and changes to other emission control devices.  For each measure contained in the plan, the plan must provide a detailed description of the specific actions that are planned, the reason that the measure is being pursued and the range of improvement in control of mercury that is expected, and the factors that affect the timing for carrying out the measure, with the current schedule for the measure. 

 

e)         Evaluation of Alternative Control Techniques for Mercury Emissions.

 

1)         During an evaluation of the effectiveness of the current sorbent, alternative sorbent, or other technique to control mercury emissions, the owner or operator of an EGU operating pursuant to this Section does not need to comply with the eligibility criteria for operation pursuant to this Section as needed to carry out an evaluation of the practicality and effectiveness of such technique, further subject to the following limitations:

 

A)        The owner or operator of the EGU must conduct the evaluation in accordance with a formal evaluation program that it has submitted to the Agency at least 30 days prior to beginning the evaluation.

 

B)        The duration and scope of the formal evaluation program must not exceed the duration and scope reasonably needed to complete the desired evaluation of the alternative control technique, as initially addressed by the owner or operator in a support document that it has submitted with the formal evaluation program pursuant to subsection (e)(1)(A) of this Section.

 

C)        Notwithstanding 35 Ill. Adm. Code 201.146(hhh), the owner or operator of the EGU must obtain a construction permit for any new or modified air pollution control equipment to be constructed as part of the evaluation of the alternative control technique.

 

D)        The owner or operator of the EGU must submit a report to the Agency no later than 90 days after the conclusion of the formal evaluation program describing the evaluation that was conducted and providing the results of the formal evaluation program.

 

2)         If the evaluation of the alternative control technique shows less effective control of mercury emissions from the EGU than was achieved with the prior control technique, the owner or operator of the EGU must resume use of the prior control technique.  If the evaluation of the alternative control technique shows comparable effectiveness, the owner or operator of the EGU may either continue to use the alternative control technique in an optimum manner or resume use of the prior control technique.  If the evaluation of the alternative control technique shows more effective control of mercury emissions, the owner or operator of the EGU must continue to use the alternative control technique in an optimum manner, if it continues to operate pursuant to this Section.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.239  Periodic Emissions Testing Alternative Requirements

 

a)         General.

 

1)         As an alternative to demonstrating compliance with the emissions standards of Sections 225.230(a) or 225.237(a), the owner or operator of an EGU may elect to demonstrate compliance pursuant to the emission standards in subsection (b) of this Section and the use of quarterly emissions testing as an alternative to the use of CEMS (or an excepted monitoring system);

 

2)         The owner or operator of an EGU that elects to demonstrate compliance pursuant to this Section must comply with the testing, recordkeeping, and reporting requirements of this Section in addition to other applicable recordkeeping and reporting requirements in this Subpart;

 

3)         The alternative method of compliance provided under this subsection may only be used until June 30, 2012, after which a CEMS (or an excepted monitoring system) certified in accordance with Section 225.250 of this Subpart B must be used.

 

4)         If an owner or operator of an EGU demonstrating compliance pursuant to Section 225.230, 225.233(d)(1) or (2), or 225.237, or 225.294(e)(1)(A) discontinues use of a CEMS (or an excepted monitoring system) before collecting a full 12 months of data and elects to demonstrate compliance pursuant to this Section, the data collected prior to that point must be averaged to determine compliance for such period.  In such case, for purposes of calculating an emission standard or mercury control efficiency using the equations in Section 225.230(a) or (b), the "12" in the equations will be replaced by a variable equal to the number of full and partial months for which the owner or operator collected data from a CEMS or an excepted monitoring system.

 

b)         Emission Limits.

 

1)         Existing Units: Beginning July 1, 2009, the owner or operator of a source with one or more EGUs subject to this Subpart B that commenced commercial operation on or before June 30, 2009, must comply with one of the following standards for each EGU, as determined through quarterly emissions testing according to subsections (c), (d), (e), and (f) of this Section:

 

A)        An emission standard of 0.0080 lb mercury/GWh gross electrical output; or

 

B)        A minimum 90-percent reduction of input mercury.

 

2)         New Units: Beginning within the first 2,160 hours after the commencement of commercial operations, the owner or operator of a source with one or more EGUs subject to this Subpart B that commenced commercial operation after June 30, 2009, must comply with one of the following standards for each EGU, as determined through quarterly emissions testing in accordance with subsections (c), (d), (e), and (f) of this Section:

 

A)        An emission standard of 0.0080 lb mercury/GWh gross electrical output; or

 

B)        A minimum 90-percent reduction of input mercury.

 

c)         Initial Emissions Testing Requirements for New Units. The owner or operator of an EGU that commenced commercial operation after June 30, 2009, and that is complying by means of this Section must conduct an initial performance test in accordance with the requirements of subsections (d) and (e) of this Section within the first 2,160 hours after the commencement of commercial operations.

 

d)         Emissions Testing Requirements.

 

1)         Subsequent to the initial performance test, emissions tests must be performed on a quarterly calendar basis in accordance with the requirements of subsections (d), (e), and (f) of this Section;

 

2)         Notwithstanding the provisions in subsection (d)(1), owners or operators of EGUs demonstrating compliance under Section 225.233 or Sections 225.291 through 225.299, and which have not opted into the emission limit provisions of Section 225.233(d)(1) or (d)(2), or Section 225.294(c) pursuant to Section 225.294(e)(1)(B), must perform emissions testing on a semi-annual calendar basis, where the periods consist of the months of January through June and July through December, in accordance with the requirements of subsections (d), (e), and (f)(1) and (2) of this Section;

 

3)         Emissions tests which demonstrate compliance with this Subpart must be performed at least 45 days apart. However, if an emissions test fails to demonstrate compliance with this Subpart or the emissions test is being performed subsequent to a significant change in the operations of an EGU under subsection (h)(2) of this Section, the owner or operator of an EGU may perform additional emissions tests using the same test protocol previously submitted in the same period, with less than 45 days in between emissions tests;

 

4)         A minimum of three and a maximum of nine emissions test runs, lasting at least one hour each, shall be conducted and averaged to determine compliance.  All test runs performed will be reported.

 

5)         If the EGU shares a common stack with one or more other EGUs, the owner or operator of the EGU will conduct emissions testing in the duct to the common stack from each unit, unless the owner or operator of the EGU considers the combined emissions measured at the common stack as the mass emissions of mercury for the EGUs for recordkeeping and compliance purposes.

 

6)         If an owner or operator of an EGU demonstrating compliance pursuant to this Section later elects to demonstrate compliance pursuant to the CEMS monitoring provisions (or excepted monitoring provisions) in Section 225.240 of this Subpart, the owner or operator must comply with the emissions monitoring deadlines in Section 225.240(b)(4) of this Subpart.

 

e)         Emissions Testing Procedures.

 

1)         The owner or operator must conduct a compliance test in accordance with Method 29, 30A, or 30B of 40 CFR 60, Appendix A, as incorporated by reference in Section 225.140;

 

2)         Mercury emissions or control efficiency must be measured while the affected unit is operating at or above 90% of peak load;

 

3)         For units complying with the control efficiency standard of subsection (b)(1)(B) or (b)(2)(B) of this Section, Section 225.233(d)(1)(B) or (d)(2)(B) and electing to demonstrate compliance pursuant to Section 225.233(d)(4), or Section 225.294(c)(2) pursuant to Section 225.294(e)(1)(B), the owner or operator must perform coal sampling as follows:

 

A)        in accordance with Section 225.265 of this Subpart at least once during each day of testing; and

 

B)        in accordance with Section 225.265 of this Subpart, once each month in those months when emissions testing is not performed unless the boiler did not operate or combust coal at all during the month;

 

4)         For units complying with the output-based emission standard of subsection (b)(1)(A) or (b)(2)(A) of this Section, the owner or operator must monitor gross electrical output for the duration of the testing.

 

5)         The owner or operator of an EGU may use an alternative emissions testing method if such alternative is submitted to the Agency in writing and approved in writing by the Manager of the Bureau of Air's Compliance Section.

 

f)         Notification Requirements.

 

1)         The owner or operator of an EGU must submit a testing protocol as described in USEPA's Emission Measurement Center's Guideline Document #42 to the Agency at least 45 days prior to a scheduled emissions test, except as provided in Section 225.239(h)(2) and (h)(3).  Upon written request directed to the Manager of the Bureau of Air's Compliance Section, the Agency may, in its sole discretion, waive the 45-day requirement. Such waiver shall only be effective if it is provided in writing and signed by the Manager of the Bureau of Air's Compliance Section, or his or her designee;

 

2)         Notification of a scheduled emissions test must be submitted to the Agency in writing, directed to the Manager of the Bureau of Air's Compliance Section, at least 30 days prior to the expected date of the emissions test. Upon written request directed to the Manager of the Bureau of Air's Compliance Section, the Agency may, in its sole discretion,  waive the 30-day notification requirement.  Such waiver shall only be effective if it is provided in writing and signed by the Manager of the Bureau of Air's Compliance Section, or his or her designee. Notification of the actual date and expected time of testing must be submitted in writing, directed to the Manager of the Bureau of Air's Compliance Section, at least five working days prior to the actual date of the test;

 

3)         For an EGU that has elected to demonstrate compliance by use of the emission standards of subsection (b) of this Section, if an emissions test performed under the requirements of this Section fails to demonstrate compliance with the limits of subsection (b) of this Section, the owner or operator of an EGU may perform a new emissions test using the same test protocol previously submitted in the same period, by notifying the Manager of the Bureau of Air's Compliance Section or his or her designee of the actual date and expected time of testing at least five working days prior to the actual date of the test. The Agency may, in its sole discretion,   waive this five-day notification requirement. Such waiver shall only be effective if it is provided in writing and signed by the Manager of the Bureau of Air's Compliance Section, or his or her designee;

 

4)         In addition to the testing protocol required by subsection (f)(1) of this Section, the owner or operator of an EGU that has elected to demonstrate compliance by use of the emission standards of subsection (b) of this Section, that opts into Section 225.233(d)(1) or (d)(2) early and elects to demonstrate compliance pursuant to Section 225.233(d)(4), or that opts into Section 225.294(c) pursuant to Section 225.294(e)(1)(B), must submit a Continuous Parameter Monitoring Plan to the Agency at least 45 days prior to a scheduled emissions test.  Upon written request directed to the Manager of the Bureau of Air's Compliance Section, the Agency may, in its sole discretion, waive the 45-day requirement. The waiver shall only be effective if it is provided in writing and signed by the Manager of the Bureau of Air's Compliance Section, or his or her designee. The Continuous Parameter Monitoring Plan must detail how the EGU will continue to operate within the parameters enumerated in the testing protocol and how those parameters will ensure compliance with the applicable mercury limit. For example, the Continuous Parameter Monitoring Plan must include coal sampling as described in Section 225.239(e)(3) of this Subpart and must ensure that an EGU that performs an emissions test using a blend of coals continues to operate using that same blend of coal.  If the Agency disapproves the Continuous Parameter Monitoring Plan, the owner or operator of the EGU has 30 days from the date of receipt of the disapproval to submit more detailed information in accordance with the Agency's request.

 

g)         Compliance Determination.

 

1)         Each successful quarterly emissions test shall determine compliance with this Subpart for that quarter, except for days in the quarter before and after a failed test and until a successful re-test as described in subsection (g)(2) of this Section, where the quarterly periods consist of the months of January through March, April through June, July through September, and October through December;

 

2)         If emissions testing conducted pursuant to this Section fails to demonstrate compliance, the owner or operator of the EGU will be deemed to have been out of compliance with this Subpart beginning on the first day of the current quarter, the last day of certified CEMS data (or certified data from an excepted monitoring system) demonstrating compliance, or the date on which a significant change was made pursuant to subsection (h)(2) of this Section if such a change was made, whichever is later; the EGU will remain out of compliance until a subsequent emissions test successfully demonstrates compliance with the limits of this Section.

 

h)         Operation Requirements.

 

1)         The owner or operator of an EGU that has elected to demonstrate compliance by use of the emission standards of subsection (b) of this Section must continue to operate the EGU commensurate with the Continuous Parameter Monitoring Plan until another Continuous Parameter Monitoring Plan is developed and submitted to the Agency in conjunction with the next compliance demonstration, in accordance with subsection (f)(4) of this Section.

 

2)         If the owner or operator makes a significant change to the operations of an EGU subject to this Section, such as changing from bituminous to subbituminous coal or any other change that would render the most recent test no longer representative of current operations according to the parameters listed in the Continuous Parameter Monitoring Plan, the owner or operator must submit a testing protocol to the Agency within seven operating days of the significant change and perform an emissions test within 30 days after the change if the change takes place more than 30 days before the end of the current calendar quarter, or within 30 days of the beginning of the new quarter if the change takes place less than 30 days before the end of the current calendar quarter. In addition, the owner or operator of an EGU that has elected to demonstrate compliance by use of the emission standards of subsection (b) of this Section, Section 225.233(d)(1) or (d)(2), or Section 225.294(c) pursuant to Section 225.294(e)(1)(B) must submit an updated Continuous Parameter Monitoring Plan within seven operating days of the significant change.

 

3)         If a blend of bituminous and subbituminous coal is fired in the EGU, the owner or operator of the EGU must ensure that the EGU continues to operate using the same blend that was used during the most recent successful emissions test. If the blend of coal changes, the owner or operator of the EGU must re-test in accordance with subsections (d), (e), (f), and (g) of this Section within 30 days of the change in coal blend, notwithstanding the requirement of subsection (d)(3) of this Section that there must be 45 days between emissions tests.

 

i)          Recordkeeping.

 

1)         The owner or operator of an EGU must comply with all applicable recordkeeping and reporting requirements in this Section.

 

2)         Continuous Parameter Monitoring.  The owner or operator of an EGU must maintain records to substantiate that the EGU is operating in compliance with the parameters listed in the Continuous Parameter Monitoring Plan, detailing the parameters that impact mercury reduction and including the following records related to the emissions of mercury:

 

A)        For an EGU for which the owner or operator is complying with this Subpart B pursuant to Section 225.239(b)(1)(B) or 225.239(b)(2)(B), records of the daily mercury content of coal used (parts per million) and the daily and quarterly input mercury (lbs).

 

B)        For an EGU for which the owner or operator of an EGU complying with this Subpart B pursuant to Section 225.239(b)(1)(A) or 225.239(b)(2)(A), records of the daily and quarterly gross electrical output (MWh) on an hourly basis.

 

3)         The owner or operator of an EGU using activated carbon injection must also comply with the following requirements

 

A)        Maintain records of the usage of sorbent, the exhaust gas flow rate from the EGU, and the sorbent feed rate, in pounds per million actual cubic feet of exhaust gas at the injection point, on a weekly average;

 

B)        If a blend of bituminous and subbituminous coal is fired in the EGU, keep records of the amount of each type of coal burned and the required injection rate for injection of activated carbon, on a weekly basis.

 

4)         The owner or operator of an EGU must retain all records required by this Section at the source for a period of five years from the date the document is created, unless otherwise provided in the CAAPP permit issued for the source, and must make a copy of any record available to the Agency promptly upon request.  This period may be extended in writing by the Agency, for cause, at any time prior to the end of five years.

 

5)         The owner or operator of an EGU demonstrating compliance pursuant to this Section must monitor and report the heat input rate at the unit level.

 

6)         The owner or operator of an EGU demonstrating compliance pursuant to this Section must perform and report coal sampling in accordance with subsection 225.239(e)(3).

 

j)          Reporting Requirements.

 

1)         An owner or operator of an EGU shall submit to the Agency a Final Source Test Report for each periodic emissions test within 45 days after the test is completed.  The Final Source Test Report will be directed to the Manager of the Bureau of Air's Compliance Section, or his or her designee, and include at a minimum:

 

A)        A summary of results;

 

B)        A description of test methods, including a description of sampling points, sampling train, analysis equipment, and test schedule, and a detailed description of test conditions, including:

 

i)          Process information, including but not limited to modes of operation, process rate, and fuel or raw material consumption;

 

ii)         Control equipment information (i.e., equipment condition and operating parameters during testing);

 

iii)        A discussion of any preparatory actions taken (i.e., inspections, maintenance, and repair); and

 

iv)        Data and calculations, including copies of all raw data sheets and records of laboratory analyses, sample calculations, and data on equipment calibration.

 

2)         The owner or operator of a source with one or more EGUs demonstrating compliance with Subpart B in accordance with this Section must submit to the Agency a Quarterly Certification of Compliance within 45 days following the end of each calendar quarter. Quarterly certifications of compliance must certify whether compliance existed for each EGU for the calendar quarter covered by the certification. If the EGU failed to comply during the quarter covered by the certification, the owner or operator must provide the reasons the EGU or EGUs failed to comply and a full description of the noncompliance (i.e., tested emissions rate, coal sample data, etc.). In addition, for each EGU, the owner or operator must provide the following appropriate data to the Agency as set forth in this Section.

 

A)        A list of all emissions tests performed within the calendar quarter covered by the Certification and submitted to the Agency for each EGU, including the dates on which such tests were performed.

 

B)        Any deviations or exceptions each month and discussion of the reasons for such deviations or exceptions.

 

C)        All Quarterly Certifications of Compliance required to be submitted must include the following certification by a responsible official:

 

I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted.  Based on my inquiry of the person or persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete.  I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.

 

3)         Deviation Reports.  For each EGU, the owner or operator must promptly notify the Agency of deviations from any of the requirements of this Subpart B.  At a minimum, these notifications must include a description of such deviations within 30 days after discovery of the deviations, and a discussion of the possible cause of such deviations, any corrective actions, and any preventative measures taken.

 

(Source:  Added at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.240  General Monitoring and Reporting Requirements

 

Except as otherwise indicated in this Subpart, the owner or operator of an EGU must comply with the monitoring, recordkeeping, and reporting requirements as provided in this Section, Sections 225.250 through 225.290 of this Subpart B, and Sections 1.14 through 1.18 of Appendix B to this Part.  If the EGU utilizes a common stack with units that are not EGUs and the owner or operator of the EGU does not conduct emissions monitoring in the duct to the common stack from each EGU, the owner or operator of the EGU must conduct emissions monitoring in accordance with Section 1.16(b)(2) of Appendix B to this Part  and this Section, including monitoring in the duct to the common stack from each unit that is not an EGU, unless the owner or operator of the EGU counts the combined emissions measured at the common stack as the mass emissions of mercury for the EGUs for recordkeeping and compliance purposes.

 

a)         Requirements for installation, certification, and data accounting.  The owner or operator of each EGU must:

 

1)         Install all monitoring systems required pursuant to this Section and Sections 225.250 through 225.290 for monitoring mercury mass emissions (including all systems required to monitor mercury concentration, stack gas moisture content, stack gas flow rate, and CO₂ or O₂ concentration, as applicable, in accordance with Sections 1.15 and 1.16 of Appendix B to this Part).

 

2)         Successfully complete all certification tests required pursuant to Section 225.250 and meet all other requirements of this Section, Sections 225.250 through 225.290, and Sections 1.14 through 1.18 of Appendix B to this Part applicable to the monitoring systems required under subsection (a)(1) of this Section.

 

3)         Record, report, and assure the quality of the data from the monitoring systems required under subsection (a)(1) of this Section.

 

4)         If the owner or operator elects to use the low mass emissions excepted monitoring methodology for an EGU that emits no more than 464 ounces (29 pounds) of mercury per year pursuant to Section 1.15(b) of Appendix B to this Part, it must perform emissions testing in accordance with Section 1.15(c) of Appendix B to this Part to demonstrate that the EGU is eligible to use this excepted emissions monitoring methodology, as well as comply with all other applicable requirements of Section 1.15(b) through (f) of Appendix B to this Part.  Also, the owner or operator must submit a copy of any information required to be submitted to the USEPA pursuant to these provisions to the Agency.  The initial emissions testing to demonstrate eligibility of an EGU for the low mass emissions excepted methodology must be conducted by the applicable of the following dates:

 

A)        If the EGU has commenced commercial operation before July 1, 2008, at least by July 1, 2009, or 45 days prior to relying on the low mass emissions excepted methodology, whichever date is later.

 

B)        If the EGU has commenced commercial operation on or after July 1, 2008, at least 45 days prior to the applicable date specified pursuant to subsection (b)(2) of this Section or 45 days prior to relying on the low mass emissions excepted methodology, whichever date is later.

 

b)         Emissions Monitoring Deadlines.  The owner or operator must meet the emissions monitoring system certification and other emissions monitoring requirements of subsections (a)(1) and (a)(2) of this Section on or before the applicable of the following dates.  The owner or operator must record, report, and quality-assure the data from the emissions monitoring systems required under subsection (a)(1) of this Section on and after the applicable of the following dates:

 

1)         For the owner or operator of an EGU that commences commercial operation before July 1, 2008, by July 1, 2009, except that an EGU in an MPS Group for which an SO₂ scrubber or fabric filter is being installed to be in operation by December 31, 2009, as described in Section 225.233(c)(1)(A), shall have a date of January 1, 2010.

 

2)         For the owner or operator of an EGU that commences commercial operation on or after July 1, 2008, by 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which the EGU commences commercial operation.

 

3)         For the owner or operator of an EGU for which construction of a new stack or flue or installation of add-on mercury emission controls, a flue gas desulfurization system, a selective catalytic reduction system, a fabric filter, or a compact hybrid particulate collector system is completed after the applicable deadline pursuant to subsection (b)(1) or (b)(2) of this Section, by 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which emissions first exit to the atmosphere through the new stack or flue, add-on mercury emission controls, flue gas desulfurization system, selective catalytic reduction system, fabric filter, or compact hybrid particulate collector system.

 

4)         For an owner or operator of an EGU that originally elected to demonstrate compliance pursuant to the emissions testing requirements in Section 225.239, by the first day of the calendar quarter following the last emissions test demonstrating compliance with Section 225.239. 

 

c)         The owner or operator of an EGU that does not meet the applicable emissions monitoring date set forth in subsection (b) of this Section for any emissions monitoring system required pursuant to subsection (a)(1) of this Section must begin periodic emissions testing in accordance with Section 225.239.

 

d)         Prohibitions.

 

1)         No owner or operator of an EGU may use any alternative emissions monitoring system, alternative reference method for measuring emissions, or other alternative to the emissions monitoring and measurement requirements of this Section and Sections 225.250 through 225.290, unless such alternative is submitted to the Agency in writing and approved in writing by the Manager of the Bureau of Air’s Compliance Section, or his or her designee.

 

2)         No owner or operator of an EGU may operate its EGU so as to discharge, or allow to be discharged, mercury emissions to the atmosphere without accounting for such emissions in accordance with the applicable provisions of this Section, Sections 225.250 through 225.290, and Sections 1.14 through 1.18 of Appendix B to this Part, unless demonstrating compliance pursuant to Section 225.239, as applicable.

 

3)         No owner or operator of an EGU may disrupt the CEMS (or excepted monitoring system), any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording mercury mass emissions discharged into the atmosphere, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the applicable provisions of this Section, Sections 225.250 through 225.290, and Sections 1.14 through 1.18 of Appendix B to this Part.

 

4)         No owner or operator of an EGU may retire or permanently discontinue use of the CEMS (or excepted monitoring system) or any component thereof, or any other approved monitoring system pursuant to this Subpart B, except under any one of the following circumstances:

 

A)        The owner or operator is monitoring emissions from the EGU with another certified monitoring system that has been approved, in accordance with the applicable provisions of this Section, Sections 225.250 through 225.290 of this Subpart B, and Sections 1.14 through 1.18 of Appendix B to this Part, by the Agency for use at that EGU and that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or

 

B)        The owner or operator submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with Section 225.250(a)(3)(A).

