BEFORE THE ILLINOIS POLLUTION CONTROL BOARD

STATE OF ILLINOIS

)

)

SS

COUNTY OF SANGAMON

)

)

CERTIFICATE OF SERVICE

I, the undersigned, an attorney, state that I have served electronically the attached

MOTION TO PROCEED WITH AMENDED PROPOSAL AND WITHDRAW TESTIMONY

of the Illinois Environmental Protection Agency upon the following persons:

John Therriault, Assistant Clerk

Illinois Pollution Control Board

State of Illinois Center

100 West Randolph, Suite 11-500

Chicago, Illinois 60601

SEE ATTACHED SERVICE LIST

and by electronic service from Springfield, Illinois on December 20, 2007.

ILLINOIS ENVIRONMENTAL

PROTECTION AGENCY

___/s/__________________

Rachel L. Doctors

Assistant Counsel

Air Regulatory Unit

Division of Legal Counsel

Dated: December 20, 2007

1021 North Grand Avenue East

Springfield, Illinois 62794-9276

(217) 782-5544

217.782.9143 (TDD)

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

R07-19 Service List

Timothy Fox, Hearing Officer

Illinois Pollution Control Board

State of Illinois Center

100 W. Randolph, Suite 11-500

Chicago, IL 60601

Katherine D. Hodge

N. LaDonna Driver

Gale W. Newton

Hodge Dwyer Zeman

3150 Roland Ave.

PO Box 5776

Springfield, IL 62705-5776

N. LaDonna Driver

Illinois Environmental Regulatory Group

3150 Roland Ave.

Springfield, IL 62705-5776

Kathleen C. Bassi

Renee Cipriano

Joshua R. More

Stephen J. Bonebrake

Schiff Hardin, LLP

6600 Sears Tower

233 S. Wacker Drive

Chicago, IL 60606-6473

Electronic Filing - Received, Clerk's Office, December 20, 2007

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SUBPART Q: STATIONARY RECIPROC

R07-19

ATING INTERNAL COMBUSTION ENGINES

AND TURBINES

Section 217.386

Applicability

a)

The provisions of this Subpart shall apply to all:

1)

A stationary Stationary reciprocating internal combustion engines engine

listed in Appendix G of this Part is subject to the requirements of this

Subpart Q.

2)

Stationary reciprocating internal combustion engines and turbines located

at a source that emits or has the potential it emit NO

x

in an amount equal

to or greater than 100 tons per year and is in either the area composed of

the Chicago area counties of Cook, DuPage, Kane, Lake, McHenry, and

Will, the Townships of Aux Sable and Goose Lake in Grundy County, and

the Township of Oswego in Kendall County, or in the area composed of

the Metro-East counties of Jersey, Madison, Monroe, and St. Clair, and

the Township of Baldwin in Randolph County, where:

A)

The engine at nameplate capacity is rated at equal to or greater

than 500 bhp output; or

B)

The turbine is rated at equal to or greater than 3.5 MW (4,694 bhp)

output at 14.7 psia, 59ºF and 60 percent relative humidity.

b)

Notwithstanding subsection (a) of this Section, an affected unit is not subject to

the requirements of this Subpart Q if the engine or turbine is or has been:

1)

Used as an emergency or standby unit as defined by 35 Ill. Adm. Code

211.1920;

2)

Used for research or for the purposes of performance verification or

testing;

3)

Used to control emissions from landfills, where at least 50 percent of the

heat input is gas collected from a landfill;

4)

Used for agricultural purposes including the raising of crops or livestock

that are produced on site, but not for associated businesses like packing

operations, sale of equipment or repair; or

5)

An engine with nameplate capacity rated at less than 1,500 bhp (1,118kW)

output, mounted on a chassis or skids, designed to be moveable, and

moved to a different source at least once every 12 months;

Electronic Filing - Received, Clerk's Office, December 20, 2007

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2

c)

If an exempt unit ceases to fulfill the criteria specified in subsection (b) of this

Section, the owner or operator must notify the Agency in writing within 30 days

after becoming aware that the exemption no longer applies and comply with the

control requirements of this Subpart Q.

d)

The requirements of this Subpart Q will continue to apply to any engine or turbine

that has ever been subject to the control requirements of Section 217.388, even if

the affected unit or source ceases to fulfill the rating requirements of subsection

(a) of this Section or becomes eligible for an exemption pursuant to subsection (b)

of this Section.