 

C)        The owner or operator is demonstrating compliance pursuant to the applicable subsections of Section 225.239.

 

e)         Long-term Cold Storage.

The owner or operator of an EGU that is in long-term cold storage is subject to the provisions of 40 CFR 75.4 and 40 CFR 75.64, incorporated by reference in Section 225.140, relating to monitoring, recordkeeping, and reporting for units in long-term cold storage.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.250  Initial Certification and Recertification Procedures for Emissions Monitoring

 

a)         The owner or operator of an EGU must comply with the following initial certification and recertification procedures for a CEMS (or an excepted monitoring system pursuant to Section 1.3 of Appendix B to this Part) required by Section 225.240(a)(1).  The owner or operator of an EGU that qualifies for, and for which the owner or operator elects to use, the low-mass-emissions excepted methodology pursuant to Section 1.15(b) of Appendix B to this Part, must comply with the procedures set forth in subsection (c) of this Section.  

 

1)         Requirements for Initial Certification.  The owner or operator of an EGU must ensure that, for each CEMS (or excepted monitoring system) required by Section 225.240(a)(1) (including the automated data acquisition and handling system), the owner or operator successfully completes all of the initial certification testing required pursuant to Section 1.4 of Appendix B to this Part, by the applicable deadline in Section 225.240(b).  In addition, whenever the owner or operator of an EGU installs a monitoring system to meet the requirements of this Subpart B in a location where no such monitoring system was previously installed, the owner or operator must successfully complete the initial certification requirements of Section 1.4 of Appendix B to this Part.

 

2)         Requirements for Recertification.  Whenever the owner or operator of an EGU makes a replacement, modification, or change in any certified CEMS, or an excepted monitoring system pursuant to Section 1.3 of Appendix B to this Part, and required by Section 225.240(a)(1), that may significantly affect the ability of the system to accurately measure or record mercury mass emissions or heat input rate or to meet the quality-assurance and quality-control requirements of Section 1.5 of Appendix B to this Part  or Exhibit B to Appendix B to this Part, the owner or operator of an EGU must recertify the monitoring system in accordance with Section 1.4(b) of Appendix B to this Part.  Furthermore, whenever the owner or operator of an EGU makes a replacement, modification, or change to the flue gas handling system or the EGU's operation that may significantly change the stack flow or concentration profile, the owner or operator must recertify each CEMS, and each excepted monitoring system  pursuant to Section 1.3 to Appendix B to this Part, whose accuracy is potentially affected by the change, all in accordance with Section 1.4(b) to Appendix B to this Part.  Examples of changes to a CEMS that require recertification include, but are not limited to, replacement of the analyzer, complete replacement of an existing CEMS, or change in location or orientation of the sampling probe or site.

 

3)         Approval Process for Initial Certification and Recertification.  Subsections (a)(3)(A) through (a)(3)(D) of this Section apply to both initial certification and recertification of a CEMS (or an excepted monitoring system) required by Section 225.240(a)(1).  For recertifications, the words "certification" and "initial certification" are to be read as the word "recertification", the word "certified" is to be read as the word "recertified", and the procedures set forth in Section 1.4(b)(5) of Appendix B to this Part  are to be followed in lieu of the procedures set forth in subsection (a)(3)(E) of this Section.

 

A)        Notification of Certification.  The owner or operator must submit written notice of the dates of certification testing to the Agency directed to the Manager of the Bureau of Air's Compliance Section, in accordance with Section 225.270.

 

B)        Certification Application.  The owner or operator must submit to the Agency a certification application for each monitoring system.  A complete certification application must include the information specified in 40 CFR 75.63, incorporated by reference in Section 225.140.

 

C)        Provisional Certification Date.  The provisional certification date for a monitoring system must be determined in accordance with Section 1.4(a)(3) of Appendix B to this Part.  A provisionally certified monitoring system may be used pursuant to this Subpart B for a period not to exceed 120 days after receipt by the Agency of the complete certification application for the monitoring system pursuant to subsection (a)(3)(B) of this Section.  Data measured and recorded by the provisionally certified monitoring system, in accordance with the requirements of Appendix B to this Part, will be considered valid quality-assured data (retroactive to the date and time of provisional certification), provided that the Agency does not invalidate the provisional certification by issuing a notice of disapproval within 120 days after the date of receipt by the Agency of the complete certification application.

 

D)        Certification Application Approval Process.  The Agency must issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days after receipt of the complete certification application required by subsection (a)(3)(B) of this Section.  In the event the Agency does not issue a written notice of approval or disapproval within the 120-day period, each monitoring system that meets the applicable performance requirements of Appendix B to this Part and which is included in the certification application will be deemed certified for use pursuant to this Subpart B.

 

i)          Approval Notice.  If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of Appendix B to this Part, then the Agency must issue a written notice of approval of the certification application within 120 days after receipt.

 

ii)         Incomplete Application Notice.  If the certification application is not complete, then the Agency must issue a written notice of incompleteness that sets a reasonable date by which the owner or operator must submit the additional information required to complete the certification application.  If the owner or operator does not comply with the notice of incompleteness by the specified date, the Agency may issue a notice of disapproval pursuant to subsection (a)(3)(D)(iii) of this Section.  The 120-day review period will not begin before receipt of a complete certification application.

 

iii)        Disapproval Notice.  If the certification application shows that any monitoring system does not meet the performance requirements of Appendix B to this Part, or if the certification application is incomplete and the requirement for disapproval pursuant to subsection (a)(3)(D)(ii) of this Section is met, the Agency must issue a written notice of disapproval of the certification application.  Upon issuance of such notice of disapproval, the provisional certification is invalidated, and the data measured and recorded by each uncertified monitoring system will not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined pursuant to Section 1.4(a)(3) of Appendix B to this Part).  The owner or operator must follow the procedures for loss of certification set forth in subsection (a)(3)(E) of this Section for each monitoring system that is disapproved for initial certification.

 

iv)        Audit Decertification.  The Agency may issue a notice of disapproval of the certification status of a monitor in accordance with Section 225.260(c).

 

E)        Procedures for Loss of Certification.  If the Agency issues a notice of disapproval of a certification application pursuant to subsection (a)(3)(D)(iii) of this Section or a notice of disapproval of certification status pursuant to subsection (a)(3)(D)(iv) of this Section, the owner or operator must fulfill the following requirements:

 

i)          The owner or operator must submit a notification of certification retest dates and a new certification application in accordance with subsections (a)(3)(A) and (B) of this Section.

 

ii)         The owner or operator must repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Agency's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.

 

b)         Exemption.

 

1)         If an emissions monitoring system has been previously certified in accordance with Appendix B to this Part  and the applicable quality assurance and quality control requirements of Section 1.5 and Exhibit B to Appendix B to this Part  are fully met, the monitoring system will be exempt from the initial certification requirements of this Section. 

 

2)         The recertification provisions of this Section apply to an emissions monitoring system required by Section 225.240(a)(1) exempt from initial certification requirements pursuant to subsection (a)(1) of this Section.

 

c)         Initial certification and recertification procedures for EGUs using the mercury low mass emissions excepted methodology pursuant to Section 1.15(b) of Appendix B to this Part.  The owner or operator that has elected to use the mercury-low-mass-emissions-excepted methodology for a qualified EGU pursuant to Section 1.15(b) to Appendix B to this Part  must meet the applicable certification and recertification requirements in Section 1.15(c) through (f) to Appendix B to this Part.

 

d)         Certification Applications.  The owner or operator of an EGU must submit an application to the Agency within 45 days after completing all initial certification or recertification tests required pursuant to this Section, including the information required pursuant to 40 CFR 75.63, incorporated by reference in Section 225.140.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.260  Out of Control Periods and Data Availability for Emission Monitors

 

a)         Out of control periods must be determined in accordance with Section 1.7 of Appendix B.

 

b)         Monitor data availability for all EGUs using a CEMS (or an excepted monitoring system) shall be greater than or equal to 75 percent; that is, quality assured data must be recorded by a certified primary monitor, a certified redundant or non-redundant backup monitor, or reference method for that unit at least 75 percent of the time the unit is in operation.   Monitor data availability must be determined in accordance with Section 1.8 of Appendix B following initial certification of the required CO₂, O₂, flow monitor, or mercury concentration or moisture monitoring systems at a particular unit or stack location; monitor data availability shall be determined on a calendar quarterly basis until June 30, 2012, and on a rolling 12-month average basis from July 1, 2012 forward (the first such 12-month period will cover July 1, 2012 through June 30, 2013).  Compliance with the percent reduction standard in Section 225.230(a)(1)(B), 225.233(d)(1)(B) or (d)(2)(B), 225.237(a)(1)(B), or 225.294(c)(2), or the emissions concentration standard in Section 225.230(a)(1)(A), 225.233(d)(1)(A) or (d)(2)(A), 225.237(a)(1)(A), or 225.294(c)(1), can only be demonstrated if the monitor data availability is equal to or greater than 75 percent.

 

c)         Audit Decertification.  Whenever both an audit of an emissions monitoring system and a review of the initial certification or recertification application reveal that any emissions monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement pursuant to Section 225.250 or the applicable provisions of Appendix B to this Part, both at the time of the initial certification or recertification application submission and at the time of the audit, the Agency must issue a notice of disapproval of the certification status of such monitoring system.  For the purposes of this subsection (c), an audit must be either a field audit or an audit of any information submitted to the Agency.  By issuing the notice of disapproval, the Agency revokes prospectively the certification status of the emissions monitoring system.  The data measured and recorded by the monitoring system must not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system.  The owner or operator shall follow the applicable initial certification or recertification procedures in Section 225.250 for each disapproved monitoring system.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.261  Additional Requirements to Provide Heat Input Data

 

The owner or operator of an EGU that monitors and reports mercury mass emissions using a mercury concentration monitoring system and a flow monitoring system must also monitor and report the heat input rate at the EGU level using the procedures set forth in Appendix B to this Part.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.263  Monitoring of Gross Electrical Output

 

The owner or operator of an EGU complying with this Subpart B by means of Section 225.230(a)(1) or using electrical output (O_i) and complying by means of Section 225.230(b) or (d) or Section 225.232 must monitor gross electrical output of the associated generator(s) in MWh on an hourly basis.

 

Section 225.265  Coal Analysis for Input Mercury Levels

 

a)         The owner or operator of an EGU complying with this Subpart B by means of Section 225.230(a)(1)(B); using input mercury levels (I_i) and complying by means of Section 225.230(b) or (d) or Section 225.232; electing to comply with the emissions testing, monitoring, and recordkeeping requirements under Section 225.239; demonstrating compliance under Section 225.233, except an EGU in an MPS Group that elects to comply with the emission standard in Section 225.233(d)(1)(A) or (d)(2)(A); or demonstrating compliance under Sections 225.291 through 225.299, except an EGU in a CPS Group that elects to comply with the emission standard in Section 225.294(c)(1) or that opts into the emission standard in Section 225.294(c)(1) pursuant to Section 225.294(e)(1) or that has permanently ceased combusting coal must fulfill the following requirements:

 

1)         Perform sampling of the coal combusted in the EGU for mercury content.  The owner or operator of such EGU must collect a minimum of one 2-lb. grab sample from the belt feeders anywhere between the crusher house or breaker building and the boiler or, in cases in which a crusher house or breaker building is not present, at a reasonable point close to the boiler of a subject EGU, according to the schedule in subsections (a)(1)(A) through (C).  The sample must be taken in a manner that provides a representative mercury content for the coal burned on that day.  If multiple samples are tested, the owner or operator must average those tests to arrive at the final mercury content for that time period.  The owner or operator of the EGU must perform coal sampling as follows:

 

A)        EGUs complying by means of Section 225.233, except an EGU in an MPS Group that elects to comply with the control efficiency standard in Section 225.233(d)(1)(B) or (d)(2)(B) or elects to comply with Section 225.233(d)(4), or Sections 225.291 through 225.299, except an EGU in a CPS Group that elects to comply with the control efficiency standard in Section 225.294(c)(2) or that opts into the emission standard in Section 225.294(c)(2) pursuant to Section 225.294(e)(1) must perform such coal sampling at least once per month unless the boiler did not operate or combust coal at all during that month;

 

B)        EGUs complying by means of the emissions testing, monitoring, and recordkeeping requirements under Section 225.239 or Section 225.233(d)(4), or EGUs that opt into the emission standard in Section 225.294(c)(2) pursuant to Section 225.294(e)(1)(B), must perform such coal sampling according to the schedule provided in Section 225.239(e)(3) of this Subpart;

 

C)        All other EGUs subject to this requirement, including EGUs in an MPS or CPS Group electing to comply with the control efficiency standard in Section 225.233(d)(1)(B) or (d)(2)(B), Section 225.294(c)(2), or Section 225.294(c)(2) pursuant to Section 225.294(e)(1)(A), must perform such coal sampling on a daily basis when the boiler is operating and combusting coal.

 

2)         Analyze the grab coal sample for the following:

 

A)        Determine the heat content using ASTM D5865-04 or an equivalent method approved in writing by the Agency.

 

B)        Determine the moisture content using ASTM D3173-03 or an equivalent method approved in writing by the Agency.

 

C)        Measure the mercury content using ASTM D6414-01, ASTM D3684-01, ASTM D6722-01, or an equivalent method approved in writing by the Agency.

 

3)         The owner or operator of multiple EGUs at the same source using the same crusher house or breaker building may take one sample per crusher house or breaker building, rather than one per EGU.

 

4)         The owner or operator of an EGU must use the data analyzed pursuant to subsection (b) of this Section to determine the mercury content in terms of parts per million.

 

b)         The owner or operator of an EGU that must conduct sampling and analysis of coal pursuant to subsection (a) of this Section must begin such activity by the following date:

 

1)         If the EGU is in daily service, at least 30 days before the start of the month for which such activity will be required.

 

2)         If the EGU is not in daily service, on the day that the EGU resumes operation.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.270  Notifications

 

The owner or operator of a source with one or more EGUs must submit written notice to the Agency according to the provisions in 40 CFR 75.61, incorporated by reference in Section 225.140, for each EGU or group of EGUs monitored at a common stack and each non-EGU monitored pursuant to Section 1.16(b)(2)(B) of Appendix B to this Part.

 

(Source:  Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.290  Recordkeeping and Reporting

 

a)         General Provisions.

 

1)         Except as otherwise indicated in this Subpart, the owner or operator of an EGU must comply with all applicable recordkeeping and reporting requirements in this Section and with all applicable recordkeeping and reporting requirements of Section 1.18 to Appendix B to this Part.

 

2)         The owner or operator of an EGU must maintain records for each month identifying the emission standard in Section 225.230(a) or 225.237(a) of this Section with which it is complying or that is applicable for the EGU and the following records related to the emissions of mercury that the EGU is allowed to emit:

 

A)        For an EGU for which the owner or operator is complying with this Subpart B by means of Section 225.230(a)(1)(B) or 225.237(a)(1)(B) or using input mercury levels to determine the allowable emissions of the EGU, records of the daily mercury content of coal used (parts per million) and the daily and monthly input mercury (lbs), which must be kept in the file pursuant to Section 1.18(a) of Appendix B to this Part.

 

B)        For an EGU for which the owner or operator of an EGU complying with this Subpart B by means of Section 225.230(a)(1)(A) or 225.237(a)(1)(A) or using electrical output to determine the allowable emissions of the EGU, records of the daily and monthly gross electrical output (GWh), which must be kept in the file required pursuant to Section 1.18(a) of Appendix B to this Part.

 

3)         The owner or operator of an EGU must maintain records of the following data for each EGU:

 

A)        Monthly emissions of mercury from the EGU.

 

B)        For an EGU for which the owner or operator is complying by means of Section 225.230(b) or (d) of this Subpart B, records of the monthly allowable emissions of mercury from the EGU.

 

4)         The owner or operator of an EGU that is participating in an Averaging Demonstration pursuant to Section 225.232 of this Subpart B must maintain records identifying all sources and EGUs covered by the Demonstration for each month and, within 60 days after the end of each calendar month, calculate and record the actual and allowable mercury emissions of the EGU for the month and the applicable 12-month rolling period.

 

5)         The owner or operator of an EGU must maintain the following records related to quality assurance activities conducted for emissions monitoring systems:

 

A)        The results of quarterly assessments conducted pursuant to Section 2.2 of Exhibit B to Appendix B to this Part; and

 

B)        Daily/weekly system integrity checks pursuant to Section 2.6 of Exhibit B to Appendix B to this Part. 

 

6)         The owner or operator of an EGU must retain all records required by this Section at the source for a period of five years from the date the document is created unless otherwise provided in the CAAPP permit issued for the source and must make a copy of any record available to the Agency upon request.  This period may be extended in writing by the Agency, for cause, at any time prior to the end of five years.

 

b)         Quarterly Reports.  The owner or operator of a source with one or more EGUs using CEMS or excepted monitoring systems at any time during a calendar quarter must submit quarterly reports to the Agency as follows:

 

1)         Source information such as source name, source ID number, and the period covered by the report.

 

2)         A list of all EGUs at the source that identifies the applicable Part 225 monitoring and reporting requirements with which each EGU is complying for the reported quarter, including the following EGUs, which are excluded from subsection (b)(3) of this Section:

 

A)        All EGUs using the periodic emissions testing provisions of Section 225.239, 225.233(d)(4), or Section 225.294(c) pursuant to Section 225.294(e)(1)(B) for the quarter.

 

B)        All EGUs using the low mass emissions (LME) excepted monitoring methodology pursuant to Section 1.15(b) of Appendix B to this Part.

 

3)         For only those EGUs using CEMS or excepted monitoring systems at any time during a calendar quarter:

 

A)        An indication of whether the identified EGUs were in compliance with all applicable monitoring, recordkeeping, and reporting requirements of Part 225 for the entire reporting period.

 

B)        The total quarterly operating hours of each EGU.

 

C)        The CEMS or excepted monitoring system QAMO hours on a quarterly basis and percentage data availability on a quarterly or rolling 12-month basis (for each concluding 12-month period in that quarter), as appropriate according to the schedule provided in Section 225.260(b).  The data availability shall be determined in accordance with Section 1.8 (CEMS) or 1.9 (excepted monitoring system) of Appendix B to this Part.

 

D)        The average monthly mercury concentration of the coal combusted in each EGU in parts per million (determined by averaging all analyzed coal samples in the month) and the quarterly total amount of mercury (calculated by multiplying the total amount of coal combusted each month by the average monthly mercury concentration and converting to ounces, then adding together for the quarter) of the coal combusted in each EGU. If the EGU is complying by means of Section 225.230(a)(1)(A), 225.233(d)(1)(A), 225.233(d)(2)(A) or 225.294(c)(1), reporting of the data in this subsection (b)(3)(D) is not required.

 

E)        The quarterly mercury mass emissions (in ounces), determined from the QAMO hours in accordance with Section 4.2 of Exhibit C to Appendix B to this Part. If the EGU is complying by means of Section 225.230(a)(1)(A), 225.233(d)(1)(A), 225.233(d)(2)(A), or 225.294(c)(1), reporting of the data in this subsection (b)(3)(E) is not required.

 

F)         The average monthly and quarterly mercury control efficiency. This is determined by dividing the mercury mass emissions recorded during QAMO hours, calculated each month and quarter, by the total amount of mercury in the coal combusted weighted by the monitor availability (total mercury content multiplied by the percent monitor availability, or QAMO hours divided by total hours) for each month and quarter.  If the DAHS for the EGU has the ability to record the amount of coal combusted during QAMO hours, the average monthly and quarterly control efficiency shall be reported without the calculation in this subsection (b)(3)(F). If the EGU is complying by means of Section 225.230(a)(1)(A), 225.233(d)(1)(A), 225.233(d)(2)(A) or 225.294(c)(1), reporting of the data in this subsection (b)(3)(F) is not required.

 

G)        The average monthly and quarterly mercury emission rate (in lb/GWh) for each EGU, determined in accordance with Section 225.230(a)(2). Only those EGUs complying by means of Section 225.230(a)(1)(A), 225.233(d)(1)(A), 225.233(d)(2)(A) or 225.294(c)(1) are required to report the data in this subsection (b)(3)(G).

 

H)        The 12-month rolling average control efficiency (percentage) or emission rate (in lb/GWh) for each month in the reporting period,  as applicable (or the rolling average control efficiency or emission rate for a lesser number of months if a full 12 months of data is not available). This applicable data is determined according to the following requirements:

 

i)          The 12-month rolling average control efficiency is required for those sources complying by means of Section 225.230(a)(1)(B), 225.233(d)(1)(B), 225.233(d)(2)(B), 225.294(c)(2), 225.230(b), 225.230(d), 225.232(b)(2), or 225.237(a)(1)(B).

 

ii)         The 12-month rolling average emission rate is required for those sources complying by means of Section 225.230(a)(1)(A), 225.233(d)(1)(A), 225.233(d)(2)(A), or 225.294(c)(1), 225.230(b), 225.230(d), 225.232(b)(1), or 225.237(a)(1)(A).

 

I)         If the CEMS or excepted monitoring system percentage data availability was less than 95.0 percent of the total operating time for the EGU, the date and time identifying each period during which the CEMS was inoperative, except for routine zero and span checks; the nature of CEMS repairs or adjustments and a summary of quality assurance data consistent with Appendix B to this Part, i.e., the dates and results of the Linearity Tests and any RATAs during the quarter; a listing of any days when a required daily calibration was not performed; and the date and duration of any periods when the CEMS was unavailable or out-of-control as addressed by Section 225.260.

 

4)         The owner or operator must submit each quarterly report to the Agency within 45 days following the end of the calendar quarter covered by the report, except that the owner or operator of an EGU that used an excepted monitoring system at any time during a calendar quarter must submit each quarterly report within 60 days following the end of the calendar quarter covered by the report.

 

c)         Compliance Certification.  The owner or operator of a source with one or more EGUs must submit to the Agency a compliance certification in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the EGUs' emissions are correctly and fully monitored.  The certification must state:

 

1)         That the monitoring data submitted were recorded in accordance with the applicable requirements of this Section, Sections 225.240 through 225.270 and Section 225.290 of this Subpart B, and Appendix B to this Part, including the quality assurance procedures and specifications; and

 

2)         For an EGU with add-on mercury emission controls, a flue gas desulfurization system, a selective catalytic reduction system, or a compact hybrid particulate collector system for all hours where mercury data is unavailable or out-of-control that:

 

A)        The mercury add-on emission controls, flue gas desulfurization system, selective catalytic reduction system, or compact hybrid particulate collector system was operating within the range of parameters listed in the quality assurance/quality control program pursuant to Exhibit B to Appendix B to this Part; or

 

B)        With regard to a flue gas desulfurization system or a selective catalytic reduction system, quality-assured SO₂ emission data recorded in accordance with the 40 CFR 75 document that the flue gas desulfurization system was operating properly, or quality-assured NO_x emission data recorded in accordance with the 40 CFR 75 document that the selective catalytic reduction system was operating properly, as applicable.

 

d)         Annual Certification of Compliance.

 

1)         The owner or operator of a source with one or more EGUs subject to this Subpart B must submit to the Agency an Annual Certification of Compliance with this Subpart B no later than May 1 of each year and must address compliance for the previous calendar year.  Such certification must be submitted to the Agency, Air Compliance Section, and the Air Regional Field Office.

 

2)         Annual Certifications of Compliance must indicate whether compliance existed for each EGU for each month in the year covered by the Certification and it must certify to that effect.  In addition, for each EGU, the owner or operator must provide the following appropriate data as set forth in subsections (d)(2)(A) through (d)(2)(E) of this Section, together with the data set forth in subsection (d)(2)(F) of this Section:

 

A)        If complying with this Subpart B by means of Section 225.230(a)(1)(A) or 225.237(a)(1)(A):

 

i)          Emissions rate during QAMO hours, in lb/GWh, for each 12-month rolling period ending in the year covered by the Certification;

 

ii)         Emissions during QAMO hours, in lbs, and gross electrical output, in GWh, for each 12-month rolling period ending in the year covered by the Certification; and

 

iii)        Emissions during QAMO hours, in lbs, and gross electrical output, in GWh, for each month in the year covered by the Certification and in the previous year.

 

B)        If complying with this Subpart B by means of Section 225.230(a)(1)(B) or 225.237(a)(1)(B):

 

i)          Control efficiency for emissions during QAMO hours for each 12-month rolling period ending in the year covered by the Certification, expressed as a percent;

 

ii)         Emissions during QAMO hours, in lbs, and mercury content in the fuel fired in such EGU, in lbs, for each 12-month rolling period ending in the year covered by the Certification; and

 

iii)        Emissions during QAMO hours, in lbs, and mercury content in the fuel fired in such EGU, in lbs, for each month in the year covered by the Certification and in the previous year.

 

C)        If complying with this Subpart B by means of Section 225.230(b):

 

i)          Emissions and allowable emissions during QAMO hours for each 12-month rolling period ending in the year covered by the Certification; and

 

ii)         Emissions and allowable emissions during QAMO hours and which standard of compliance the owner or operator was utilizing for each month in the year covered by the Certification and in the previous year.

 

D)        If complying with this Subpart B by means of Section 225.230(d):

 

i)          Emissions and allowable emissions during QAMO hours for all EGUs at the source for each 12-month rolling period ending in the year covered by the Certification; and

 

ii)         Emissions and allowable emissions during QAMO hours, and which standard of compliance the owner or operator was utilizing for each month in the year covered by the Certification and in the previous year.

 

E)        If complying with this Subpart B by means of Section 225.232:

 

i)          Emissions and allowable emissions during QAMO hours for all EGUs at the source in an Averaging Demonstration for each 12-month rolling period ending in the year covered by the Certification; and

 

ii)         Emissions and allowable emissions during QAMO hours, with the standard of compliance the owner or operator was utilizing for each EGU at the source in an Averaging Demonstration for each month for all EGUs at the source in an Averaging Demonstration in the year covered by the Certification and in the previous year.

 

F)         Any deviations or exceptions each month and discussion of the reasons for such deviations or exceptions.

 

3)         All Annual Certifications of Compliance required to be submitted must include the following certification by a responsible official:

 

I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted.  Based on my inquiry of the person or persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete.  I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.

 

4)         The owner or operator of an EGU must submit its first Annual Certification of Compliance to address calendar year 2009 or the calendar year in which the EGU commences commercial operation, whichever is later.  Notwithstanding subsection (d)(2) of this Section, in the Annual Certifications of Compliance that are required to be submitted by May 1, 2010, and May 1, 2011, to address calendar years 2009 and 2010, respectively, the owner or operator is not required to provide 12-month rolling data for any period that ends before June 30, 2010.

 

e)         Deviation Reports.  For each EGU, the owner or operator must promptly notify the Agency of deviations from requirements of this Subpart B.  At a minimum, these notifications must include a description of such deviations within 30 days after discovery of the deviations, and a discussion of the possible cause of such deviations, any corrective actions, and any preventative measures taken.

 

f)         Quality Assurance RATA Reports.  The owner or operator of an EGU must submit to the Agency, Air Compliance and Enforcement Section, the quality assurance RATA report for each EGU or group of EGUs monitored at a common stack and each non-EGU pursuant to Section 1.16(b)(2)(B) of Appendix B to this Part, within 45 days after completing a quality assurance RATA.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.291  Combined Pollutant Standard:  Purpose

 

The purpose of Sections 225.291 through 225.299 (hereinafter referred to as the Combined Pollutant Standard ("CPS")) is to allow an alternate means of compliance with the emissions standards for mercury in Section 225.230(a) for specified EGUs through permanent shut-down, installation of ACI, the application of pollution control technology for NO_x, PM, and SO₂ emissions, or the conversion of an EGU to a fuel other than coal (such as natural gas or distillate fuel oil with sulfur content no greater than 15 ppm), that also reduce mercury emissions as a co-benefit and to establish permanent emissions standards for those specified EGUs.  Unless otherwise provided for in the CPS, owners and operators of those specified EGUs are not excused from compliance with other applicable requirements of Subparts B, C, D, and E. 

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.292  Applicability of the Combined Pollutant Standard

 

a)         As an alternative to compliance with the emissions standards of Section 225.230(a), the owner or operator of specified EGUs in the CPS located at the Fisk, Crawford, Joliet, Powerton, Waukegan, and Will County power plants may elect for all of those EGUs as a group to demonstrate compliance pursuant to the CPS, which establishes control requirements and emissions standards for NO_x, PM, SO₂, and mercury.  For this purpose, ownership of a specified EGU is determined based on direct ownership, by holding a majority interest in a company that owns the EGU or EGUs, or by the common ownership of the company that owns the EGU, whether through a parent-subsidiary relationship, as a sister corporation, or as an affiliated corporation with the same parent corporation, provided that the owner or operator has the right or authority to submit a CAAPP application on behalf of the EGU.

 

b)         A specified EGU is an EGU listed in Appendix A, irrespective of any subsequent changes in ownership of the EGU or power plant, the operator, unit designation, or name of unit, or the type of fuel combusted (including natural gas or distillate fuel oil with sulfur content no greater than 15 ppm).

 

c)         The owner or operator of each of the specified EGUs electing to demonstrate compliance with Section 225.230(a) pursuant to the CPS must submit an application for a CAAPP permit modification to the Agency, as provided for in Section 225.220, that includes the information specified in Section 225.293 that clearly states the owner's or operator's election to demonstrate compliance with Section 225.230(a) pursuant to the CPS.

 

d)         If an owner or operator of one or more specified EGUs elects to demonstrate compliance with Section 225.230(a) pursuant to the CPS, then all specified EGUs owned or operated in Illinois by the owner or operator as of December 31, 2006, as defined in subsection (a) of this Section, are thereafter subject to the standards and control requirements of the CPS.  Such EGUs are referred to as a Combined Pollutant Standard (CPS) group.

 

e)         If an EGU is subject to the requirements of this Section, then the requirements apply to all owners and operators of the EGU.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.293  Combined Pollutant Standard:  Notice of Intent

 

The owner or operator of one or more specified EGUs that intends to comply with Section 225.230(a) by means of the CPS must notify the Agency of its intention on or before December 31, 2007.  The following information must accompany the notification:

 

a)         The identification of each EGU that will be complying with Section 225.230(a) pursuant to the CPS, with evidence that the owner or operator has identified all specified EGUs that it owned or operated in Illinois as of December 31, 2006, and which commenced commercial operation on or before December 31, 2004;

 

b)         If an EGU identified in subsection (a) of this Section is also owned or operated by a person different than the owner or operator submitting the notice of intent, a demonstration that the submitter has the right to commit the EGU or authorization from the responsible official for the EGU submitting the application;

 

c)         A summary of the current control devices installed and operating on each EGU and identification of the additional control devices that will likely be needed for each EGU to comply with emission control requirements of the CPS; and

 

d)         Additionally, the owner or operator of a specified EGU that, on or after January 1, 2015, changes the type of primary fuel combusted by the unit or the control device or devices installed and operating on the unit must notify the Agency of such change by January 1, 2017, or within 30 days after the completion of such change, whichever is later.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.294  Combined Pollutant Standard:  Control Technology Requirements and Emissions Standards for Mercury

 

a)         Control Technology Requirements for Mercury.

 

1)         For each coal-fired EGU in a CPS group other than an EGU that is addressed by subsection (b) of this Section, the owner or operator of the EGU must install, if not already installed, and properly operate and maintain, by the dates set forth in subsection (a)(2) of this Section, ACI equipment complying with subsections (g), (h), (i), (j), and (k) of this Section, as applicable.

 

2)         By the following dates, for the EGUs listed in subsections (a)(2)(A) and (B), which include hot and cold side ESPs, the owner or operator must install, if not already installed, and begin operating ACI equipment or the Agency must be given written notice that the EGU will be shut down on or before the following dates:

 

A)        Fisk 19, Crawford 7, Crawford 8, Waukegan 7, and Waukegan 8 on or before July 1, 2008; and

 

B)        Powerton 5, Powerton 6, Will County 3, Will County 4, Joliet 6, Joliet 7, and Joliet 8 on or before July 1, 2009.

 

b)         Notwithstanding subsection (a) of this Section:

 

1)         The following EGUs are not required to install ACI equipment because they will be permanently shut down, as addressed by Section 225.297, by the date specified:

 

A)        EGUs that are required to permanently shut down:

 

i)          On or before December 31, 2007, Waukegan 6; and

 

ii)         On or before December 31, 2010, Will County 1 and Will County 2.

 

B)        Any other specified EGU that is permanently shut down by December 31, 2010; and

 

2)         On and after the date an EGU permanently ceases combusting coal, it is not required to install, operate, or maintain ACI equipment.

 

c)         Beginning on January 1, 2015, and continuing thereafter, and measured on a rolling 12-month basis (the initial period is January 1, 2015, through December 31, 2015, and, then, for every 12-month period thereafter), each specified EGU that has not permanently ceased combusting coal, except Will County 3, shall achieve one of the following emissions standards:

 

1)         An emissions standard of 0.0080 lbs mercury/GWh gross electrical output; or

 

2)         A minimum 90 percent reduction of input mercury.

 

d)         On and after April 16, 2015, Will County 3 must not combust coal.

 

e)         Compliance with Emission Standards

 

1)         At any time prior to the dates required for compliance in subsections (c) and (d) of this Section, the owner or operator of a specified EGU, upon notice to the Agency, may elect to comply with the emissions standards of subsection (c) of this Section measured on either:

 

A)        a rolling 12-month basis; or

 

B)        a quarterly calendar basis pursuant to the emissions testing requirements in Section 225.239(a)(4), (c), (d), (e), (f), (g), (h), (i), and (j) of this Subpart until June 30, 2012. 

 

2)         Once an EGU is subject to the mercury emissions standards of subsection (c) of this Section, it shall not be subject to the requirements of subsections (g), (h), (i), (j) and (k) of this Section;

 

3)         On and after the date an EGU permanently ceases combusting coal, it shall not be subject to the requirements of subsections (g), (h), (i), (j) and (k) of this Section.

 

f)         Compliance with the mercury emissions standards or reduction requirement of this Section must be calculated in accordance with Section 225.230(a) or (b), or Section 225.232 until December 31, 2013.

 

g)         For each EGU for which injection of halogenated activated carbon is required by subsection (a)(1) of this Section, the owner or operator of the EGU must inject halogenated activated carbon in an optimum manner.

 

1)         Except as provided in subsection (h) of this Section, optimum manner is defined as all of the following:

 

A)        The use of an injection system for effective absorption of mercury, considering the configuration of the EGU and its ductwork;

 

B)        The injection of halogenated activated carbon manufactured by Alstom, Norit, or Sorbent Technologies, Calgon Carbon's FLUEPAC CF Plus, or Calgon Carbon's FLUEPAC MC Plus, or the injection of any other halogenated activated carbon or sorbent that the owner or operator of the EGU has demonstrated to have similar or better effectiveness for control of mercury emissions; and

 

C)        The injection of sorbent at the following minimum rates, as applicable:

 

i)          For an EGU firing subbituminous coal, 5.0 lbs per million actual cubic feet or, for any cyclone-fired EGU that will install a scrubber and baghouse by December 31, 2012, and which already meets an emission rate of 0.020 lb mercury/GWh gross electrical output or at least 75 percent reduction of input mercury, 2.5 lbs per million actual cubic feet;

 

ii)         For an EGU firing bituminous coal, 10.0 lbs per million actual cubic feet or, for any cyclone-fired EGU that will install a scrubber and baghouse by December 31, 2012, and which already meets an emission rate of 0.020 lb mercury/GWh gross electrical output or at least 75 percent reduction of input mercury, 5.0 lbs per million actual cubic feet;

 

iii)        For an EGU firing a blend of subbituminous and bituminous coal, a rate that is the weighted average of the rates specified in subsections (g)(1)(C)(i) and (ii) based on the blend of coal being fired; or

 

iv)        A rate or rates set lower by the Agency, in writing, than the rate specified in any of subsection (g)(1)(C)(i), (ii), or (iii) of this Section on a unit-specific basis, provided that the owner or operator of the EGU has demonstrated that such rate or rates are needed so that carbon injection will not increase particulate matter emissions or opacity so as to threaten noncompliance with applicable requirements for particulate matter or opacity.

 

2)         For purposes of subsection (g)(1)(C) of this Section, the flue gas flow rate shall be the gas flow rate in the stack for all units except for those equipped with activated carbon injection prior to a hot-side electrostatic precipitator; for units equipped with activated carbon injection prior to a hot-side electrostatic precipitator, the flue gas flow rate shall be the gas flow rate at the inlet to the hot-side electrostatic precipitator, which shall be determined as the stack flow rate adjusted through the use of Charles' Law for the differences in gas temperatures in the stack and at the inlet to the electrostatic precipitator (V_esp = V_stack x T_esp/T_stack, where V = gas flow rate in acf and T = gas temperature in Kelvin or Rankine).

 

h)         The owner or operator of an EGU that seeks to operate an EGU with an activated carbon injection rate or rates that are set on a unit-specific basis pursuant to subsection (g)(1)(C)(iv) of this Section must submit an application to the Agency proposing such rate or rates, and must meet the requirements of subsections (h)(1) and (h)(2) of this Section, subject to the limitations of subsections (h)(3) and (h)(4) of this Section:

 

1)         The application must be submitted as an application for a new or revised federally enforceable operation permit for the EGU, and it must include a summary of relevant mercury emissions data for the EGU, the unit-specific injection rate or rates that are proposed, and detailed information to support the proposed injection rate or rates;

 

2)         This application must be submitted no later than the date that activated carbon must first be injected.  For example, the owner or operator of an EGU that must inject activated carbon pursuant to subsection (a)(1) of this Section must apply for unit-specific injection rate or rates by July 1, 2008.  Thereafter, the owner or operator may supplement its application;

 

3)         Any decision of the Agency denying a permit or granting a permit with conditions that set a lower injection rate or rates may be appealed to the Board pursuant to Section 39 of the Act; and

 

4)         The owner or operator of an EGU may operate at the injection rate or rates proposed in its application until a final decision is made on the application including a final decision on any appeal to the Board.

 

i)          During any evaluation of the effectiveness of a listed sorbent, alternative sorbent, or other technique to control mercury emissions, the owner or operator of an EGU need not comply with the requirements of subsection (g) of this Section for any system needed to carry out the evaluation, as further provided as follows:

 

1)         The owner or operator of the EGU must conduct the evaluation in accordance with a formal evaluation program submitted to the Agency at least 30 days prior to commencement of the evaluation;

 

2)         The duration and scope of the evaluation may not exceed the duration and scope reasonably needed to complete the desired evaluation of the alternative control techniques, as initially addressed by the owner or operator in a support document submitted with the evaluation program;

 

3)         The owner or operator of the EGU must submit a report to the Agency no later than 30 days after the conclusion of the evaluation that describes the evaluation conducted and which provides the results of the evaluation; and

 

4)         If the evaluation of alternative control techniques shows less effective control of mercury emissions from the EGU than was achieved with the principal control techniques, the owner or operator of the EGU must resume use of the principal control techniques.  If the evaluation of the alternative control technique shows comparable effectiveness to the principal control technique, the owner or operator of the EGU may either continue to use the alternative control technique in a manner that is at least as effective as the principal control technique or it may resume use of the principal control technique.  If the evaluation of the alternative control technique shows more effective control of mercury emissions than the control technique, the owner or operator of the EGU must continue to use the alternative control technique in a manner that is more effective than the principal control technique, so long as it continues to be subject to this Section.

 

j)          In addition to complying with the applicable recordkeeping and monitoring requirements in Sections 225.240 through 225.290, the owner or operator of an EGU that elects to comply with this Subpart B by means of Sections 225.291 through 225.299 must also comply with the following additional requirements:

 

1)         For the first 36 months that injection of sorbent is required, it must maintain records of the usage of sorbent, the flue gas flow rate from the EGU (and, if the unit is equipped with activated carbon injection prior to a hot-side electrostatic precipitator, flue gas temperature at the inlet of the hot-side electrostatic precipitator and in the stack), and the sorbent feed rate, in pounds per million actual cubic feet of flue gas, on a weekly average;

 

2)         After the first 36 months that injection of sorbent is required, it must monitor activated sorbent feed rate to the EGU, gas flow rate in the stack, and, if the unit is equipped with activated carbon injection prior to a hot-side electrostatic precipitator, flue gas temperature at the inlet of the hot-side electrostatic precipitator and in the stack.  It must automatically record this data and the sorbent carbon feed rate, in pounds per million actual cubic feet of flue gas, on an hourly average; and

 

3)         If a blend of bituminous and subbituminous coal is fired in the EGU, it must keep records of the amount of each type of coal burned and the required injection rate for injection of activated carbon on a weekly basis.

 

k)         In addition to complying with the applicable reporting requirements in Sections 225.240 through 225.290, the owner or operator of an EGU that elects to comply with Section 225.230(a) by means of the CPS must also submit quarterly reports for the recordkeeping and monitoring conducted pursuant to subsection (j) of this Section.

 

l)          Until June 30, 2012, as an alternative to the CEMS (or excepted monitoring system) monitoring, recordkeeping, and reporting requirements in Sections 225.240 through 225.290, the owner or operator of an EGU may elect to comply with the emissions testing, monitoring, recordkeeping, and reporting requirements in Section 225.239(c), (d), (e), (f)(1) and (2), (h)(2), (i)(3) and (4), and (j)(1).

 

m)        Notwithstanding any other provision in this Subpart, the requirements in Sections 225.240 through 225.290 of this Subpart, and any other mercury-related monitoring, recordkeeping, notice, analysis, certification, and reporting requirements set forth in this Subpart, including in this CPS, will not apply to a specified EGU on and after the date the EGU permanently ceases combusting coal.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.295  Combined Pollutant Standard:  Emissions Standards for NO_x and SO₂

 

a)         Emissions Standards for NO_x and Reporting Requirements.

 

1)         Beginning with calendar year 2012 and continuing in each calendar year thereafter, the CPS group, which includes all specified EGUs, regardless of the type of fuel combusted, that have not been permanently shut down by December 31 before the applicable calendar year, must comply with a CPS group average annual NO_x emissions rate of no more than 0.11 lbs/mmBtu.

 

2)         Beginning with ozone season control period 2012 and continuing in each ozone season control period (May 1 through September 30) thereafter, the CPS group, which includes all specified EGUs, regardless of the type of fuel combusted, that have not been permanently shut down by December 31 before the applicable ozone season, must comply with a CPS group average ozone season NO_x emissions rate of no more than 0.11 lbs/mmBtu.

 

3)         The owner or operator of the specified EGUs in the CPS group must file, not later than one year after startup of any selective SNCR on such EGU, a report with the Agency describing the NO_x emissions reductions that the SNCR has been able to achieve.

 

4)         The specified EGUs are not subject to the requirements set forth in 35 Ill. Adm. Code 217, Subpart M, including without limitation the NO_x emission standards set forth in 35 Ill. Adm. Code 217.344.

 

b)         Emissions Standards for SO₂.  Beginning in calendar year 2013 and continuing in each calendar year thereafter, the CPS group must comply with the applicable CPS group average annual SO₂ emissions rate listed as follows.  For purposes of subsections (b) and (d) only, the CPS group includes only those specified EGUs that combust coal.

 

year                                lbs/mmBtu

 

2013                                     0.44

2014                                     0.41

2015                                     0.28

2016                                     0.195

2017                                     0.15

2018                                     0.13

2019                                     0.11

 

c)         Compliance with the NO_x and SO₂ emissions standards must be demonstrated in accordance with Sections 225.310, 225.410, and 225.510.  The owner or operator of the specified EGUs must complete the demonstration of compliance pursuant to Section 225.298(c) before March 1 of the following year for annual standards and before November 30 of the particular year for ozone season control periods (May 1 through September 30) standards, by which date a compliance report must be submitted to the Agency.

 

d)         The CPS group average annual SO₂ emission rate, annual NO_x emission rate and ozone season NO_x emission rates shall be determined as follows:

 

 

Where:

 

ERavg	=	average annual or ozone season emission rate in lbs/mmBtu of all EGUs in the CPS group.
HIi	=	heat input for the annual or ozone control period of each EGU, in mmBtu.
SO2i	=	actual annual SO2 lbs of each EGU in the CPS group, as set forth in subsection (b).
NOxi	=	actual annual or ozone season NOx lbs of each EGU in the CPS group.
n	=	number of EGUs that are in the CPS group.
i	=	each EGU in the CPS group.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.296  Combined Pollutant Standard:  Control Technology Requirements for NO_x, SO₂, and PM Emissions

 

a)         Control Technology Requirements for NO_x and SO₂.

 

1)         On or before December 31, 2013, the owner or operator must either permanently shut down or install and have operational FGD equipment on Waukegan 7;

 

2)         On or before December 31, 2014, the owner or operator must either permanently shut down or install and have operational FGD equipment on Waukegan 8;

 

3)         On or before December 31, 2015, the owner or operator must either permanently shut down or install and have operational FGD equipment on Fisk 19;

 

4)         If Crawford 7 will be operated after December 31, 2018, and not permanently shut down by this date, the owner or operator must:

 

A)        On or before December 31, 2015, install and have operational SNCR or equipment capable of delivering essentially equivalent NO_x reductions on Crawford 7; and

 

B)        On or before December 31, 2018, install and have operational FGD equipment on Crawford 7;

 

5)         If Crawford 8 will be operated after December 31, 2017 and not permanently shut down by this date, the owner or operator must:

 

A)        On or before December 31, 2015, install and have operational SNCR or equipment capable of delivering essentially equivalent NO_x emissions reductions on Crawford 8; and

 

B)        On or before December 31, 2017, install and have operational FGD equipment on Crawford 8.

 

b)         Other Control Technology Requirements for SO₂.  On and after April 16, 2015, Will County 3 must not combust coal.  On and after December 31, 2016, Joliet 6, 7, and 8 must not combust coal.  Owners or operators of the other specified EGUs must permanently shut down, permanently cease combusting coal at, or install FGD equipment on each specified EGU (except Will County 4), on or before December 31, 2018, unless an earlier date is specified in subsection (a) of this Section.

 

c)          Control Technology Requirements for PM.  The owner or operator of the specified EGU listed in this subsection that is equipped with a hot-side ESP must replace the hot-side ESP with a cold-side ESP, install an appropriately designed fabric filter, or permanently shut down the EGU by the date specified.  Hot-side ESP means an ESP on a coal-fired boiler that is installed before the boiler's air-preheater where the operating temperature is typically at least 550ºF, as distinguished from a cold-side ESP that is installed after the air pre-heater where the operating temperature is typically no more than 350ºF.  Waukegan 7 on or before December 31, 2013.