(Source: Amended at

Ill. Reg.

, effective

)

Section 217.388

Control and Maintenance Requirements

On and after the applicable compliance date in Section 217.392, an owner or operator of an

affected unit must inspect and maintain affected units as required by subsection (c) of this

Section and comply with either the applicable emissions concentration as set forth in subsection

(a) of this Section, or the requirements for an emissions averaging plan as specified in subsection

(b) of this Section, or the requirements for operation as a low usage unit as specified in

subsection (d) of this Section.

a)

The owner or operator must limits the discharge from an affected unit into the

atmosphere of any gases that contain NO

x

to no more than:

1)

150 ppmv (corrected to 15 percent O

2

on a dry basis) for spark-ignited

rich-burn engines;

2)

210 ppmv (corrected to 15 percent O

2

on a dry basis) for spark-ignited

lean-burn engines, except for existing spark-ignited Worthington engines

that are not listed in Appendix G;

3)

365 ppmv (corrected to 15 percent O

2

on a dry basis) for existing spark-

ignited Worthington engines that are not listed in Appendix G;

4)

660 ppmv (corrected to 15 percent O

2

on a dry basis) for diesel engines;

5)

42 ppmv (corrected to 15 percent O

2

on a dry basis) for gaseous fuel-fired

turbines; and

6)

96 ppmv (corrected to 15 percent O

2

on a dry basis) for liquid fuel-fired

turbines.

b)

The owner or operator must

compliesy with an emissions averaging plan as

Electronic Filing - Received, Clerk's Office, December 20, 2007

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3

provided for in either subsection (b)(1) or (b)(2) of this Section:

1)

For any affected unit identified by Section 217.386: The the requirements

of the applicable emissions averaging plan as set forth in Section 217.390;

or

2)

For units identified in Section 217.386(a)(2): The requirements of an

emissions averaging plan adopted pursuant to any other Subpart of this

Part. For such affected engines and turbines the applicable requirements

of this Subpart apply, including but not limited to, calculation of NO

x

allowable and actual emissions rates, compliance dates, monitoring,

testing, reporting, and recordkeeping.

c)

The owner or operator operates the affected unit as a low usage unit pursuant to

subsection (c)(1) or (c)(2) of this Section. Low usage units are not subject to the

requirements of this Subpart Q except for the requirements to inspect and

maintain the unit pursuant to subsection (d) of this Section, and retain records

pursuant to Sections 217.396(b) and (d). Either the limitation in subsection (c)(1)

or (c)(2) may be utilized at a source, but not both:

1)

The potential to emit (PTE) is no more than 100 TPY NO

x

aggregated

from all engines and turbines located at the source that are not otherwise

exempt pursuant to Section 217.386(b), and not complying with the

requirements of subsection (a) or (b) of this Section, and the NO

x

PTE

limit is contained in a federally enforceable permit; or

2)

The aggregate bhp-hrs/MW-hrs from all affected units located at the

source that are not exempt pursuant to Section 217.386(b), and not

complying with the requirements of subsection (a) or (b) of this Section,

are less than or equal to the bhp-hrs and MW-hrs operation limit listed in

subsection (c)(2)(A) and (c)(2)(B) of this Section. For units that drive a

natural gas compressor station but that are not located at a natural gas

compressor station or storage facility, the operation limits of subsection

(c)(2)(A) and (c)(2)(B) of this Section must be contained in a federally

enforceable permit. The operation limits are:

A)

8 mm bhp-hrs or less on an annual basis for engines; and

B)

20,000 MW-hrs or less on an annual basis for turbines.

d)

The owner or operator must inspects and performs periodic maintenance on the

affected unit, in accordance with a Maintenance Plan that documents:

1)

For a unit not located at natural gas transmission compressor station or

storage facility either:

Electronic Filing - Received, Clerk's Office, December 20, 2007

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12/20/2007 4:17 PM

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4

A)

The manufacturer’s recommended inspection and maintenance of

the applicable air pollution control equipment, monitoring device,

and affected unit; or

B)

If the original equipment manual is not available or substantial

modifications have been made that require an alternative procedure

for the applicable air pollution control device, monitoring device,

or affected unit, the owner or operator must establish a plan for

inspection and maintenance in accordance with what is customary

for the type of air pollution control equipment, monitoring device,

and affected unit.