 

d)          Beginning on December 31, 2008, and annually thereafter up to and including December 31, 2015, the owner or operator of the Fisk power plant must submit in writing to the Agency a report on any technology or equipment designed to affect air quality that has been considered or explored for the Fisk power plant in the preceding 12 months.  This report will not obligate the owner or operator to install any equipment described in the report.

 

e)         Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied with the applicable requirements of subsections 225.296(a), (b), and (c), the owner or operator of the EGU must obtain a construction permit for any new or modified air pollution control equipment that it proposes to construct for control of emissions of mercury, NO_x, PM, or SO₂.

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.297  Combined Pollutant Standard: Permanent Shut-Downs

 

a)         The owner or operator of the following EGUs must permanently shut down the EGU by the dates specified:

 

1)         Waukegan 6 on or before December 31, 2007; and

 

2)         Will County 1 and Will County 2 on or before December 31, 2010.

 

b)         No later than 8 months before the date that a specified EGU will be permanently shut down, the owner or operator must submit a report to the Agency that includes a description of the actions that have already been taken to allow the shutdown of the EGU and a description of the future actions that must be accomplished to complete the shutdown of the EGU, with the anticipated schedule for those actions and the anticipated date of permanent shutdown of the unit.

 

c)         No later than six months before a specified EGU will be permanently shut down, the owner or operator shall apply for revisions to the operating permits for the EGU to include provisions that terminate the authorization to operate the unit on that date.

 

d)         If after applying for or obtaining a construction permit to install required control equipment, the owner or operator decides to permanently shut-down a Specified EGU rather than install the required control technology, the owner or operator must immediately notify the Agency in writing and thereafter submit the information required by subsections (b) and (c) of this Section.

 

e)         Failure to permanently shut down a specified EGU by the required date shall be considered separate violations of the applicable emissions standards and control technology requirements of the CPS for NO_x, PM, SO₂, and mercury.

 

(Source:  Added at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.298  Combined Pollutant Standard:  Requirements for NO_x and SO₂ Allowances

 

a)         The following requirements apply to the owner and operator with respect to SO₂ and NO_x allowances, which mean, for the purposes of this Section 225.298, allowances necessary for compliance with Section 225.310, 225.410, or 225.510, 40 CFR 72, or subparts AA and AAAA of 40 CFR 96, or any future federal NO_x or SO₂ emissions trading programs that modify or replace these programs:

 

1)         The owner or operator of specified EGUs in a CPS group may sell, trade, or transfer any and all SO₂ and NO_x emissions allowances of any vintage (the year an allowance is issued) owned, allocated to, or earned by the specified EGUs (the "CPS allowances"), without restriction, to any person or entity located anywhere, except that the owner or operator may not directly sell, trade, or transfer CPS allowances to a unit located in Ohio, Indiana, Illinois, Wisconsin, Michigan, Kentucky, Missouri, Iowa, Minnesota, or Texas. 

 

2)         In no event shall this subsection (a) require or be interpreted to require any restriction whatsoever on the sale, trade, or exchange of the CPS allowances by persons or entities who have acquired the CPS allowances from the owner or operator of specified EGUs in a CPS group.

 

b)         The owner or operator of EGUs in a specified CPS group is prohibited from purchasing or using SO₂ and NO_x allowances for the purposes of meeting the SO₂ and NO_x emissions standards set forth in Section 225.295.

 

c)         By March 1, 2010, and continuing each year thereafter, the owner or operator of the EGUs in a CPS group must submit a report to the Agency that demonstrates compliance with the requirements of this Section for the previous calendar year and ozone season control period (May 1 through September 30), and includes identification of any NO_x or SO₂ allowances that have been used for compliance with any NO_x or SO₂ trading programs, and any NO_x or SO₂ allowances that were sold, gifted, used, exchanged, or traded.  A final report must be submitted to the Agency by August 31 of each year, providing either verification that the actions described in the initial report have taken place, or, if such actions have not taken place, an explanation of the changes that have occurred and the reasons for such changes. 

 

(Source:  Amended at 39 Ill. Reg. 16225, effective December 7, 2015)

 

Section 225.299  Combined Pollutant Standard: Clean Air Act Requirements

 

The SO₂ emissions rates set forth in the CPS shall be deemed to be best available retrofit technology ("BART") under the Visibility Protection provisions of the CAA (42 USC 7491), reasonably available control technology ("RACT") and reasonably available control measures ("RACM") for achieving fine particulate matter ("PM_2.5") requirements under NAAQS in effect on August 31, 2007, as required by the CAA (42 USC 7502).  The Agency may use the SO₂ and NO_x emissions reductions required under the CPS in developing attainment demonstrations and demonstrating reasonable further progress for PM_2.5 and 8 hour ozone standards, as required under the CAA.  Furthermore, in developing rules, regulations, or State Implementation Plans designed to comply with PM_2.5 and 8 hour ozone NAAQS, the Agency, taking into account all emission reduction efforts and other appropriate factors, will use best efforts to seek SO₂ and NO_x emissions rates from other EGUs that are equal to or less than the rates applicable to the CPS group and will seek SO₂ and NO_x reductions from other sources before seeking additional emissions reductions from any EGU in the CPS group.

 

(Source:  Added at 33 Ill. Reg. 10427, effective June 26, 2009)

 

Section 225.300  Purpose

 

The purpose of this Subpart C is to control the emissions of sulfur dioxide (SO₂) from EGUs annually by implementing the CAIR SO₂ Trading Program pursuant to 40 CFR 96, as incorporated by reference in Section 225.140.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.305  Applicability

 

a)         Except as provided in subsections (b)(1), (b)(3), and (b)(4) of this Section:

 

1)         The following units are CAIR SO₂ units, and any source that includes one or more such units is a CAIR SO₂ source subject to the requirements of this Subpart C:  any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

 

2)         If a stationary boiler or stationary combustion turbine that, pursuant to subsection (a)(1) of this Section, is not a CAIR SO₂ unit begins to combust fossil fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the unit will become a CAIR SO₂ unit as provided in subsection (a)(1) of this Section on the first date on which it both combusts fossil fuel and serves such generator.

 

b)         The units that meet the requirements set forth in subsections (b)(1), (b)(3), and (b)(4) of this Section will not be CAIR SO₂ units and units that meet the requirements of subsections (b)(2) and (b)(5) of this Section are CAIR SO₂ units:

 

1)         Any unit that would otherwise be classified as a CAIR SO₂ unit pursuant to subsection (a)(1) or (a)(2) of this Section and:

 

A)        Qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continues to qualify as a cogeneration unit; and

 

B)        Does not serve at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution for sale.

 

2)         If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and meets the requirements of subsection (b)(1) of this Section for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become a CAIR SO₂ unit starting on the earlier of January 1 after the first calendar year during which the unit no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of subsection (b)(1)(B) of this Section.

 

3)         Any unit that would otherwise be classified as a CAIR SO₂ unit pursuant to subsection (a)(1) or (a)(2) of this Section commencing operation before January 1, 1985 and:

 

A)        Qualifies as a solid waste incineration unit; and

 

B)        Has an average annual fuel consumption of non-fossil fuel for 1985-1987 exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any three consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).

 

4)         Any unit that would otherwise be classified as a CAIR SO₂ unit under subsection (a)(1) or (a)(2) of this Section commencing operation on or after January 1, 1985 and:

 

A)        Qualifies as a solid waste incineration unit; and

 

B)        Has an average annual fuel consumption of non-fossil fuel the first three years of operation exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any three consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).

 

5)         If a unit qualifies as a solid waste incineration unit and meets the requirements of subsection (b)(3) or (b)(4) of this Section for at least three consecutive years, but subsequently no longer meets all such requirements, the unit shall become a CAIR SO₂ unit starting on the earlier of January 1 after the first three consecutive calendar years after 1990 for which the unit has an average annual fuel consumption of 20 percent or more.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.310  Compliance Requirements

 

a)         The designated representative of a CAIR SO₂ unit must comply with the requirements of the CAIR SO₂ Trading Program for Illinois as set forth in this Subpart C and 40 CFR 96, subpart AAA (CAIR SO₂ Trading Program General Provisions, excluding 40 CFR 96.204, and 96.206); 40 CFR 96, subpart BBB (CAIR Designated Representative for CAIR SO₂ Sources); 40 CFR 96, subpart FFF (CAIR SO₂ Allowance Tracking System); 40 CFR 96, subpart GGG (CAIR SO₂ Allowance Transfers); and 40 CFR 96, subpart HHH (Monitoring and Reporting); as incorporated by reference in Section 225.140 .

 

b)         Permit requirements:

 

1)         The owner or operator of each source with one or more CAIR SO₂ units at the source must apply for a permit issued by the Agency with federally enforceable conditions covering the CAIR SO₂ Trading Program ("CAIR permit") that complies with the requirements of Section 225.320 (Permit Requirements).

 

2)         The owner or operator of each CAIR SO₂ source and each CAIR SO₂ unit at the source must operate the CAIR SO₂ unit in compliance with its CAIR permit.

 

c)         Monitoring requirements:

 

1)         The owner or operator of each CAIR SO₂ source and each CAIR SO₂ unit at the source must comply with the monitoring, reporting and recordkeeping requirements of 40 CFR 96, subpart HHH.  The CAIR designated representative of each CAIR SO₂ source and each CAIR SO₂ unit at the CAIR SO₂ source must comply with those sections of the monitoring, reporting and recordkeeping requirements of 40 CFR 96, subpart HHH, applicable to the CAIR designated representative.

 

2)         The compliance of each CAIR SO₂ source with the emissions limitation pursuant to subsection (d) of this Section will be determined by the emissions measurements recorded and reported in accordance with 40 CFR 96, subpart HHH and 40 CFR 75.

 

d)         Emission requirements:

 

1)         By the allowance transfer deadline, midnight of March 1, 2010, and by midnight of March 1 of each subsequent year if March 1 is a business day, the owner or operator of each CAIR SO₂ source and each CAIR SO₂ unit at the source must hold a tonnage equivalent in CAIR SO₂ allowances available for compliance deductions pursuant to 40 CFR 96.254(a) and (b) in the CAIR SO₂ source's CAIR SO₂ compliance account.  If March 1 is not a business day, the allowance transfer deadline means by midnight of the first business day thereafter.  The number of allowances held on the allowance transfer deadline may not be less than the total tonnage equivalent of the tons of SO₂ emissions for the control period from all CAIR SO₂ units at the CAIR SO₂ source, as determined in accordance with 40 CFR 96, subpart HHH.

 

2)         Each ton of excess emissions of SO₂ emitted by a CAIR SO₂ source for each day of a control period, starting in 2010 will constitute a separate violation of this Subpart C, the Clean Air Act, and the Act.

 

3)         Each CAIR SO₂ unit will be subject to the requirements of subsection (d)(1) of this Section for the control period starting on the later of January 1, 2010 or the deadline for meeting the unit's monitoring certification requirements pursuant to 40 CFR 96.270(b)(1) or (2) and for each control period thereafter.

 

4)         CAIR SO₂ allowances must be held in, deducted from, or transferred into or among allowance accounts in accordance with this Subpart and 40 CFR 96, subparts FFF and GGG.

 

5)         In order to comply with the requirements of subsection (d)(1) of this Section, a CAIR SO₂ allowance may not be deducted for compliance according to subsection (d)(1) of this Section for a control period in a calendar year before the year for which the allowance is allocated.

 

6)         A CAIR SO₂ allowance is a limited authorization to emit SO₂ in accordance with the CAIR SO₂ Trading Program.  No provision of the CAIR SO₂ Trading Program, the CAIR permit application, the CAIR permit, or a retired unit exemption pursuant to 40 CFR 96.205, and no provision of law, will be construed to limit the authority of the United States or the State to terminate or limit this authorization.

 

7)         A CAIR SO₂ allowance does not constitute a property right.

 

8)         Upon recordation by USEPA pursuant to 40 CFR 96 subpart FFF or subpart GGG, every allocation, transfer, or deduction of a CAIR SO₂ allowance to or from a CAIR SO₂ source's compliance account is deemed to amend automatically, and become a part of, any CAIR permit of the CAIR SO₂ source.  This automatic amendment of the CAIR permit will be deemed an operation of law and will not require any further review.

 

e)         Recordkeeping and reporting requirements:

 

1)         Unless otherwise provided, the owner or operator of the CAIR SO₂ source and each CAIR SO₂ unit at the source must keep on site at the source each of the documents listed in subsections (e)(1)(A) through (e)(1)(D) of this Section for a period of five years from the date the document is created.  This period may be extended for cause, at any time prior to the end of five years, in writing by the Agency or USEPA.

 

A)        The certificate of representation for the CAIR designated representative for the source and each CAIR SO₂ unit at the source, all documents that demonstrate the truth of the statements in the certificate of representation, provided that the certificate and documents must be retained on site at the source beyond such five-year period until the documents are superseded because of the submission of a new certificate of representation, pursuant to 40 CFR 96.213, changing the CAIR designated representative.

 

B)        All emissions monitoring information, in accordance with 40 CFR 96, subpart HHH.

 

C)        Copies of all reports, compliance certifications, and other submissions and all records made or required pursuant to the CAIR SO₂ Trading Program or documents necessary to demonstrate compliance with the requirements of the CAIR SO₂ Trading Program or with the requirements of this Subpart C.

 

D)        Copies of all documents used to complete a CAIR permit application and any other submission or documents used to demonstrate compliance pursuant to the CAIR SO₂ Trading Program.

 

2)         The CAIR designated representative of a CAIR SO₂ source and each CAIR SO₂ unit at the source must submit to the Agency and USEPA the reports and compliance certifications required pursuant to the CAIR SO₂ Trading Program, including those pursuant to 40 CFR 96, subpart HHH.

 

f)         Liability:

 

1)         No revision of a permit for a CAIR SO₂ unit may excuse any violation of the requirements of this Subpart C or the requirements of the CAIR SO₂ Trading Program.

 

2)         Each CAIR SO₂ source and each CAIR SO₂ unit must meet the requirements of the CAIR SO₂ Trading Program.

 

3)         Any provision of the CAIR SO₂ Trading Program that applies to a CAIR SO₂ source (including any provision applicable to the CAIR designated representative of a CAIR SO₂ source) will also apply to the owner and operator of the CAIR SO₂ source and to the owner and operator of each CAIR SO₂ unit at the source.

 

4)         Any provision of the CAIR SO₂ Trading Program that applies to a CAIR SO₂ unit (including any provision applicable to the CAIR designated representative of a CAIR SO₂ unit) will also apply to the owner and operator of the CAIR SO₂ unit. 

 

5)         The CAIR designated representative of a CAIR SO₂ unit that has excess SO₂ emissions in any control period must surrender the allowances as required for deduction pursuant to 40 CFR 96.254(d)(1).

 

6)         The owner or operator of a CAIR SO₂ unit that has excess SO₂ emissions in any control period must pay any fine, penalty, or assessment or comply with any other remedy imposed pursuant to the Act and 40 CFR 96.254(d)(2).

 

g)         Effect on other authorities:  No provision of the CAIR SO₂ Trading Program, a CAIR permit application, a CAIR permit, or a retired unit exemption pursuant to 40 CFR 96.205 will be construed as exempting or excluding the owner and operator and, to the extent applicable, the CAIR designated representative of a CAIR SO₂ source or a CAIR SO₂ unit from compliance with any other regulation promulgated pursuant to the CAA, the Act, any State regulation or permit, or a federally enforceable permit.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.315  Appeal Procedures

 

The appeal procedures for decisions of USEPA pursuant to the CAIR SO2 Trading Program are set forth in 40 CFR 78, as incorporated by reference in Section 225.140.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.320  Permit Requirements

 

a)         Permit requirements:

 

1)         The owner or operator of each source with a CAIR SO₂ unit is required to submit:

 

A)        A complete permit application addressing all applicable CAIR SO₂ Trading Program requirements for a permit meeting the requirements of this Section, applicable to each CAIR SO₂ unit at the source.  Each CAIR permit must contain elements required for a complete CAIR permit application pursuant to subsection (b)(2) of this Section.

 

B)        Any supplemental information that the Agency determines is necessary in order to review a CAIR permit application and issue a CAIR permit.

 

2)         Each CAIR permit will be issued pursuant to Section 39 or 39.5 of the Act, must contain federally enforceable conditions addressing all applicable CAIR SO₂ Trading Program requirements, and will be a complete and segregable portion of the source's entire permit pursuant to subsection (a)(1) of this Section.

 

3)         No CAIR permit may be issued until the Agency and USEPA have received a complete certificate of representation for a CAIR designated representative or alternate designated representative pursuant to 40 CFR 96, subpart BBB, for a source and the CAIR SO₂ unit at the source.

 

4)         For all CAIR SO₂ units that commenced operation before July 1, 2008, the owner or operator of the unit must submit a CAIR permit application meeting the requirements of this Section on or before July 1, 2008.

 

5)         For CAIR SO₂ units that commence operation on or after July 1, 2008, and that are and are not subject to Section 39.5 of the Act, the owner or operator of such units must submit applications for construction and operating permits pursuant to the requirements of Sections 39 and 39.5 of the Act, as applicable, and 35 Ill. Adm. Code 201 and the applications must specify that they are applying for CAIR permits and must address the CAIR permit application requirements of this Section.

 

b)         Permit applications:

 

1)         Duty to apply:  The owner or operator of any source with one or more CAIR SO₂ units must submit to the Agency a CAIR permit application for the source covering each CAIR SO₂ unit pursuant to subsection (b)(2) of this Section by the applicable deadline in subsection (a)(4) or (a)(5) of this Section.  The owner or operator of any source with one or more CAIR SO₂ units must reapply for a CAIR permit for the source as required by this Subpart, 35 Ill. Adm. Code 201, and, as applicable, Sections 39 and 39.5 of the Act.

 

2)         Information requirements for CAIR permit applications:  A complete CAIR permit application must include the following elements concerning the source for which the application is submitted:

 

A)        Identification of the source, including plant name.  The ORIS (Office of Regulatory Information Systems) or facility code assigned to the source by the Energy Information Administration must also be included, if applicable;

 

B)        Identification of each CAIR SO₂ unit at the source; and

 

C)        The compliance requirements applicable to each CAIR SO₂ unit as set forth in Section 225.310.

 

3)         An application for a CAIR permit will be treated as a modification of the CAIR SO₂ source's existing federally enforceable permit, if such a permit has been issued for that CAIR SO₂ source, and will be subject to the same procedural requirements.  When the Agency issues a CAIR permit pursuant to the requirements of this Section, it will be incorporated into and become part of that CAIR SO₂ source's existing federally enforceable permit.

 

c)         Permit content:  Each CAIR permit is deemed to incorporate automatically the definitions and terms specified in 225.130 and 40 CFR 96.202, as incorporated by reference in Section 225.140 and, upon recordation of USEPA under 40 CFR 96, subparts FFF and GGG, as incorporated by reference in Section 225.140, every allocation, transfer, or deduction of a CAIR SO₂ allowance to or from the compliance account of the CAIR SO₂ source covered by the permit.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.325  Trading Program

 

a)         The CAIR SO₂ Trading Program is administered by USEPA.  CAIR SO₂ allowances are issued as described by the definition for allocate in 40 CFR 96.202, as incorporated by reference in Section 225.140.  The amount of CAIR SO₂ allowances to be credited to a CAIR SO₂ source's CAIR SO₂ Allowance Tracking System account for a CAIR SO₂ unit will be determined in accordance with 40 CFR 96.253, as incorporated by reference in Section 225.140.

 

b)         A CAIR SO₂ allowance is a limited authorization to emit SO₂ during the calendar year for which the allowance is allocated or any calendar year thereafter pursuant to the CAIR SO₂ Trading Program as follows:

 

1)         For one CAIR SO₂ allowance allocated for a control period in a year before 2010, one ton of SO₂, except as provided for in the compliance deductions pursuant to 40 CFR 96.254(b);

 

2)         For one CAIR SO₂ allowance allocated for a control period in 2010 through 2014, 0.50 ton of SO₂, except as provided for in the compliance deductions pursuant to 40 CFR 96.254(b); and

 

3)         For one CAIR SO₂ allowance allocated for a control period in 2015 or later, 0.35 ton of SO₂, except as provided for in the compliance deductions pursuant to 40 CFR 96.254(b).

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.400  Purpose

 

The purpose of this Subpart D is to control the annual emissions of nitrogen oxides (NO_x) from EGUs by determining allocations and implementing the CAIR NO_x Annual Trading Program.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.405  Applicability

 

a)         Except as provided in subsections (b)(1), (b)(3), and (b)(4) of this Section:

 

1)         The following units are CAIR NO_x units, and any source that includes one or more such units is a CAIR NO_x source subject to the requirements of this Subpart D:  any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

 

2)         If a stationary boiler or stationary combustion turbine that, pursuant to subsection (a)(1) of this Section, is not a CAIR NO_x unit begins to combust fossil fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the unit will become a CAIR NO_x unit as provided in subsection (a)(1) of this Section on the first date on which it both combusts fossil fuel and serves such generator.

 

b)         The units that meet the requirements set forth in subsections (b)(1), (b)(3), and (b)(4) of this Section will not be CAIR NO_x units and units that meet the requirements of subsections (b)(2) and (b)(5) of this Section are CAIR NO_x units:

 

1)         Any unit that would otherwise be classified as a CAIR NO_x unit pursuant to subsection (a)(1) or (a)(2) of this Section and:

 

A)        Qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continues to qualify as a cogeneration unit; and

 

B)        Does not serve at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution for sale.

 

2)         If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and meets the requirements of subsection (b)(1) of this Section for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become a CAIR NO_x unit starting on the earlier of January 1 after the first calendar year during which the unit no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of subsection (b)(1)(B) of this Section.

 

3)         Any unit that would otherwise be classified as a CAIR NO_x unit pursuant to subsection (a)(1) or (a)(2) of this Section commencing operation before January 1, 1985 and:

 

A)        Qualifies as a solid waste incineration unit; and

 

B)        Has an average annual fuel consumption of non-fossil fuel for 1985-1987 exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any three consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).

 

4)         Any unit that would otherwise be classified as a CAIR NO_x unit under subsection (a)(1) or (a)(2) of this Section commencing operation on or after January 1, 1985 and:

 

A)        Qualifies as a solid waste incineration unit; and

 

B)        Has an average annual fuel consumption of non-fossil fuel the first three years of operation exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any three consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).

 

5)         If a unit qualifies as a solid waste incineration unit and meets the requirements of subsection (b)(3) or (b)(4) of this Section for at least three consecutive years, but subsequently no longer meets all such requirements, the unit shall become a CAIR NO_x unit starting on the earlier of January 1 after the first three consecutive calendar years after 1990 for which the unit has an average annual fuel consumption of 20 percent or more.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.410  Compliance Requirements

 

a)         The designated representative of a CAIR NO_x unit must comply with the requirements of the CAIR NO_x Annual Trading Program for Illinois as set forth in this Subpart D and 40 CFR 96, subpart AA (NO_x Annual Trading Program General Provisions, excluding 40 CFR 96.104, 96.105(b)(2), and 96.106); 40 CFR 96, subpart BB (CAIR Designated Representative for CAIR NO_x Sources); 40 CFR 96, subpart FF (CAIR NO_x Allowance Tracking System); 40 CFR 96, subpart GG (CAIR NO_x Allowance Transfers); and 40 CFR 96, subpart HH (Monitoring and Reporting); as incorporated by reference in Section 225.140.

 

b)         Permit requirements:

 

1)         The designated representative of each source with one or more CAIR NO_x units at the source must apply for a permit issued by the Agency with federally enforceable conditions covering the CAIR NO_x Annual Trading Program ("CAIR permit") that complies with the requirements of Section 225.420 (Permit Requirements).

 

2)         The owner or operator of each CAIR NO_x source and each CAIR NO_x unit at the source must operate the CAIR NO_x unit in compliance with its CAIR permit.

 

c)         Monitoring requirements:

 

1)         The owner or operator of each CAIR NO_x source and each CAIR NO_x unit at the source must comply with the monitoring, reporting and recordkeeping requirements of 40 CFR 96, subpart HH and Section 225.450.  The CAIR designated representative of each CAIR NO_x source and each CAIR NO_x unit at the CAIR NO_x source must comply with those sections of the monitoring, reporting and recordkeeping requirements of 40 CFR 96, subpart HH, applicable to a CAIR designated representative.

 

2)         The compliance of each CAIR NO_x source with the NO_x emissions limitation pursuant to subsection (d) of this Section will be determined by the emissions measurements recorded and reported in accordance with 40 CFR 96, subpart HH.

 

d)         Emission requirements:

 

1)         By the allowance transfer deadline, midnight of March 1, 2010, and by midnight March 1 of each subsequent year if March 1 is a business day, the owner or operator of each CAIR NO_x source and each CAIR NO_x unit at the source must hold CAIR NO_x allowances available for compliance deductions pursuant to 40 CFR 96.154(a) in the CAIR NO_x source's CAIR NO_x compliance account.  If March 1 is not a business day, the allowance transfer deadline means by midnight of the first business day thereafter.  The number of allowances held on the allowance transfer deadline may not be less than the tons of NO_x emissions for the control period from all CAIR NO_x units at the source, as determined in accordance with 40 CFR 96, subpart HH.

 

2)         Each ton of excess emissions of a CAIR NO_x source for each day in a control period, starting in 2009, will constitute a separate violation of this Subpart D, the Act, and the CAA.

 

3)         Each CAIR NO_x unit will be subject to the requirements of subsection (d)(1) of this Section for the control period starting on the later of January 1, 2009 or the deadline for meeting the unit's monitoring certification requirements pursuant to 40 CFR 96.170(b)(1) or (b)(2) and for each control period thereafter.

 

4)         CAIR NO_x allowances must be held in, deducted from, or transferred into or among allowance accounts in accordance with this Subpart and 40 CFR 96, subparts FF and GG.

 

5)         In order to comply with the requirements of subsection (d)(1) of this Section, a CAIR NO_x allowance may not be deducted for compliance according to subsection (d)(1) of this Section for a control period in a year before the calendar year for which the allowance is allocated.

 

6)         A CAIR NO_x allowance is a limited authorization to emit one ton of NO_x in accordance with the CAIR NO_x Trading Program.  No provision of the CAIR NO_x Trading Program, the CAIR NO_x permit application, the CAIR permit, or a retired unit exemption pursuant to 40 CFR 96.105, and no provision of law, will be construed to limit the authority of the United States or the State to terminate or limit this authorization.

 

7)         A CAIR NO_x allowance does not constitute a property right.

 

8)         Upon recordation by USEPA pursuant to 40 CFR 96, subpart FF or subpart GG, every allocation, transfer, or deduction of a CAIR NO_x allowance to or from a CAIR NO_x source compliance account is deemed to amend automatically, and become a part of, any CAIR NO_x permit of the CAIR NO_x source.  This automatic amendment of the CAIR permit will be deemed an operation of law and will not require any further review.

 

e)         Recordkeeping and reporting requirements:

 

1)         Unless otherwise provided, the owner or operator of the CAIR NO_x source and each CAIR NO_x unit at the source must keep on site at the source each of the documents listed in subsections (e)(1)(A) through (e)(1)(E) of this Section for a period of five years from the date the document is created.  This period may be extended for cause, at any time prior to the end of five years, in writing by the Agency or USEPA.

 

A)        The certificate of representation for the CAIR designated representative for the source and each CAIR NO_x unit at the source, all documents that demonstrate the truth of the statements in the certificate of representation, provided that the certificate and documents must be retained on site at the source beyond such five-year period until the documents are superseded because of the submission of a new certificate of representation, pursuant to 40 CFR 96.113, changing the CAIR designated representative.

 

B)        All emissions monitoring information, in accordance with 40 CFR 96, subpart HH.

 

C)        Copies of all reports, compliance certifications, and other submissions and all records made or required pursuant to the CAIR NO_x Annual Trading Program or documents necessary to demonstrate compliance with the requirements of the CAIR NO_x Annual Trading Program or with the requirements of this Subpart D.

 

D)        Copies of all documents used to complete a CAIR NO_x permit application and any other submission or documents used to demonstrate compliance pursuant to the CAIR NO_x Annual Trading Program.

 

E)        Copies of all records and logs for gross electrical output and useful thermal energy required by Section 225.450.

 

2)         The CAIR designated representative of a CAIR NO_x source and each CAIR NO_x unit at the source must submit to the Agency and USEPA the reports and compliance certifications required pursuant to the CAIR NO_x Annual Trading Program, including those pursuant to 40 CFR 96, subpart HH.

 

f)         Liability:

 

1)         No revision of a permit for a CAIR NO_x unit may excuse any violation of the requirements of this Subpart D or the requirements of the CAIR NO_x Annual Trading Program.

 

2)         Each CAIR NO_x source and each CAIR NO_x unit must meet the requirements of the CAIR NO_x Annual Trading Program.

 

3)         Any provision of the CAIR NO_x Annual Trading Program that applies to a CAIR NO_x source (including any provision applicable to the CAIR designated representative of a CAIR NO_x source) will also apply to the owner and operator of the CAIR NO_x source and to the owner and operator of each CAIR NO_x unit at the source.

 

4)         Any provision of the CAIR NO_x Annual Trading Program that applies to a CAIR NO_x unit (including any provision applicable to the CAIR designated representative of a CAIR NO_x unit) will also apply to the owner and operator of the CAIR NO_x unit. 

 

5)         The CAIR designated representative of a CAIR NO_x unit that has excess emissions in any control period must surrender the allowances as required for deduction pursuant to 40 CFR 96.154(d)(1).

 

6)         The owner or operator of a CAIR NO_x unit that has excess NO_x emissions in any control period must pay any fine, penalty, or assessment or comply with any other remedy imposed pursuant to the Act and 40 CFR 96.154(d)(2).

 

g)         Effect on other authorities:  No provision of the CAIR NO_x Annual Trading Program, a CAIR permit application, a CAIR permit, or a retired unit exemption pursuant to 40 CFR 96.105 will be construed as exempting or excluding the owner and operator and, to the extent applicable, the CAIR designated representative of a CAIR NO_x source or a CAIR NO_x unit from compliance with any other regulation promulgated pursuant to the CAA, the Act, any State regulation or permit, or a federally enforceable permit.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.415  Appeal Procedures

 

The appeal procedures for decisions of USEPA pursuant to the CAIR NO_x Annual Trading Program are set forth in 40 CFR 78, as incorporated by reference in Section 225.140.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.420  Permit Requirements

 

a)         Permit requirements:

 

1)         The owner or operator of each source with a CAIR NO_x unit is required to submit:

 

A)        A complete permit application addressing all applicable CAIR NO_x Annual Trading Program requirements for a permit meeting the requirements of this Section, applicable to each CAIR NO_x unit at the source.  Each CAIR permit must contain elements required for a complete CAIR permit application pursuant to subsection (b)(2) of this Section.

 

B)        Any supplemental information that the Agency determines necessary in order to review a CAIR permit application and issue any CAIR permit.

 

2)         Each CAIR permit will be issued pursuant to Sections 39 and 39.5 of the Act, must contain federally enforceable conditions addressing all applicable CAIR NO_x Annual Trading Program requirements, and will be a complete and segregable portion of the source's entire permit pursuant to subsection (a)(1) of this Section.

 

3)         No CAIR permit may be issued until the Agency and USEPA have received a complete certificate of representation for a CAIR designated representative pursuant to 40 CFR 96, subpart BB, for the CAIR NO_x source and the CAIR NO_x unit at the source.

 

4)         For all CAIR NO_x units that commenced operation before December 31, 2007, the owner or operator of the unit must submit a CAIR permit application meeting the requirements of this Section on or before December 31, 2007.

 

5)         For all CAIR NO_x units that commence operation on or after December 31, 2007, the owner or operator of these units must submit applications for construction and operating permits pursuant to the requirements of Sections 39 and 39.5 of the Act, as applicable, and 35 Ill. Adm. Code 201 and the applications must specify that they are applying for CAIR permits and must address the CAIR permit application requirements of this Section.

 

b)         Permit applications:

 

1)         Duty to apply:  The owner or operator of any source with one or more CAIR NO_x units must submit to the Agency a CAIR permit application for the source covering each CAIR NO_x unit pursuant to subsection (b)(2) of this Section by the applicable deadline in subsection (a)(4) or (a)(5) of this Section.  The owner or operator of any source with one or more CAIR NO_x units must reapply for a CAIR permit for the source as required by this Subpart, 35 Ill. Adm. Code 201, and, as applicable, Sections 39 and 39.5 of the Act.

 

2)         Information requirements for CAIR permit applications: A complete CAIR permit application must include the following elements concerning the source for which the application is submitted:

 

A)        Identification of the source, including plant name.  The ORIS (Office of Regulatory Information Systems) or facility code assigned to the source by the Energy Information Administration must also be included, if applicable;

 

B)        Identification of each CAIR NO_x unit at the source; and

 

C)        The compliance requirements applicable to each CAIR NO_x unit as set forth in Section 225.410.

 

3)         An application for a CAIR permit will be treated as a modification of the CAIR NO_x source's existing federally enforceable permit, if such a permit has been issued for that source, and will be subject to the same procedural requirements.  When the Agency issues a CAIR permit pursuant to the requirements of this Section, it will be incorporated into and become part of that source's existing federally enforceable permit.

 

c)         Permit content:  Each CAIR permit is deemed to incorporate automatically the definitions and terms specified in Section 225.130 and 40 CFR 96.102, as incorporated by reference in Section 225.140 and, upon recordation of USEPA under 40 CFR 96, subparts FF and GG, as incorporated by reference in Section 225.140, every allocation, transfer, or deduction of a CAIR NO_x allowance to or from the compliance account of the CAIR NO_x source covered by the permit.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.425  Annual Trading Budget

 

The CAIR NO_x Annual Trading budget available for allowance allocations for each control period will be determined as follows:

 

a)         The total base CAIR NO_x Annual Trading budget is 76,230 tons per control period for the years 2009 through 2014, subject to a reduction for two set-asides, the New Unit Set-Aside (NUSA) and the Clean Air Set-Aside (CASA).  Five percent of the budget will be allocated to the NUSA and 25 percent will be allocated to the CASA, resulting in a CAIR NO_x Annual Trading budget of 53,361 tons available for allocation per control period pursuant to Section 225.440.  The requirements of the NUSA are set forth in Section 225.445, and the requirements of the CASA are set forth in Sections 225.455 through 225.470.

 

b)         The total base CAIR NO_x Annual Trading budget is 63,525 tons per control period for the year 2015 and thereafter, subject to a reduction for two set-asides, the NUSA and the CASA.  Five percent of the budget will be allocated to the NUSA and 25 percent will be allocated to the CASA, resulting in a CAIR NO_x Annual Trading budget of 44,468 tons available for allocation per control period pursuant to Section 225.440. 

 

c)         If USEPA adjusts the total base CAIR NO_x Annual Trading budget for any reason, the Agency will adjust the base CAIR NO_x Annual Trading budget and the CAIR NO_x Annual Trading budget available for allocation, accordingly.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.430  Timing for Annual Allocations

 

a)         On or before September 25, 2007, the Agency will submit to USEPA the CAIR NO_x allowance allocations, in accordance with Sections 225.435 and 225.440, for the 2009, 2010, and 2011 control periods.

 

b)         By October 31, 2008, and October 31 of each year thereafter, the Agency will submit to USEPA the CAIR NO_x allowance allocations in accordance with Sections 225.435 and 225.440, for the control period four years after the year of the applicable deadline for submission pursuant to this Section.  For example, on October 31, 2008, the Agency will submit to USEPA the allocations for the 2012 control period.

 

c)         For CAIR NO_x units that commence commercial operation on or after January 1, 2006, that have not been allocated allowances under Section 225.440 for the applicable or any preceding control period, the Agency will allocate allowances from the NUSA in accordance with Section 255.445.  The Agency will report these allocations to USEPA by October 31 of the applicable control period.  For example, on October 31, 2009, the Agency will submit to USEPA the allocations from the NUSA for the 2009 control period.

 

d)         The Agency will allocate allowances from the CASA to energy efficiency, renewable energy, and clean technology projects pursuant to the criteria in Sections 225.455 through 225.470.  The Agency will report these allocations to USEPA by October 1 of each year.  For example, on October 1, 2009, the Agency will submit to USEPA the allocations from the CASA for the 2009 control period, based on reductions made in the 2008 control period.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.435  Methodology for Calculating Annual Allocations

 

The Agency will calculate converted gross electrical (CGO) output, in MWh, for each CAIR NO_x unit that has operated during at least one calendar year prior to the calendar year in which the Agency reports the allocations to USEPA as follows:

 

a)         For control periods 2009, 2010, and 2011, the owner or operator of the unit must submit in writing to the Agency, by September 15, 2007, a statement that either gross electrical output data or heat input data is to be used to calculate the unit's converted gross electrical output.  The data shall be used to calculate converted gross electrical output pursuant to either subsection (a)(1) or (a)(2) of this Section:

 

1)         Gross electrical output:  If the unit has four or five control periods of data, then the gross electrical output (GO) will be the average of the unit's three highest gross electrical outputs from the 2001, 2002, 2003, 2004, or 2005 control periods.  If the unit has three or fewer control periods of gross electrical output data, the gross electrical output will be the average of those control periods for which data is available.  If a generator is served by two or more units, the gross electrical output of the generator will be attributed to each unit in proportion to the unit's share of the total control period heat input of these units for the control period.  The unit's converted gross electrical output will be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = GO (in MWh) ´ 1.0;

 

B)        If the unit is oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.6; or

 

C)        If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.4

 

2)         Heat input (HI):  If the unit has four or five control periods of data, the average of the unit's three highest heat inputs from the 2001, 2002, 2003, 2004 or 2005 control period will be used.  If the unit has three or fewer control periods of heat input data, the heat input will be the average of those control periods for which data is available.  The unit's converted gross electrical output will be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0967;

 

B)        If the unit is oil-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0580; or

 

C)        If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0387.

 

b)         For control periods 2012 and 2013, the owner or operator of the unit must submit in writing to the Agency, by June 1, 2008, a statement that either gross electrical output data or heat input data will be used to calculate the unit's converted gross electrical output.  The unit's converted gross electrical output shall be calculated pursuant to either subsection (b)(1) or (b)(2) of this Section:

 

1)         Gross electrical output:  The average of the unit's two most recent years of control period gross electrical output, if available.  If a unit commences commercial operation in the 2007 control period and does not have gross electrical output for the 2006 control period, then the gross electrical output from 2007 will be used.  If a generator is served by two or more units, the gross electrical output of the generator shall be attributed to each unit in proportion to the unit's share of the total control period heat input of such units for the control period.  The unit's converted gross electrical output shall be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = GO (in MWh) ´ 1.0;

 

B)        If the unit is oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.6;

 

C)        If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.4.

 

2)         Heat input:  The average of the unit's two most recent years of control period heat inputs, e.g., for the 2012 control period, the average of the unit's heat input from the 2006 and 2007 control periods.  The unit's converted gross electrical output shall be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0967;

 

B)        If the unit is oil-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0580; or

 

C)        If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0387.

 

c)         For control period 2014 and thereafter, the unit's gross electrical output will be the average of the unit's two most recent control period's gross electrical output, if available.  If a unit commences commercial operation in the most recent control period and does not have gross electrical output for two control periods, the gross electrical output from the most recent period, e.g., if the unit commences commercial operation in 2009 and does not have gross electrical output from 2008, gross electrical output from 2009 will be used.  If a generator is served by two or more units, the gross electrical output of the generator will be attributed to each unit in proportion to the unit's share of the total control period heat input of these units for the control period.  The unit's converted gross electrical output will be calculated as follows:

 

1)         If the unit is coal-fired:

CGO (in MWh) = GO (in MWh) ´ 1.0;

 

2)         If the unit is oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.6; or

 

3)         If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.4.

 

d)         For a unit that is a combustion turbine or boiler and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the Agency will add the converted gross electrical output calculated for electricity pursuant to subsection (a), (b), or (c) of this Section to the converted useful thermal energy (CUTE) to determine the total converted gross electrical output for the unit (TCGO).  The Agency will determine the converted useful thermal energy by using the average of the unit's control period useful thermal energy for the prior two control periods, if available.  In the first year for which a unit is considered to be an existing unit rather than a new unit, the unit's control period useful thermal output for the prior year will be used.  The converted useful thermal energy will be determined using the following equations:

 

1)         If the unit is coal-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.2930;

 

2)         If the unit is oil-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.1758; or

 

3)         If the unit is neither coal-fired nor oil-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.1172.

 

e)         The CAIR NO_x unit's converted gross electrical output and converted useful thermal energy in subsections (a)(1), (b)(1), (c), and (d) of this Section for each control period will be based on the best available data reported or available to the Agency for the CAIR NO_x unit pursuant to the provisions of Section 225.450.

 

f)         The CAIR NO_x unit's heat input in subsections (a)(2) and (b)(2) of this Section for each control period will be determined in accordance with 40 CFR 75, as incorporated by reference in Section 225.140.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.440  Annual Allocations

 

a)         For the 2009 control period, and each control period thereafter, the Agency will allocate to all CAIR NO_x units in Illinois for which the Agency has calculated the converted gross electrical output pursuant to Section 225.435(a), (b), or (c) or total converted gross electrical output pursuant to Section 225.435(d), as applicable, a total amount of CAIR NO_x allowances equal to tons of NO_x emissions in the CAIR NO_x Annual Trading budget available for allocation as determined in Section 225.425 and as adjusted to add allowances not allocated pursuant to subsection (b) of this Section in the previous year's allocation.

 

b)         The Agency will allocate CAIR NO_x allowances to each CAIR NO_x unit on a pro-rata basis using the unit's converted gross electrical output pursuant to Section 225.435(a), (b), or (c) or total converted gross electrical output calculated pursuant to Section 225.435(d), as applicable, to the extent whole allowances may be allocated.  The Agency will retain any additional allowances beyond this allocation of whole allowances for allocation pursuant to subsection (a) of this Section in the next control period.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.445  New Unit Set-Aside (NUSA)

 

For the 2009 control period and each control period thereafter, the Agency will allocate CAIR NO_x allowances from the NUSA to CAIR NO_x units that commenced commercial operation on or after January 1, 2006, and do not yet have an allocation for the particular control period or any preceding control period pursuant to Section 225.440, in accordance with the following procedures:

 

a)         Beginning with the 2009 control period and each control period thereafter, the Agency will establish a separate NUSA for each control period.  Each NUSA will be allocated CAIR NO_x allowances equal to five percent of the amount of tons of NO_x emissions in the base CAIR NO_x Annual Trading budget in Section 225.425.

 

b)         The CAIR designated representative of a new CAIR NO_x unit may submit to the Agency a request, in a format specified by the Agency, to be allocated CAIR NO_x allowances from the NUSA, starting with the first control period after the control period in which the new unit commences commercial operation and until the fifth control period after the control period in which the unit commenced commercial operation.  The NUSA allowance allocation request may only be submitted after a new unit has operated during one control period, and no later than March 1 of the control period for which allowances from the NUSA are being requested.

 

c)         In a NUSA allowance allocation request pursuant to subsection (b) of this Section, the CAIR designated representative must provide in its request information for gross electrical output and useful thermal energy, if any, for the new CAIR NO_x unit for that control period. 

 

d)         The Agency will allocate allowances from the NUSA to a new CAIR NO_x unit using the following procedures:

 

1)         For each new CAIR NO_x unit, the unit's gross electrical output for the most recent control period will be used to calculate the unit's gross electrical output.  If a generator is served by two or more units, the gross electrical output of the generator will be attributed to each unit in proportion to the unit's share of the total control period heat input of these units for the control period.  The new unit's converted gross electrical output will be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = GO (in MWh) ´ 1.0;

 

B)        If the unit is oil-fired:

CGO (in MW_h) = GO (in MWh) ´ 0.6; or

 

C)        If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.4.

 

2)         If the unit is a combustion turbine or boiler and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the Agency will add the converted gross electrical output calculated for electricity pursuant to subsection (d)(1) of this Section to the converted useful thermal energy to determine the total converted gross electrical output for the unit.  The Agency will determine the converted useful thermal energy using the unit's useful thermal energy for the most recent control period.  The converted useful thermal energy will be determined using the following equations:

 

A)        If the unit is coal-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.2930;

 

B)        If the unit is oil-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.1758; or

 

C)        If the unit is neither coal-fired nor oil-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.1172.

 

3)         The gross electrical output and useful thermal energy in subsections (d)(1) and (d)(2) of this Section for each control period will be based on the best available data reported or available to the Agency for the CAIR NO_x unit pursuant to the provisions of Section 225.450.

 

4)         The Agency will determine a unit's unprorated allocation (UA_y) using the unit's converted gross electrical output  plus the unit's converted useful thermal energy, if any, calculated in subsections (d)(1) and (d)(2) of this Section, converted to approximate NO_x tons (the unit's unprorated allocation), as follows:

 

UAy	=	NCGOy * (1.0 lbs/MWh)
		2000 lbs/ton

 

Where:

 

UAy	=	unprorated allocation to a new CAIR NOx unit.
NCGOy	=	converted gross electrical output or total converted gross electrical output, as applicable, for a new CAIR NOx unit.

 

5)         The Agency will allocate CAIR NO_x allowances from the NUSA to new CAIR NO_x units as follows:

 

A)        If the NUSA for the control period for which CAIR NO_x allowances are requested has a number of allowances greater than or equal to the total unprorated allocations for all new units requesting allowances, the Agency will allocate the number of allowances using the unprorated allocation determined for that unit pursuant to subsection (d)(4) of this Section, to the extent that whole allowances may be allocated.  For any additional allowances beyond this allocation of whole allowances, the Agency will retain the additional allowances in the NUSA for allocation pursuant to this Section in later control periods.

 

B)        If the NUSA for the control period for which the allowances are requested has a number of CAIR NO_x allowances less than the total unprorated allocation to all new CAIR NO_x units requesting allocations, the Agency will allocate the available allowances for new CAIR NO_x units on a pro-rata basis, using the unprorated allocation determined for that unit pursuant to subsection (d)(4) of this Section, to the extent that whole allowances may be allocated.  For any additional allowances beyond this allocation of whole allowances, the Agency will retain the additional allowances in the NUSA for allocation pursuant to this Section in later control periods.

 

e)         The Agency will review each NUSA allowance allocation request pursuant to subsection (b) of this Section.  The Agency will accept a NUSA allowance allocation request only if the request meets, or is adjusted by the Agency as necessary to meet, the requirements of this Section.

 

f)         By June 1 of the applicable control period, the Agency will notify each CAIR designated representative that submitted a NUSA allowance request of the amount of CAIR NO_x allowances from the NUSA, if any, allocated for the control period to the new unit covered by the request.

 

g)         The Agency will allocate CAIR NO_x allowances to new units from the NUSA no later than October 31 of the applicable control period.

 

h)         After a new CAIR NO_x unit has operated in one control period, it becomes an existing unit for the purposes of calculating future allocations in Section 225.440 only, and the Agency will allocate CAIR NO_x allowances for that unit, for the control period commencing five control periods after the control period in which the unit commences commercial operation, pursuant to Section 225.440.  For example, if a unit commences commercial operation in 2009, in 2010, the Agency will allocate to that unit allowances pursuant to Section 225.440 for the 2014 control period.  The new CAIR NO_x unit will continue to receive CAIR NO_x allowances from the NUSA according to this Section until the unit is eligible to use the CAIR NO_x allowances allocated to the unit pursuant to Section 225.440.

 

i)          If, after the completion of the procedures in subsection (c) of this Section for a control period, any unallocated CAIR NO_x allowances remain in the NUSA for the control period, the Agency will, at a minimum, accrue those CAIR NO_x allowances for future control period allocations to new CAIR NO_x units.  The Agency may from time to time elect to retire CAIR NO_x allowances in the NUSA that are in excess of 15,881 for the purposes of continued progress toward attainment and maintenance of National Ambient Air Quality Standards pursuant to the CAA.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.450  Monitoring, Recordkeeping and Reporting Requirements for Gross Electrical Output and Useful Thermal Energy

 

a)         By January 1, 2008, or by the date of commencing commercial operation, whichever is later, the owner or operator of the CAIR NO_x unit must operate a system for accurately measuring gross electrical output that is consistent with the requirements of either 40 CFR 60 or 75; must measure gross electrical output in MWh using such a system; and must record the output of the measurement system at all times.  If a generator is served by two or more units, the information to determine each unit's heat input for that control period must also be recorded, so as to allow each unit's share of the gross electrical output to be determined.  If heat input data is used, the owner or operator must comply with the applicable provisions of 40 CFR 75, as incorporated by reference in Section 225.140.

 

b)         For a CAIR NO_x unit that is a cogeneration unit, by January 1, 2008, or by the date the CAIR NO_x unit commences to produce useful thermal energy, whichever is later, the owner or operator of the unit with cogeneration capabilities must install, calibrate, maintain, and operate meters for steam flow in lbs/hr, temperature in degrees Fahrenheit, and pressure in PSI, to measure and record the useful thermal energy that is produced, in mmBtu/hr, on a continuous basis.  Owners and operators of a CAIR NO_x unit that produces useful thermal energy but uses an energy transfer medium other than steam, e.g., hot water or glycol, must install, calibrate, maintain, and operate the necessary meters to measure and record the necessary data to express the useful thermal energy produced, in mmBtu/hr, on a continuous basis.  If the CAIR NO_x unit ceases to produce useful thermal energy, the owner or operator may cease operation of the meters, provided that operation of these meters must be resumed if the CAIR NO_x unit resumes production of useful thermal energy.

 

c)         The owner or operator of a CAIR NO_x unit must either report gross electrical output data to the Agency or comply with the applicable provisions for providing heat input data to USEPA as follows:

 

1)         By September 15, 2007, the gross electrical output for control periods 2001, 2002, 2003, 2004 and 2005, if available, and the unit's useful thermal energy data, if applicable.  If a generator is served by two or more units, the documentation needed to determine each unit's share of the heat input of such units for that control period must also be submitted.  If heat input data is used, the owner or operator must comply with the applicable provisions of 40 CFR 75, as incorporated by reference in Section 225.140.

 

2)         By June 1, 2008, the gross electrical output for control periods 2006 and 2007, if available, and the unit's useful thermal energy data, if applicable.  If a generator is served by two or more units, the documentation needed to determine each unit's share of the heat input of such units for that control period must also be submitted.  If heat input data is used, the owner or operator must comply with the applicable provisions of 40 CFR 75, as incorporated by reference in Section 225.140.

 

d)         Beginning with 2008, the CAIR designated representative of the CAIR NO_x unit must submit to the Agency quarterly, by no later than April 30, July 31, October 31, and January 31 of each year, information for the CAIR NO_x unit's gross electrical output, on a monthly basis for the prior quarter, and, if applicable, the unit's useful thermal energy for each month.

 

e)         The owner or operator of a CAIR NO_x unit must maintain on-site the monitoring plan detailing the monitoring system, maintenance of the monitoring system, including quality assurance activities pursuant to the requirements of 40 CFR 60 or 75, as applicable, including the appropriate provisions for the measurement of gross electrical output for the CAIR NO_x Trading Program and, if applicable, for new units.  The monitoring plan must include, but is not limited to:

 

1)         A description of the system to be used for the measurement of gross electrical output pursuant to Section 225.450(a), including a list of any data logging devices, solid-state kW meters, rotating kW meters, electromechanical kW meters, current transformers, transducers, potential transformers, pressure taps, flow venturi, orifice plates, flow nozzles, vortex meters, turbine meters, pressure transmitters, differential pressure transmitters, temperature transmitters, thermocouples, resistance temperature detectors, and any equipment or methods used to accurately measure gross electrical output.

 

2)         A certification statement by the CAIR designated representative that all components of the gross electrical output system have been tested to be accurate within three percent and that the gross electrical output system is accurate to within ten percent.

 

f)         The owner or operator of a CAIR NO_x unit must retain records for at least five years from the date the record is created or the data is collected under subsections (a) and (b) of this Section, and the reports are submitted to the Agency and USEPA in accordance with subsections (c) and (d) of this Section.  The owner or operator of a CAIR NO_x unit must retain the monitoring plan required in subsection (e) of this Section for at least five years from the date that it is replaced by a new or revised monitoring plan.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.455  Clean Air Set-Aside (CASA)

 

a)         A project sponsor may apply for allowances from the CASA for sponsoring an energy efficiency and conservation, renewable energy, or clean technology project as set forth in Section 225.460 by submitting the application required by Section 225.470.

 

b)         Notwithstanding subsection (a) of this Section, a project sponsor with a CAIR NO_x source that is out of compliance with this Subpart for a given control period may not apply for allowances from the CASA for that control period.  If a source receives CAIR NO_x allowances from the CASA and then is subsequently found to have been out of compliance with this Subpart for the applicable control period or periods, the project sponsor must restore the CAIR NO_x allowances that it received pursuant to its CASA request or an equivalent number of CAIR NO_x allowances to the CASA within six months after receipt of an Agency notice that NO_x allowances must be restored.  These allowances will be assigned to the fund from which they were distributed.

 

c)         CAIR NO_x allowances from the CASA will be allocated in accordance with the procedures in Section 225.475.

 

d)         The project sponsor may submit an application that aggregates two or more projects under a CASA project category that would individually result in less than one allowance, but that equal at a minimum one whole allowance when aggregated. 

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.460  Energy Efficiency and Conservation, Renewable Energy, and Clean Technology Projects

 

a)         Energy efficiency and conservation project means any of the following projects implemented and located in Illinois:

 

1)         Demand side management projects that reduce overall power demand by using less energy include:

 

A)        Smart building management software that more efficiently regulates power flows.

 

B)        The use of or replacement to high efficiency motors, pumps, compressors, or steam systems.

 

C)        Lighting retrofits.

 

2)         Energy efficient new building construction projects include:

 

A)        ENERGY STAR-qualified new home projects.

 

B)        Measures to reduce or conserve energy consumption beyond the requirements of the Illinois Energy Conservation Code for Commercial Buildings [20 ILCS 687/6-3].

 

C)        New residential construction projects that qualify for Energy Efficient Tax Incentives pursuant to the Energy Policy Act of 2005 (42 USC 15801 (2005)).

 

3)         Supply-side energy efficiency projects include projects implemented to improve the efficiency in electricity generation by coal-fired power plants and the efficiency of electrical transmission and distribution systems.

 

4)         Highly efficient power generation projects, such as, but not limited to, combined cycle projects, combined heat and power, and microturbines.  To be considered a highly efficient power generation project pursuant to this subsection (a)(4), a project must meet the following applicable thresholds and criteria: 

 

A)        For combined heat and power projects generating both electricity and useful thermal energy for space, water, or industrial process heat, a rated-energy efficiency of at least 60 percent and is not a CAIR NO_x unit.

 

B)        For combined cycle projects rated at greater than 0.50 MW, a rated-energy efficiency of at least 50 percent.

 

C)        For microturbine projects rated at or below 0.50 MW and all other projects, a rated-energy efficiency of at least 40 percent.

 

b)         Renewable energy project means any of the following projects implemented and located in Illinois:

 

1)         Zero-emission electric generating projects, including wind, solar (thermal or photovoltaic), and hydropower projects.  Eligible hydropower plants are restricted to new generators, that are not replacements of existing generators, that commenced operation on or after January 1, 2006, and that do not involve the significant expansion of an existing dam or the construction of a new dam.

 

2)         Renewable energy units are those units that generate electricity using more than 50 percent of the heat input, on an annual basis, from dedicated crops grown for energy production or the capture systems for methane gas from landfills, water treatment plants or sewage treatment plants, and organic waste biomass, and other similar sources of non-fossil fuel energy.  Renewable energy projects do not include energy from incineration by burning or heating of waste wood, tires, garbage, general household waste, institutional lunchroom waste, office waste, landscape waste, or construction or demolition debris.

 

c)         Clean technology project for reducing emissions from producing electricity and useful thermal energy means any of the following projects implemented and located in Illinois:

 

1)         Air pollution control equipment upgrades at existing coal-fired EGUs, as follows: installation of flue gas desulfurization (FGD) for control of SO₂ emissions; installation of a baghouse for control of particulate matter emissions; and installation of selective catalytic reduction (SCR), selective non-catalytic reduction (SNCR), or other add-on control devices for control of NO_x emissions.  For this purpose, a unit will be considered "existing" after it has been in commercial operation for at least eight years.  Air pollution control upgrade projects do not include the addition of low NO_x burners, overfired air techniques or gas reburning techniques for control of NO_x emissions; projects involving flue gas conditioning techniques or upgrades, or replacement of electrostatic precipitators; or addition of an activated carbon injection or other sorbent injection system for control of mercury.

 

2)         Clean coal technologies projects include:

 

A)        Integrated gasification combined cycle (IGCC) plants.

 

B)        Fluidized bed coal combustion that commenced operation prior to December 31, 2006.

 

d)         In addition to those projects excluded in subsections (a) through (c) of this Section, the following projects are also not energy efficiency and conservation, renewable energy, or clean technology projects:

 

1)         Nuclear power projects.

 

2)         Projects required to meet emission standards or technology requirements under State or federal law or regulation, except that allowances may be allocated for:

 

A)        The installation of a baghouse.

 

B)        Projects undertaken pursuant to Section 225.233 or Subpart F.

 

3)         Projects used to meet the requirements of a court order or consent decree, except that allowances may be allocated for:

 

A)        Emission rates or limits achieved that are lower than what is required to meet the emission rates or limits for SO₂ or NO_x, or for installing a baghouse as provided for in a court order or consent decree entered into before May 30, 2006.

 

B)        Projects used to meet the requirements of a court order or consent decree entered into on or after May 30, 2006, if the court order or consent decree does not specifically preclude such allocations.

 

4)         A Supplemental Environmental Project (SEP).

 

e)         Applications for projects implemented and located in Illinois that are not specifically listed in subsections (a) through (c) of this Section, and that are not specifically excluded by definition in subsections (a) through (c) of this Section or by specific exclusion in subsection (d) of this Section, may be submitted to the Agency.  The application must designate which category or categories from those listed in subsections (a)(1) through (c)(2)(B) of this Section best fit the proposed project and the applicable formula pursuant to Section 225.465(b) to calculate the number of allowances that it is requesting.  The Agency will determine whether the application is approvable based on a sufficient demonstration by the project sponsor that the project is a new type of energy efficiency, renewable energy, or clean technology project, similar in its effects as the projects specifically listed in subsections (a) through (c)(2)(B) of this Section.

 

f)         Early adopter projects include projects that meet the criteria for any energy efficiency and conservation, renewable energy, or clean technology projects listed in subsections (a), (b), (c), and (e) of this Section and commence construction between July 1, 2006 and December 31, 2012.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.465  Clean Air Set-Aside (CASA) Allowances

 

a)         The CAIR NO_x allowances for the CASA for each control period will be assigned to the following categories of projects:

 

		Phase I	Phase II
		(2009-2014)	(2015 and thereafter)
1)	Energy Efficiency and Conservation/Renewable Energy	9149	7625
2)	Air Pollution Control Equipment Upgrades	3811	3175
3)	Clean Coal Technology	4573	3810
4)	Early Adopters	1525	1271

 

b)         The following formulas must be used to determine the number of CASA allowances that may be allocated to a project per control period:

 

1)         For an energy efficiency and conservation project pursuant to Section 225.460(a)(1) through (a)(4)(A), the number of allowances must be calculated using the number of megawatt hours of electricity that was not consumed during a control period and the following formula:

 

A

=

(MWhc) ´ (1.5 lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhc	=	The number of megawatt hours of electricity conserved or generated during a control period by a project.

 

2)         For a zero emission electric generating project pursuant to Section 225.460(b)(1), the number of allowances must be calculated using the number of megawatt hours of electricity generated during a control period and the following formula:

 

A

=

(MWhg) ´ (2.0 lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project
MWhg	=	The number of megawatt hours of electricity generated during a control period by a project.

 

3)         For a renewable energy emission unit pursuant to Section 225.460(b)(2), the number of allowances must be calculated using the number of MWhs of electricity generated during a control period and the following formula:

 

A

=

(MWhg) ´ (0.5 lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhg	=	The number of MW hours of electricity generated during a control period by a project.

 

4)         For an air pollution control equipment upgrade project pursuant to Section 225.460(c)(1), the number of allowances will be calculated as follows:

 

A)        For NO_x or SO₂ control projects, by determining the difference in emitted NO_x or SO₂ per control period using the emission rate before and after replacement or improvement, and the following formula:

 

A

=

(MWhg) ´ K ´ (ERB  lb/MWh - ERA  lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhg	=	The number of megawatt hours of electricity generated during a control period by a project.
K	=	The pollutant factor:  for NOx, K= 0.1; and for SO2, K = 0.05.
ERB	=	Average NOx or SO2 emission rate based on CEMS data from the most recent two control periods prior to the replacement or improvement of the control equipment in lb/MWh, unless subject to a court order or consent decree.  For units subject to a court order or consent decree entered into before May 30, 2006, ERB is limited to emission rates that are lower than the emission rate required in the consent decree or court order.  For a court order or consent decree entered into after May 30, 2006, ERB is limited to the lesser of the emission rate specified in the court order or consent decree or the actual average emission rate during the control period.  If such limit is not expressed in lb/MWh, the limit must be converted into lb/MWh using a heat rate of 10 mmBtu/1 MW.
ERA	=	Annual NOx or SO2 average emission rate for the applicable control period data based on CEMS data in lb/MWh.

 

B)        For a baghouse project:

 

A

=

(MWhg) ´ (Q lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhg	=	The number of MWh of electricity generated during a control period or the portion of a control period that the units were controlled by the baghouse.
Q	=	•    If a baghouse was not installed pursuant to a consent decree or court order, 0.2. •    If a baghouse was installed pursuant to a consent decree or court order that assigns a Q factor, the factor established in the consent decree or court order but must not exceed a factor of 0.2. •    If a baghouse was installed pursuant to a consent decree or court order that does not assign a Q factor, then Q shall equal: Q = 0.25 - (P ´ ERq)

 

Where:

 

P	=	If the most recent control period's average PM emission rate was based on PM CEMS data, 1.0; otherwise 1.1.
ERq	=	The magnitude of the most recent control period's average PM emission rate in lb/MWh exiting the baghouse, subject to the following limits:
		If P	=	1.0, then 1/10 ≤ ERq ≤ 2/10
		If P	=	1.1, then 1/11 ≤ ERq ≤ 2/11

 

•   If the ERq is less than the lower limit, the lower limit shall be used.

•   If ERq is greater than the upper limit, the upper limit shall be used.

•   If ERq is not expressed in lb/MWh, the number must be converted to lb/MWh using a heat rate of 10 mmBtu/1 MW.

 

5)         For highly efficient power generation and clean coal technology projects:

 

A)        For projects other than fluidized coal combustion pursuant to Section 225.460(a)(4)(B), (a)(4)(C), and (c)(2), the number of allowances must be calculated using the number of MWh of electricity the project generates during a control period and the following formula:

 

A

=

(MWhg) ´ (1.0 lb/MWh - ER lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhg	=	The number of megawatt hours of electricity generated during a control period by a project.
ER	=	Annual average NOx emission rate based on CEMS data in lb/MWh.

 

B)        For fluidized bed coal combustion projects pursuant to Section 225.460(c)(2), the number of allowances shall be calculated using the number of gross MWh of electricity the project generates during a control period and the following formula:

 

A

=

(MWhg) ´ (1.4 lb/MWh - ER lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhg	=	The number of gross MWh of electricity generated during a control period by a project.
ER	=	Annual NOx emission rate for the control period based on CEMS data in lb/MWh.

 

6)         For a CASA project that commences construction before December 31, 2012, in addition to the allowances allocated pursuant to subsections (b)(1) through (b)(5) of this Section, a project sponsor may also request additional allowances pursuant to the early adopter project category pursuant to Section 225.460(e) based on the following formula:

 

A

=

1.0 + 0.10 ´ Σ Ai

 

Where:

 

A	=	The number of allowances for a particular project as determined in subsections (b)(1) through (b)(5) of this Section.
Ai	=	The number of allowances as determined in subsection (b)(1), (b)(2), (b)(3), (b)(4) or (b)(5) of this Section for a given project.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.470  Clean Air Set-Aside (CASA) Applications

 

a)         A project sponsor may request allowances if the project commenced construction on or after the dates listed in this subsection.  The project sponsor may request and be allocated allowances from more than one CASA category for a project, if applicable.

 

1)         Demand side management, energy efficient new construction, and supply side energy efficiency and conservation projects that commenced construction on or after January 1, 2003;

 

2)         Fluidized bed coal combustion projects, highly efficient power generation operations projects, or renewable energy emission units, that commenced construction on or after January 1, 2001; and

 

3)         All other projects on or after July 1, 2006.

 

b)         Beginning with the 2009 control period and each control period thereafter, a project sponsor may request allowances from the CASA.  The application must be submitted to the Agency by May 1 of the control period for which the allowances are being requested.

 

c)         The allocation will be based on the electricity conserved or generated in the control period preceding the calendar year in which the application is submitted.  To apply for a CAIR NO_x allocation from the CASA, project sponsors must provide the Agency with the following information:

 

1)         Identification of the project sponsor, including name, address, type of organization, certification that the project sponsor has met the definition of "project sponsor" as set forth in Section 225.130, and names of the principals or corporate officials.

 

2)         The number of the CAIR NO_x general or compliance account for the project and the name of the associated CAIR account representative.

 

3)         A description of the project or projects, location, the role of the project sponsor in the projects, and a general explanation of how the amount of energy conserved or generated was measured, verified, and calculated, and the number of allowances requested with the supporting calculations.  The number of allowances requested will be calculated using the applicable formula from Section 225.470(b).

 

4)         Detailed information to support the request for allowances, including the following types of documentation for the measurement and verification of the NO_x emissions reductions, electricity generated, or electricity conserved using established measurement verification procedures, as applicable.  The measurement and verification required will depend on the type of project proposed.

 

A)        As applicable, documentation of the project's base and control period conditions and resultant base and control period energy data, using the procedures and methods included in M&V Guidelines:  Measurement and Verification for Federal Energy Projects, incorporated by reference in Section 225.140, or other method approved by the Agency.  Examples include:

 

i)          Energy consumption and demand profiles;

 

ii)         Occupancy type;

 

iii)        Density and periods;

 

iv)        Space conditions or plant throughput for each operating period and season. (For example, in a building this would include the light level and color, space temperature, humidity and ventilation);

 

v)         Equipment inventory, nameplate data, location, and condition; and

 

vi)        Equipment operating practices (schedules and set points, actual temperatures/pressures);

 

B)        Emissions data, including, if applicable, CEMS data;

 

C)        Information for rated-energy efficiency, including supporting documentation and calculations; and

 

D)        Electricity, in MWh generated or conserved for the applicable control period.

 

5)         Notwithstanding the requirements of subsection (c)(4) of this Section, applications for fewer than five allowances may propose other reliable and applicable methods of quantification acceptable to the Agency.

 

6)         Any additional information requested by the Agency to determine the correctness of the requested number of allowances, including site information, project specifications, supporting calculations, operating procedures, and maintenance procedures.

 

7)         The following certification by the responsible official for the project sponsor and the applicable CAIR account representative for the project:

 

"I am authorized to make this submission on behalf of the project sponsor and the holder of the CAIR NO_x general account or compliance account for which the submission is made.  I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this application and all its attachments.  Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete.  I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information." 

 

d)         A project sponsor may request allowances from the CASA for each project for a total number of control periods not to exceed the number of control periods listed in this subsection.  After a project has been allocated allowances from the CASA, subsequent requests for the project from the project sponsor must include the information required by subsections (c)(1), (c)(2), (c)(3) and (c)(7) of this Section, a description of any changes, or further improvements made to the project, and information specified in subsections (c)(5) and (c)(6) as specifically requested by the Agency.

 

1)         For energy efficiency and conservation projects (except for efficient operation and renewable energy projects), for a total of eight control periods. 

 

2)         For early adopter projects, for a total of ten control periods. 

 

3)         For air pollution control equipment upgrades, for a total of 15 control periods. 

 

4)         For renewable energy projects, clean coal technology, and highly efficient power generation projects, for each year that the project is in operation. 

 

e)         A project sponsor must keep copies of all CASA applications and the documentation used to support the application for at least five years.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.475  Agency Action on Clean Air Set-Aside (CASA) Applications

 

a)         By September 1, 2009 and each September 1 thereafter, the Agency will determine the total number of allowances that are approvable for allocation to project sponsors based upon the applications submitted pursuant to Section 225.470. 

 

1)         The Agency will determine the number of CAIR NO_x allowances that are approvable based on the formulas and the criteria for these projects.  The Agency will notify a project sponsor within 90 days after receipt of an application if the project is not approvable, the number of allowances requested is not approvable, or additional information is needed by the Agency to complete its review of the application.

 

2)         If the total number of CAIR NO_x allowances requested for approved projects is less than or equal to the number of CAIR NO_x allowances in the CASA project category, the number of allowances that are approved will be allocated to each CAIR NO_x compliance or general account. 

 

3)         If more CAIR NO_x allowances are requested than the number of CAIR NO_x allowances in a given CASA project category, allowances will be allocated on a pro-rata basis based on the number of allowances available, subject to further adjustment as provided for by subsection (b) of this Section.  CAIR NO_x allowances will be allocated, transferred, or used as whole allowances.  The number of whole allowances will be determined by rounding down for decimals less than 0.5 and rounding up for decimals of 0.5 or greater.

 

b)         For control periods 2011 and thereafter:

 

1)         If there are, after the completion of the procedures in subsection (a) of this Section for a control period, any CAIR NO_x allowances not allocated to a CASA project for the control period the remaining allowances will accrue in each CASA project category up to twice the number of allowances that are assigned to the project category each control period as set forth in Section 225.465.

 

2)         If any allowances remain after allocations pursuant to subsection (b)(1) of this Section, the Agency will allocate these allowances pro rata to projects that received fewer allowances than requested, based on the number of allowances not allocated but approved by the Agency for the project under CASA.  No project may be allocated more allowances than approved by the Agency for the applicable control period.

 

3)         If any allowances remain after the allocation of allowances pursuant to subsection (b)(2) of this Section, the Agency will then distribute pro-rata the remaining allowances to project categories that have fewer than twice the number of allowances assigned to that project category.  The pro-rata distribution will be based on the difference between two times the project category and the number of allowances that remain in the project category.

 

4)         If allowances still remain undistributed after the allocations and distributions in the subsections (b)(1) through (b)(3) are completed, the Agency may elect to retire the CAIR NO_x allowances that have not been distributed to any CASA category to continue progress toward attainment or maintenance of the National Ambient Air Quality Standards pursuant to the CAA.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.480  Compliance Supplement Pool

 

In addition to the CAIR NO_x allowances allocated pursuant to Section 225.425, the USEPA has allowed allocation of an additional 11,299 CAIR NO_x allowances in Illinois as a compliance supplement pool to Illinois for the control period in 2009.  However, for the purposes of public health and air quality improvements, none of these allowances will be allocated.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.500  Purpose

 

The purpose of this Subpart E is to control the seasonal emissions of nitrogen oxides (NO_x) from EGUs by determining allocations and implementing the CAIR NO_x Ozone Season Trading Program.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.505  Applicability

 

a)         Except as provided in subsections (b)(1), (b)(3), and (b)(4) of this Section:

 

1)         The following units are CAIR NO_x Ozone Season units, and any source that includes one or more such units is a CAIR NO_x source subject to the requirements of this Subpart E:  any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

 

2)         If a stationary boiler or stationary combustion turbine that, pursuant to subsection (a)(1) of this Section, is not a CAIR NO_x Ozone Season unit begins to combust fossil fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the unit will become a CAIR NO_x Ozone Season unit as provided in subsection (a)(1) of this Section on the first date on which it both combusts fossil fuel and serves such generator.

 

b)         The units that meet the requirements set forth in subsections (b)(1), (b)(3), and (b)(4) of this Section will not be CAIR NO_x Ozone Season units and units that meet the requirements of subsections (b)(2) and (b)(5) of this Section are CAIR NO_x Ozone Season units:

 

1)         Any unit that would otherwise be classified as a CAIR NO_x Ozone Season unit pursuant to subsection (a)(1) or (a)(2) of this Section and:

 

A)        Qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continues to qualify as a cogeneration unit; and

 

B)        Does not serve at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution for sale.

 

2)         If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and meets the requirements of subsection (b)(1) of this Section for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become a CAIR NO_x Ozone Season unit starting on the earlier of January 1 after the first calendar year during which the unit no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of subsection (b)(1)(B) of this Section.

 

3)         Any unit that would otherwise be classified as a CAIR NO_x Ozone Season unit pursuant to subsection (a)(1) or (a)(2) of this Section commencing operation before January 1, 1985 and:

 

A)        Qualifies as a solid waste incineration unit; and

 

B)        Has an average annual fuel consumption of non-fossil fuel for 1985-1987 exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any three consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).

 

4)         Any unit that would otherwise be classified as a CAIR NO_x Ozone Season unit under subsection (a)(1) or (a)(2) of this Section commencing operation on or after January 1, 1985 and:

 

A)        Qualifies as a solid waste incineration unit; and

 

B)        Has an average annual fuel consumption of non-fossil fuel the first three years of operation exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any three consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).

 

5)         If a unit qualifies as a solid waste incineration unit and meets the requirements of subsection (b)(3) or (b)(4) of this Section for at least three consecutive years, but subsequently no longer meets all such requirements, the unit shall become a CAIR NO_x Ozone Season unit starting on the earlier of January 1 after the first three consecutive calendar years after 1990 for which the unit has an average annual fuel consumption of 20 percent or more.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.510  Compliance Requirements

 

a)         The designated representative of a CAIR NO_x Ozone Season unit must comply with the requirements of the CAIR NO_x Ozone Season Trading Program for Illinois as set forth in this Subpart E and 40 CFR 96, subpart AAAA (CAIR NO_x Ozone Season Trading Program General Provisions) (excluding 40 CFR  96.304, 96.305(b)(2), and 96.306); 40 CFR 96, subpart BBBB (CAIR Designated Representative for CAIR NO_x Ozone Season Sources); 40 CFR 96, subpart FFFF (CAIR NO_x Ozone Season Allowance Tracking System); 40 CFR 96, subpart GGGG (CAIR NO_x Ozone Season Allowance Transfers); and 40 CFR  96, subpart HHHH (Monitoring and Reporting); as incorporated by reference in Section 225.140.

 

b)         Permit requirements:

 

1)         The designated representative of each source with one or more CAIR NO_x Ozone Season units at the source must apply for a permit issued by the Agency with federally enforceable conditions covering the CAIR NO_x Ozone Season Trading Program ("CAIR permit") that complies with the requirements of Section 225.520 (Permit Requirements).

 

2)         The owner or operator of each CAIR NO_x Ozone Season source and each CAIR NO_x Ozone Season unit at the source must operate the CAIR NO_x Ozone Season unit in compliance with its CAIR permit.

 

c)         Monitoring requirements:

 

1)         The owner or operator of each CAIR NO_x Ozone Season source and each CAIR NO_x Ozone Season unit at the source must comply with the monitoring, reporting and recordkeeping requirements of 40 CFR 96, subpart HHHH; 40 CFR 75; and Section 225.550.  The CAIR designated representative of each CAIR NO_x Ozone Season source and each CAIR NO_x Ozone Season unit at the source must comply with those sections of the monitoring, reporting and recordkeeping requirements of 40 CFR 96, subpart HHHH, applicable to a CAIR designated representative.

 

2)         The compliance of each CAIR NO_x Ozone Season source with the CAIR NO_x Ozone Season emissions limitation pursuant to subsection (d) of this Section will be determined by the emissions measurements recorded and reported in accordance with 40 CFR 96, subpart HHHH.

 

d)         Emission requirements:

 

1)         By the allowance transfer deadline, midnight of November 30, 2009, and by midnight of November 30 of each subsequent year if November 30 is a business day, the owner or operator of each CAIR NO_x Ozone Season source and each CAIR NO_x Ozone Season unit at the source must hold allowances available for compliance deductions pursuant to 40 CFR 96.354(a) in the CAIR NO_x Ozone Season source's compliance account.  If November 30 is not a business day, the allowance transfer deadline means by midnight of the first business day thereafter.  The number of allowances held may not be less than the tons of NO_x emissions for the control period from all CAIR NO_x Ozone Season units at the CAIR NO_x Ozone Season source, as determined in accordance with 40 CFR 96, subpart HHHH.

 

2)         Each ton of excess emissions of a CAIR NO_x Ozone Season source for each day in a control period, starting in 2009 will constitute a separate violation of this Subpart E, the Act, and the CAA.

 

3)         Each CAIR NO_x Ozone Season unit will be subject to the requirements of subsection (d)(1) of this Section for the control period starting on the later of May 1, 2009 or the deadline for meeting the unit's monitoring certification requirements pursuant to 40 CFR  96.370(b)(1), (b)(2) or (b)(3) and for each control period thereafter.

 

4)         CAIR NO_x Ozone Season allowances must be held in, deducted from, or transferred into or among allowance accounts in accordance with this Subpart and 40 CFR 96, subparts FFFF and GGGG.

 

5)         In order to comply with the requirements of subsection (d)(1) of this Section, a CAIR NO_x Ozone Season allowance may not be deducted for compliance according to subsection (d)(1) of this Section for a control period in a calendar year before the year for which the CAIR NO_x Ozone Season allowance is allocated.

 

6)         A CAIR NO_x Ozone Season allowance is a limited authorization to emit one ton of NO_x in accordance with the CAIR NO_x Ozone Season Trading Program.  No provision of the CAIR NO_x Ozone Season Trading Program, the CAIR permit application, the CAIR permit, or a retired unit exemption pursuant to 40 CFR 96.305, and no provision of law, will be construed to limit the authority of the United States or the State to terminate or limit this authorization.

 

7)         A CAIR NO_x Ozone Season allowance does not constitute a property right.

 

8)         Upon recordation by USEPA pursuant to 40 CFR 96, subpart FFFF or GGGG, every allocation, transfer, or deduction of a CAIR NO_x Ozone Season allowance to or from a CAIR NO_x Ozone Season source compliance account is deemed to amend automatically, and become a part of, any CAIR permit of the CAIR NO_x Ozone Season source.  This automatic amendment of the CAIR permit will be deemed an operation of law and will not require any further review.

 

e)         Recordkeeping and reporting requirements:

 

1)         Unless otherwise provided, the owner or operator of the CAIR NO_x Ozone Season source and each CAIR NO_x Ozone Season unit at the source must keep on site at the source each of the documents listed in subsections (e)(1)(A) through (e)(1)(E) of this Section for a period of five years from the date the document is created.  This period may be extended for cause, at any time prior to the end of five years, in writing by the Agency or USEPA.

 

A)        The certificate of representation for the CAIR designated representative for the source and each CAIR NO_x Ozone Season unit at the source, all documents that demonstrate the truth of the statements in the certificate of representation, provided that the certificate and documents must be retained on site at the source beyond such five-year period until the documents are superseded because of the submission of a new certificate of representation, pursuant to 40 CFR 96.313, changing the CAIR designated representative.

 

B)        All emissions monitoring information, in accordance with 40 CFR 96, subpart HHHH.

 

C)        Copies of all reports, compliance certifications, and other submissions and all records made or required pursuant to the CAIR NO_x Ozone Season Trading Program or documents necessary to demonstrate compliance with the requirements of the CAIR NO_x Ozone Season Trading Program or with the requirements of this Subpart E.

 

D)        Copies of all documents used to complete a CAIR permit application and any other submission or documents used to demonstrate compliance pursuant to the CAIR NO_x Ozone Season Trading Program.

 

E)        Copies of all records and logs for gross electrical output and useful thermal energy required by Section 225.550.

 

2)         The CAIR designated representative of a CAIR NO_x Ozone Season source and each CAIR NO_x Ozone Season unit at the source must submit to the Agency and USEPA the reports and compliance certifications required pursuant to the CAIR NO_x Ozone Season Trading Program, including those pursuant to 40 CFR 96, subpart HHHH and Section 225.550.

 

f)         Liability:

 

1)         No revision of a permit for a CAIR NO_x Ozone Season unit may excuse any violation of the requirements of this Subpart E or the requirements of the CAIR NO_x Ozone Season Trading Program.

 

2)         Each CAIR NO_x Ozone Season source and each CAIR NO_x Ozone Season unit must meet the requirements of the CAIR NO_x Ozone Season Trading Program.

 

3)         Any provision of the CAIR NO_x Ozone Season Trading Program that applies to a CAIR NO_x Ozone Season source (including any provision applicable to the CAIR designated representative of a CAIR NO_x Ozone Season source) will also apply to the owner and operator of the CAIR NO_x Ozone Season source and to the owner and operator of each CAIR NO_x Ozone Season unit at the source.

 

4)         Any provision of the CAIR NO_x Ozone Season Trading Program that applies to a CAIR NO_x Ozone Season unit (including any provision applicable to the CAIR designated representative of a CAIR NO_x Ozone Season unit) will also apply to the owner and operator of the CAIR NO_x Ozone Season unit. 

 

5)         The CAIR designated representative of a CAIR NO_x Ozone Season unit that has excess emissions in any control period must surrender the allowances as required for deduction pursuant to 40 CFR 96.354(d)(1).

 

6)         The owner or operator of a CAIR NO_x Ozone Season unit that has excess NO_x emissions in any control period must pay any fine, penalty, or assessment or comply with any other remedy imposed pursuant to the Act and 40 CFR 96.354(d)(2).

 

g)         Effect on other authorities:  No provision of the CAIR NO_x Ozone Season Trading Program, a CAIR permit application, a CAIR permit, or a retired unit exemption pursuant to 40 CFR 96.305 will be construed as exempting or excluding the owner and operator and, to the extent applicable, the CAIR designated representative of a CAIR NO_x Ozone Season source or a CAIR NO_x Ozone Season unit from compliance with any other regulation promulgated pursuant to the CAA, the Act, any State regulation or permit, or a federally enforceable permit.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.515  Appeal Procedures

 

The appeal procedures for decisions of USEPA pursuant to the CAIR NO_x Ozone Season Trading Program are set forth in 40 CFR 78, as incorporated by reference in Section 225.140.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.520  Permit Requirements

 

a)         Permit requirements:

 

1)         The owner or operator of each source with a CAIR NO_x Ozone Season unit is required to submit:

 

A)        A complete permit application addressing all applicable CAIR NO_x Ozone Season Trading Program requirements for a permit meeting the requirements of this Section, applicable to each CAIR NO_x Ozone Season unit at the source.  Each CAIR permit must contain elements required for a complete CAIR permit application pursuant to subsection (b)(2) of this Section.

 

B)        Any supplemental information that the Agency determines necessary in order to review a CAIR permit application and issue any CAIR permit.

 

2)         Each CAIR permit will be issued pursuant to Sections 39 and 39.5 of the Act and will contain federally enforceable conditions addressing all applicable CAIR NO_x Ozone Season Trading Program requirements and will be a complete and segregable portion of the source's entire permit pursuant to subsection (a)(1) of this Section.

 

3)         No CAIR permit may be issued until the Agency and USEPA have received a complete certificate of representation for a CAIR designated representative pursuant to 40 CFR 96, subpart BBBB, for the CAIR NO_x Ozone Season source and the CAIR NO_x Ozone Season unit at the source.

 

4)         For all CAIR NO_x Ozone Season units that commenced operation before December 31, 2007, the owner or operator of the unit must submit a CAIR permit application meeting the requirements of this Section on or before December 31, 2007.

 

5)         For all units that commence operation on or after December 31, 2007, the owner or operator of these units must submit applications for construction and operating permits pursuant to the requirements of Sections 39 and 39.5 of the Act, as applicable, and 35 Ill. Adm. Code 201, and the applications must specify that they are applying for CAIR permits and must address the CAIR permit application requirements of this Section 225.520.

 

b)         Permit applications:

 

1)         Duty to apply:  The owner or operator of any source with one or more CAIR NO_x Ozone Season units must submit to the Agency a CAIR permit application for the source covering each CAIR NO_x Ozone Season unit pursuant to subsection (b)(2) of this Section by the applicable deadline in subsection (a)(4) or (a)(5) of this Section.  The owner or operator of any source with one or more CAIR NO_x Ozone Season units must reapply for a CAIR permit for the source as required by this Subpart, 35 Ill. Adm. Code 201, and, as applicable, Sections 39 and 39.5 of the Act.

 

2)         Information requirements for CAIR permit applications.  A complete CAIR permit application must include the following elements concerning the source for which the application is submitted:

 

A)        Identification of the source, including plant name.  The ORIS (Office of Regulatory Information Systems) or facility code assigned to the source by the Energy Information Administration must also be included, if applicable;

 

B)        Identification of each CAIR NO_x Ozone Season unit at the source; and

 

C)        The compliance requirements applicable to each CAIR NO_x Ozone Season unit as set forth in Section 225.510.

 

3)         An application for a CAIR permit will be treated as a modification of the CAIR NO_x Ozone Season source's existing federally enforceable permit, if such a permit has been issued for that source, and will be subject to the same procedural requirements.  When the Agency issues a CAIR permit pursuant to the requirements of this Section, it will be incorporated into and become part of that source's existing federally enforceable permit.

 

c)         Permit content:  Each CAIR permit is deemed to incorporate automatically the definitions and terms specified in Section 225.130 and 40 CFR 96.302, as incorporated by reference in Section 225.140, and, upon recordation of USEPA under 40 CFR 96, subparts FFFF and GGGG, as incorporated by reference in Section 225.140, every allocation, transfer, or deduction of a CAIR NO_x Ozone Season allowance to or from the compliance account of the CAIR NO_x Ozone Season source covered by the permit.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.525  Ozone Season Trading Budget

 

The CAIR NO_x Ozone Season Trading budget available for allowance allocations for each control period will be determined as follows:

 

a)         The total base CAIR NO_x Ozone Season Trading budget is 30,701 tons per control period for the years 2009 through 2014, subject to a reduction for two set-asides, the NUSA and the CASA.  Five percent of the budget will be allocated to the NUSA and 25 percent will be allocated to the CASA, resulting in a CAIR NO_x Ozone Season Trading budget available for allocation of 21,491 tons per control period pursuant to Section 225.540.  The requirements of the NUSA are set forth in Section 225.545, and the requirements of the CASA are set forth in Sections 225.555 through 225.570.

 

b)         The total base CAIR NO_x Ozone Season Trading budget is 28,981 tons per control period for the year 2015 and thereafter, subject to a reduction for two set-asides, the NUSA and the CASA.  Five percent of the budget will be allocated to the NUSA and 25 percent will be allocated to the CASA, resulting in a CAIR NO_x Ozone Season Trading budget available for allocation of 20,287 tons per control period pursuant to Section 225.540.

 

c)         If USEPA adjusts the total base CAIR NO_x Ozone Season Trading budget for any reason, the Agency will adjust the base CAIR NO_x Ozone Season Trading budget and the CAIR NO_x Ozone Season Trading budget available for allocation, accordingly.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.530  Timing for Ozone Season Allocations

 

a)         On or before September 25, 2007, the Agency will submit to USEPA the CAIR NO_x Ozone Season allowance allocations, in accordance with Sections 225.535 and 225.540, for the 2009, 2010, and 2011 control periods.

 

b)         By July 1, 2008 and July 31 of each year thereafter, the Agency will submit to USEPA the CAIR NO_x Ozone Season allowance allocations in accordance with Sections 225.535 and 225.540, for the control period four years after the year of the applicable deadline for submission pursuant to this Section.  For example, on July 31, 2008, the Agency will submit to USEPA the allocation for the 2012 control period.

 

c)         For CAIR NO_x Ozone Season units that commence commercial operation on or after May 1, 2006, that have not been allocated allowances under Section 225.440 for the applicable or any preceding control period, the Agency will allocate allowances from the NUSA in accordance with Section 225.545.  The Agency will report these allocations to USEPA by July 31 of the applicable control period.  For example, on July 31, 2009, the Agency will submit to USEPA the allocations from the NUSA for the 2009 control period.

 

d)         The Agency will allocate allowances from the CASA to energy efficiency, renewable energy, and clean technology projects pursuant to the criteria in Sections 225.555 through 225.570.  The Agency will report these allocations to USEPA by October 1 of each year.  For example, on October 1, 2009, the Agency will submit to USEPA the allocations from the CASA for the 2009 control period, based on reductions made in the 2008 control period.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.535  Methodology for Calculating Ozone Season Allocations

 

The Agency will calculate converted gross electrical output (CGO), in MWh, for each CAIR NO_x Ozone Season unit that has operated during at least one control period prior to the calendar year in which the Agency reports the allocations to USEPA as follows:

 

a)         For control periods 2009, 2010, and 2011, the owner or operator of the unit must submit in writing to the Agency, by September 15, 2007, a statement that either gross electrical output data or heat input data is to be used to calculate converted gross electrical output.  The data shall be used to calculate converted gross electrical output pursuant to either subsection (a)(1) or (a)(2) of this Section:

 

1)         Gross electrical output:  If the unit has four or five control periods of data, then the gross electrical output (GO) will be the average of the unit's three highest gross electrical outputs from the 2001, 2002, 2003, 2004, or 2005 control periods.  If the unit has three or fewer control periods of gross electrical outputs, the gross electrical output will be the average of those control periods for which data is available.  If a generator is served by two or more units, then the gross electrical output of the generator will be attributed to each unit in proportion to the unit's share of the total control period heat input of these units for the control period.  The unit's converted gross electrical output will be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = GO (in MWh) ´ 1.0;

 

B)        If the unit is oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.6; or

 

C)        If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.4.

 

2)         Heat input (HI):  If the unit has four or five control periods of data, the average of the unit's three highest control period heat inputs from 2001, 2002, 2003, 2004, or 2005 will be used.  If the unit has three or fewer control periods of heat input data, the heat input will be the average of those control periods for which data is available.  The unit's converted gross electrical output will be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0967;

 

B)        If the unit is oil-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0580; or

 

C)        If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0387.

 

b)         For control periods 2012 and 2013, the owner or operator of the unit must submit in writing to the Agency, by June 1, 2008, a statement that either gross electrical output data or heat input data is to be used to calculate the unit's converted gross electrical output.  The unit's converted gross electrical output shall be calculated pursuant to either subsection (b)(1) or (b)(2) of this Section:

 

1)         Gross electrical output:  The average of the unit's two most recent years of control period gross electrical output, if available.  If a unit commences commercial operation in the 2007 control period and does not have gross electrical output for the 2006 control period, the gross electrical output from the 2007 control period will be used.  If a generator is served by two or more units, the gross electrical output of the generator shall be attributed to each unit in proportion to the unit's share of the total control period heat input of such units for the control period.  The unit's converted gross electrical output shall be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = GO (in MWh) ´ 1.0;

 

B)        If the unit is oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.6;

 

C)        If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.4.

 

2)         Heat input:  The average of the unit's two most recent years of control period heat inputs, e.g., for the 2012 control period, the average of the unit's heat input from the 2006 and 2007 control periods.  The unit's converted gross electrical output shall be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0967;

 

B)        If the unit is oil-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0580; or

 

C)        If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = HI (in mmBtu) ´ 0.0387.

 

c)         For control period 2014 and thereafter, the unit's gross electrical output will be the average of the unit's two most recent control period's gross electrical output, if available.  If a unit commences commercial operation in the most recent control period and does not have gross electrical output from the most recent control period, e.g., if the unit commences commercial operation in the 2009 control period and does not have gross electrical output from the 2008 control period, gross electrical output from the 2009 control period will be used.  If a generator is served by two or more units, the gross electrical output of the generator will be attributed to each unit in proportion to the unit's share of the total control period heat input of these units for the control period. The unit's converted gross electrical output will be calculated as follows:

 

1)         If the unit is coal-fired:

CGO (in MWh) = GO (in MWh) ´ 1.0;

 

2)         If the unit is oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.6; or

 

3)         If the unit is neither coal-fired nor oil-fired:

CGO (in MWh) = GO (in MWh) ´ 0.4.

 

d)         For a unit that is a combustion turbine or boiler and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the Agency will add the converted gross electrical output calculated for electricity pursuant to subsection (a), (b), or (c) of this Section to the converted useful thermal energy (CUTE) to determine the total converted gross electrical output for the unit (TCGO).  The Agency will determine the converted useful thermal energy by using the average of the unit's control period useful thermal energy for the prior two control periods, if available.  In the first control period for which the unit is considered to be an existing unit rather than a new unit, the unit's control period useful thermal output for the prior year will be used.  The converted useful thermal energy will be determined using the following equations:

 

1)         If the unit is coal-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.2930;

 

2)         If the unit is oil-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.1758; or

 

3)         If the unit is neither coal-fired nor oil-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.1172.

 

e)         The CAIR NO_x Ozone Season unit's converted gross electrical output and converted useful thermal energy in subsections (a)(1), (b)(1), (c), and (d) of this Section for each control period will be based on the best available data reported or available to the Agency for the CAIR NO_x Ozone Season unit pursuant to the provisions of Section 225.550.

 

f)         The CAIR NO_x Ozone Season unit's heat input in subsections (a)(2) and (b)(2) of this Section for each control period will be determined in accordance with 40 CFR 75, as incorporated by reference in Section 225.140.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.540  Ozone Season Allocations

 

a)         For the 2009 control period, and each control period thereafter, the Agency will allocate, to all CAIR NO_x Ozone Season units in Illinois for which the Agency has calculated the converted gross electrical output pursuant to Section 225.535(a), (b), or (c), or total converted gross electrical output pursuant to Section 225.535(d), a total amount of CAIR NO_x Ozone Season allowances equal to tons of NO_x emissions in the CAIR NO_x Ozone Season Trading budget available for allocation as determined in Section 225.525(d) and, as adjusted to add allowances not allocated pursuant to subsection (b) of this Section in the previous year's allocation.

 

b)         The Agency will allocate CAIR NO_x Ozone Season allowances to each CAIR NO_x Ozone Season unit on a pro-rata basis using the unit's converted gross electrical output pursuant to Section 225.535(a), (b), or (c), or total converted gross electrical output calculated pursuant to Section 225.535(d), as applicable, to the extent whole allowances may be allocated.  The Agency will retain any additional allowances beyond this allocation of whole allowances for allocation pursuant to subsection (a) of this Section in the next control period.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.545  New Unit Set-Aside (NUSA)

 

For the 2009 control period and each control period thereafter, the Agency will allocate CAIR NO_x Ozone Season allowances from the NUSA to CAIR NO_x Ozone Season units that commenced commercial operation on or after May 1, 2006, and do not yet have an allocation for the particular control period or any preceding control period pursuant to Section 225.540, in accordance with the following procedures:

 

a)         Beginning with the 2009 control period and each control period thereafter, the Agency will establish a separate NUSA for each control period.  Each NUSA will be allocated CAIR NO_x Ozone Season allowances equal to five percent of the amount of tons of NO_x emissions in the base CAIR NO_x Ozone Season Trading budget in Section 225.525.

 

b)         The CAIR designated representative of a new CAIR NO_x Ozone Season unit may submit to the Agency a request, in a format specified by the Agency, to be allocated CAIR NO_x Ozone Season allowances from the NUSA, starting with the first control period after the control period in which the new unit commences commercial operation and until the fifth control period after the control period in which the unit commenced commercial operation.  The NUSA allowance allocation request may only be submitted after a new unit has operated during one control period, and no later than March 1 of the control period for which allowances from the NUSA are being requested.

 

c)         In a NUSA allowance allocation request pursuant to subsection (b) of this Section, the CAIR designated representative must provide in its request   information for gross electrical output and useful thermal energy, if any, for the new CAIR NO_x Ozone Season unit for that control period. 

 

d)         The Agency will allocate allowances from the NUSA to a new CAIR NO_x Ozone Season unit using the following procedures:

 

1)         For each new CAIR NO_x Ozone Season unit, the unit's gross electrical output for the most recent control period will be used to calculate the unit's gross electrical output.  If a generator is served by two or more units, the gross electrical output of the generator will be attributed to each unit in proportion to the unit's share of the total control period heat input of these units for the control period. The new unit's converted gross electrical output will be calculated as follows:

 

A)        If the unit is coal-fired:

CGO (in MWh) = GO (in MWh) ´ 1.0;

 

B)        If the unit is oil-fired: 

CGO (in MWh) = GO (in MWh) ´ 0.6; or

 

C)        If the unit is neither coal-fired nor oil-fired: 

CGO (in MWh) = GO (in MWh) ´ 0.4.

 

2)         If the unit is a combustion turbine or boiler and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the Agency will add the converted gross electrical output calculated for electricity pursuant to subsection (d)(1) of this Section to the converted useful thermal energy to determine the total converted gross electrical output for the unit.  The Agency will determine the converted useful thermal energy using the unit's useful thermal energy for the most recent control period.  The converted useful thermal energy will be determined using the following equations:

 

A)        If the unit is coal-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.2930;

 

B)        If the unit is oil-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.1758; or

 

C)        If the unit is neither coal-fired nor oil-fired:

CUTE (in MWh) = UTE (in mmBtu) ´ 0.1172.

 

3)         The gross electrical output and useful thermal energy in subsections (d)(1) and (d)(2) of this Section for each control period will be based on the best available data reported or available to the Agency for the CAIR NO_x Ozone Season unit pursuant to the provisions of Section 225.550 .

 

4)         The Agency will determine a unit's unprorated allocation (UA_y) using the unit's converted gross electrical output plus the unit's converted useful thermal energy, if any, calculated in subsections (d)(1) and (d)(2) of this Section, converted to approximate NO_x tons (the unit's unprorated allocation), as follows:

 

UAy	=	NCGOy ´ (1.01 lbs/MWh)
		2000 lbs/ton

 

Where:

 

UAy	=	unprorated allocation to a new CAIR NOx Ozone Season unit.
NCGOy	=	converted gross electrical output or total converted gross electrical output, as applicable, for a new CAIR NOx Ozone Season unit.

 

5)         The Agency will allocate CAIR NO_x Ozone Season allowances from the NUSA to new CAIR NO_x Ozone Season units as follows:

 

A)        If the NUSA for the control period for which CAIR NO_x Ozone Season allowances are requested has a number of allowances greater than or equal to the total unprorated allocations for all new units requesting allowances, the Agency will allocate the number of allowances using the unprorated allocation determined for that unit pursuant to subsection (d)(4) of this Section, to the extent that whole allowances may be allocated.  For any additional allowances beyond this allocation of whole allowances, the Agency will retain the additional allowances in the NUSA for allocation pursuant to this Section in later control periods.

 

B)        If the NUSA for the control period for which the allowances are requested has a number of CAIR NO_x Ozone Season allowances less than the total unprorated allocation to all new CAIR NO_x Ozone Season units requesting allocations, the Agency will allocate the available allowances for new CAIR NO_x Ozone Season units on a pro-rata basis, using the unprorated allocation determined for that unit pursuant to subsection (d)(4) of this Section, to the extent that whole allowances may be allocated.  For any additional allowances beyond this allocation of whole allowances, the Agency will retain the additional allowances in the NUSA for allocation pursuant to this Section in later control periods.

 

e)         The Agency will review each NUSA allowance allocation request pursuant to subsection (b) of this Section.  The Agency will accept a NUSA allowance allocation request only if the request meets, or is adjusted by the Agency as necessary to meet, the requirements of this Section.

 

f)         By June 1 of the applicable control period, the Agency will notify each CAIR designated representative that submitted a NUSA allowance request of the amount of CAIR NO_x Ozone Season allowances from the NUSA, if any, allocated for the control period to the new unit covered by the request.

 

g)         The Agency will allocate CAIR NO_x Ozone Season allowances to new units from the NUSA no later than July 31 of the applicable control period.

 

h)         After a new CAIR NO_x Ozone Season unit has operated in one control period, it becomes an existing unit for the purposes of calculating future allocations in Section 225.540 only, and the Agency will allocate CAIR NO_x Ozone Season allowances for that unit, for the control period commencing five control periods after the control period in which the unit commenced commercial operation, pursuant to Section 225.540.  The new CAIR NO_x Ozone Season unit will continue to receive CAIR NO_x Ozone Season allowances from the NUSA according to this Section until the unit is eligible to use the CAIR NO_x Ozone Season allowances allocated to the unit pursuant to Section 225.540.

 

i)          If, after the completion of the procedures in subsection (c) of this Section for a control period, any unallocated CAIR NO_x Ozone Season allowances remain in the NUSA for the control period, the Agency will, at a minimum, accrue those CAIR NO_x Ozone Season allowances for future control period allocations to new CAIR NO_x Ozone Season units.  The Agency may from time to time elect to retire CAIR NO_x Ozone Season allowances in the NUSA that are in excess of 7,245 for the purposes of continued progress toward attainment and maintenance of National Ambient Air Quality Standards pursuant to the CAA.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.550   Monitoring, Recordkeeping and Reporting Requirements for Gross Electrical Output and Useful Thermal Energy

 

a)         By January 1, 2008, or by the date of commencing commercial operation, whichever is later, the owner or operator of the CAIR NO_x Ozone Season unit must operate a system for accurately measuring gross electrical output that is consistent with the requirements of either 40 CFR 60 or 75; must measure gross electrical output in MWh using such a system; and must record the output of the measurement system at all times.  If a generator is served by two or more units, the information to determine each unit's heat input for that control period must also be recorded, so as to allow each unit's share of the gross electrical output to be determined.  If heat input data is used, the owner or operator must comply with the applicable provisions of 40 CFR 75, as incorporated by reference in Section 225.140.

 

b)         For a CAIR NO_x Ozone Season unit that is a cogeneration unit, by January 1, 2008, or by the date the CAIR NO_x Ozone Season unit commences to produce useful thermal energy, whichever is later, the owner or operator of the unit with cogeneration capabilities must install, calibrate, maintain, and operate meters for steam flow in lbs/hr, temperature in degrees Fahrenheit, and pressure in PSI, to measure and record the useful thermal energy that is produced, in mmBtu/hr, on a continuous basis.  Owners and operators of a CAIR NO_x Ozone Season unit that produces useful thermal energy but uses an energy transfer medium other than steam, e.g., hot water or glycol, must install, calibrate, maintain, and operate the necessary meters to measure and record the necessary data to express the useful thermal energy produced, in mmBtu/hr, on a continuous basis.  If the CAIR NO_x Ozone Season unit ceases to produce useful thermal energy, the owner or operator may cease operation of these meters, provided that operation of such meters must be resumed if the CAIR NO_x Ozone Season unit resumes production of useful thermal energy.

 

c)         The owner or operator of a CAIR NO_x Ozone Season unit must either report gross electrical output data to the Agency or comply with the applicable provisions for providing heat input data to USEPA as follows:

 

1)         By September 15, 2007, the gross electrical output for control periods 2001, 2002, 2003, 2004 and 2005, if available, and the unit's useful thermal energy data, if applicable.  If a generator is served by two or more units, the documentation needed to determine each unit's share of the heat input of such units for that control period must also be submitted.  If heat input data is used, the owner or operator must comply with the applicable provisions of 40 CFR 75, as incorporated by reference in Section 225.140.

 

2)         By June 1, 2008, the gross electrical output for control periods 2006 and 2007, if available, and the unit's useful thermal energy data, if applicable.  If a generator is served by two or more units, the documentation needed to determine each unit's share of the heat input of such units for that control period must also be submitted.  If heat input data is used, the owner or operator must comply with the applicable provisions of 40 CFR 75, as incorporated by reference in Section 225.140.

 

d)         Beginning with 2008, the CAIR designated representative of the CAIR NO_x Ozone Season unit must submit to the Agency quarterly, by no later than April 30, July 31, October 31, and January 31 of each year, information for the CAIR NO_x Ozone Season unit's gross electrical output, on a monthly basis for the prior quarter, and, if applicable, the unit's useful thermal energy for each month.

 

e)         The owner or operator of a CAIR NO_x Ozone Season unit must maintain on-site the monitoring plan detailing the monitoring system, maintenance of the monitoring system, including quality assurance activities pursuant to the requirements of 40 CFR 60 or 75, as applicable, including the appropriate provisions for the measurement of gross electrical output for the CAIR NO_x Ozone Season Trading Program and, if applicable, for new units.  The monitoring plan must include, but is not limited to:

 

1)         A description of the system to be used for the measurement of gross electrical output pursuant to Section 225.550(a), including a list of any data logging devices, solid-state kW meters, rotating kW meters, electromechanical kW meters, current transformers, transducers, potential transformers, pressure taps, flow venturi, orifice plates, flow nozzles, vortex meters, turbine meters, pressure transmitters, differential pressure transmitters, temperature transmitters, thermocouples, resistance temperature detectors, and any equipment or methods used to accurately measure gross electrical output.

 

2)         A certification statement by the CAIR designated representative that all components of the gross electrical output system have been tested to be accurate within three percent and that the gross electrical output system is accurate to within ten percent.

 

f)         The owner or operator of a CAIR NO_x Ozone Season unit must retain records for at least five years from the date the record is created or the data is collected under subsections (a) and (b) of this Section, and the reports are submitted to the Agency and USEPA in accordance with subsections (c) and (d) of this Section.  The owner or operator of a CAIR NO_x Ozone Season unit must retain the monitoring plan required in subsection (e) of this Section for at least five years from the date that it is replaced by a new or revised monitoring plan.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.555  Clean Air Set-Aside (CASA)

 

a)         A project sponsor may apply for allowances from the CASA for sponsoring an energy efficiency and conservation, renewable energy, or clean technology project as set forth in Section 225.560 by submitting the application required by Section 225.570.

 

b)         Notwithstanding subsection (a) of this Section, a project sponsor with a CAIR NO_x Ozone Season source that is out of compliance with this Subpart for a given control period may not apply for allowances from the CASA for that control period.  If a source receives CAIR NO_x Ozone Season allowances from the CASA and then is subsequently found to have been out of compliance with this Subpart for the applicable control period or periods, the project sponsor must restore the CAIR NO_x Ozone Season allowances that it received pursuant to its CASA request or an equivalent number of CAIR NO_x Ozone Season allowances to the CASA within six months after receipt of an Agency notice that NO_x Ozone Season allowances must be restored.  These allowances will be assigned to the fund from which they were distributed.

 

c)         CAIR NO_x Ozone Season allowances from the CASA will be allocated in accordance with the procedures in Section 225.575.

 

d)         The project sponsor may submit an application that aggregates two or more projects under a CASA project category that would individually result in less than one allowance, but that equal at a minimum one whole allowance when aggregated. 

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.560  Energy Efficiency and Conservation, Renewable Energy, and Clean

Technology Projects

 

a)         Energy efficiency and conservation projects means any of the following projects implemented and located in Illinois:

 

1)         Demand side management projects that reduce the overall power demand by using less energy include:

 

A)        Smart building management software that more efficiently regulates power flows.

 

B)        The use of or replacement to high efficiency motors, pumps, compressors, or steam systems.

 

C)        Lighting retrofits.

 

2)         Energy efficient new building construction projects include:

 

A)        ENERGY STAR-qualified new home projects.

 

B)        Measures to reduce or conserve energy consumption beyond the requirements of the Illinois Energy Conservation Code for Commercial Buildings [20 ILCS 687/6-3].

 

C)        New residential construction projects that qualify for Energy Efficient Tax Incentives pursuant to the Energy Policy Act of 2005 (42 USC 15801 (2005)).

 

3)         Supply-side energy efficiency projects include projects implemented to improve the efficiency in electricity generation by coal-fired power plants and the efficiency of electrical transmission and distribution systems.

 

4)         Highly efficient power generation projects, such as, but not limited to, combined cycle projects, combined heat and power, and microturbines.  To be considered a highly efficient power generation project pursuant to this subsection (a)(4), a project must meet the following applicable thresholds and criteria: 

 

A)        For combined heat and power projects generating both electricity and useful thermal energy for space, water, or industrial process heat, a rated-energy efficiency of at least 60 percent: the project shall not be a CAIR NO_x Ozone Season unit.

 

B)        For combined cycle projects rated at greater than 0.50 MW, a rated-energy efficiency of at least 50 percent.

 

C)        For microturbine projects rated at or below 0.50 MW and all other projects a rated-energy efficiency of at least 40 percent.

 

b)         Renewable energy project means any of the following projects implemented and located in Illinois:

 

1)         Zero-emission electric generating projects, including wind, solar (thermal or photovoltaic), and hydropower projects.  Eligible hydropower plants are restricted to new generators that are not replacements of existing generators, that commenced operation on or after January 1, 2006, and that do not involve the significant expansion of an existing dam or the construction of a new dam.

 

2)         Renewable energy units are those units that generate electricity using more than 50 percent of the heat input, on an annual basis, from dedicated crops grown for energy production or the capture systems for methane gas from landfills, water treatment plants or sewage treatment plants, and organic waste biomass, and other similar sources of non-fossil fuel energy.  Renewable energy projects do not include energy from incineration by burning or heating of waste wood, tires, garbage, general household waste, institutional lunchroom waste, office waste, landscape waste, or construction or demolition debris.

 

c)         Clean technology projects for reducing emissions from producing electricity and useful thermal energy means any of the following projects implemented and located in Illinois:

 

1)         Air pollution control equipment upgrades for control of NO_x emissions at existing coal-fired EGUs, as follows:  installation of a selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) system, or other emission control technologies.  For this purpose, a unit will be considered "existing" after it has been in commercial operation for at least eight years.  Air pollution control upgrades do not include the addition of low NO_x burners, overfired air techniques, gas reburning techniques, flue gas conditioning techniques for the control of NO_x emissions, projects involving upgrades or replacement of electrostatic precipitators, or addition of an activated carbon injection, or other sorbent injection for control of mercury.

 

2)         Clean coal technologies projects include:

 

A)        Integrated gasification combined cycle (IGCC) plants.

 

B)        Fluidized bed coal combustion that commenced operation prior to December 31, 2006.

 

d)         In addition to those projects excluded in subsections (a) through (c) of this Section, the following projects are also not energy efficiency and conservation, renewable energy, or clean technology projects:

 

1)         Nuclear power projects.

 

2)         Projects required to meet emission standards or technology requirements under State or federal law or regulation, except that allowances may be allocated for projects undertaken pursuant to Section 225.233 or Subpart F.

 

3)         Projects used to meet the requirements of a court order or consent decree, except that allowances may be allocated for:

 

A)        Emission rates or limits achieved that are lower than what is required to meet the emission rates or limits for SO₂ or NO_x, or for installing a baghouse as provided for in a court order or consent decree entered into before May 30, 2006.

 

B)        Projects used to meet the requirements of a court order or consent decree entered into on or after May 30, 2006, if the court order or consent decree does not specifically preclude such allocations.

 

4)         A Supplemental Environmental Project (SEP).

 

e)         Applications for projects implemented and located in Illinois that are not specifically listed in subsections (a) through (c) of this Section, and that are not specifically excluded by definition in subsections (a) through (c) of this Section or by specific exclusion in subsection (d) of this Section, may be submitted to the Agency.  The application must designate which category or categories from those listed in subsections (a)(1) through (c)(2)(B) of this Section best fit the proposed project and the applicable formula pursuant to Section 225.565(b) to calculate the number of allowances that it is requesting.  The Agency will determine whether the application is approvable based on a sufficient demonstration by the project sponsor that the project is a new type of energy efficiency, renewable energy, or clean technology project, similar in its effects as the projects specifically listed in subsections (a) through (c) of this Section.

 

f)         Early adopter projects include projects that meet the criteria for any energy efficiency and conservation, renewable energy, or clean technology projects listed in subsections (a) , (b), (c), and (e) of this Section and commence construction between July 1, 2006 and December 31, 2012.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)

 

Section 225.565  Clean Air Set-Aside (CASA) Allowances

 

a)         The CAIR NO_x Ozone Season allowances for the CASA for each control period will be assigned to the following categories of projects:

 

		Phase I	Phase II
		(2009-2014)	(2015 and thereafter)
1)	Energy Efficiency and Conservation/Renewable Energy	3684	3479
2)	Air Pollution Control Equipment Upgrades	1535	1448
3)	Clean Coal Technology Projects	1842	1738
4)	Early Adopters	614	580

 

b)         The following formulas must be used to determine the number of CASA allowances that may be allocated to a project per control period:

 

1)         For an energy efficiency and conservation project pursuant to Section 225.560(a)(1) through (a)(4)(A), the number of allowances must be calculated using the number of megawatt hours of electricity that was not consumed during a control period and the following formula:

 

A

=

(MWhc) ´ (1.5 lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhc	=	The number of megawatt hours of electricity conserved or generated during a control period by a project.

 

2)         For a zero emission electric generating project pursuant to Section 225.560(b)(1), the number of allowances must be calculated using the number of megawatt hours of electricity generated during a control period and the following formula:

 

A

=

(MWhg) ´ (2.0 lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project
MWhg	=	The number of megawatt hours of electricity generated during a control period by a project.

 

3)         For a renewable energy emission unit pursuant to Section 225.560(b)(2), the number of allowances must be calculated using the number of megawatt hours of electricity generated during a control period and the following formula:

 

A

=

(MWhg) ´ (0.5 lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhg	=	The number of MW hours of electricity generated during a control period by a project.

 

4)         For an air pollution control equipment upgrade project pursuant to Section 225.560(c)(1), the number of allowances must be calculated using the emission rate before and after replacement or improvement, and the following formula:

 

A

=

(MWhg) ´ 0.10 ´ (ERB lb/MWh - ERA lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhg	=	The number of MWhs of electricity generated during a control period by a project.
ERB	=	Average NOx emission rate based on CEMS data from the most recent two control periods prior to the replacement or improvement of the control equipment in lb/MWh, unless subject to a consent decree or court order.  For units subject to a consent decree or court order entered into before May 30, 2006, ERB is limited to emission rates or limits that are lower than the emission rate or limit required in the consent decree
		or court order.  On or after May 30, 2006, ERB is limited to emission rates or limits specified in the consent decree or court order.  If such limit is not expressed in lb/MWh, the limit shall be converted into lb/MWh using a heat rate of 10 mmBtu/1 MW.
ERA	=	Average NOx emission rate for the applicable control period data based on CEMS data in lb/MWh.

 

5)         For highly efficient power generation and clean coal technology projects:

 

A)        For projects other than fluidized coal combustion pursuant to Section 225.560(a)(4)(B), (a)(4)(C), and (c)(2), the number of allowances must be calculated using the number of MWh of electricity the project generates during a control period and the following formula:

 

A

=

(MWhg) ´ (1.0 lb/MWh - ER lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhg	=	The number of megawatt hours of electricity generated during a control period by a project.
ER	=	Annual average NOx emission rate based on CEMS data in 1b/MWh.

B)        For fluidized bed coal combustion projects pursuant to Section 225.560(c)(2), the number of allowances shall be calculated using the number of gross MWh of electricity the project generates during a control period and the following formula:

 

A

=

(MWhg) ´ (1.4 lb/MWh - ER lb/MWh) / 2000 lb

 

Where:

 

A	=	The number of allowances for a particular project.
MWhg	=	The number of gross MWh of electricity generated during a control period by a project.
ER	=	Annual NOx emission rate for the control period based on CEMS data in lb/MWh.

 

6)         For a CASA project that commences construction before December 31, 2012, in addition to the allowances allocated pursuant to subsections (b)(1) through (b)(5) of this Section, a project sponsor may also request additional allowances under the early adopter project category pursuant to Section 225.560(e) based on the following formula:

 

A

=

1.0 + 0.10 ´ Σ Ai

 

Where:

 

A	=	The number of allowances for a particular project as determined in subsections (b)(1) through (b)(5) of this Section.
Ai	=	The number of allowances as determined in subsection (b)(1), (b)(2), (b)(3), (b)(4) or (b)(5) of this Section for a given project.

 

(Source:  Added at 31 Ill. Reg. 12864, effective August 31, 2007)