2)

For a unit located at a natural gas compressor station or storage facility,

the operator’s maintenance procedures for the applicable air pollution

control device, monitoring device, and affected unit.

(Source: Amended at

Ill. Reg.

, effective

)

Section 217.390

Emissions Averaging Plans

a)

An owner or operator of certain affected units may comply through an emissions

averaging plan.

1)

The unit or units that commenced operation before January 1, 2002, may

be included in only onean emissions averaging plan, as follows:

A)

The theunits:

i)

Listed in Appendix G and located at a single source or at

multiple sources in Illinois, so long as the units are owned

by the same company or parent company where the parent

company has working control through stock ownership of

its subsidiary corporations. A unit may be listed in only

one emissions averaging plan; or

ii)

Identified in Section 217.386(b)(2), and located at a single

source or at multiple sources in either the Chicago area

counties or Metro-East area counties, so long as the units

are owned by the same company or parent company where

the parent company has working control through stock

ownership of its subsidiary corporations.

B)

Units that have a compliance date later than the control period for

which the averaging plan is being used for compliance; and

Electronic Filing - Received, Clerk's Office, December 20, 2007

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12/20/2007 4:17 PM

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5

C)

Units which the owner or operator may claim as exempt pursuant

to Section 217.386(b) but does not claim as exempt. For as long as

such unit is included in an emissions averaging plan, it will be

treated as an affected unit and subject to the applicable emission

concentration, limits, testing, monitoring, recordkeeping and

reporting requirements.

2)

The following types of units may not be included in an emissions

averaging plan:

A)

Units units that commence operation after January 1, 2002, unless

the unit replaces an engine or turbine that commenced operation on

or before January 1, 2002, or it replaces an engine or turbine that

replaced a unit that commenced operation on or before January 1,

2002. The new unit must be used for the same purpose as the

replacement unit. The owner or operator of a unit that is shutdown

and replaced must comply with the provisions of Section

217.396(c)(3) before the replacement unit may be included in an

emissions averaging plan.

B)

Units which the owner or operator is claiming are exempt pursuant

to Section 217.386(b) or as low usage units pursuant to Section

217.388(c).

b)

An owner or operator must submit an emissions averaging plan to the Agency by

the applicable compliance date set forth in Section 217.392. The plan must

include, but is not limited to:

1)

The list of affected units included in the plan by unit identification number

and permit number.

2)

A sample calculation demonstrating compliance using the methodology

provided in subsection (f) of this Section for both the ozone season and

calendar year.

c)

An owner or operator may amend an emissions averaging plan only once per

calendar year. An amended plan must be submitted to the Agency by May 1 of

the applicable calendar year. If an amended plan is not received by the Agency

by May 1 of the applicable calendar year, the previous year’s plan will be the

applicable emissions averaging plan.

d)

Notwithstanding subsection (c) of this Section, an owner or operator, and the

buyer, if applicable:

, must

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

1)

Must submit an updated emissions averaging plan or plans to the Agency

within 60 days, if a unit that is listed in an emissions averaging plan is

sold or taken out of service.

2)

May amend its emissions averaging plan to include another unit within 30

days of discovering that the unit no longer qualifies as an exempt unit

pursuant to Section 217.386(b) or as a low usage unit pursuant to Section

217.388(c).

e)

An owner or operator must:

1)

Demonstrate compliance for both the ozone season (May 1 through

September 30) and the calendar year (January 1 through December 31) by

using the methodology and the units listed in the most recent emissions

averaging plan submitted to the Agency pursuant to subsection (b), (c), or

(d) of this Section; the higher of the monitoring or test data determined

pursuant to Section 217.394; and the actual hours of operation for the

applicable control period;

2)

Notify the Agency by October 31 following the ozone season, if

compliance cannot be demonstrated for that ozone season; and

3)

Submit to the Agency by January 31 following each calendar year, a

compliance report containing the information required by Section

217.396(c)(4).

f)

The total mass of actual NO

x

emissions from the units listed in the emissions

averaging plan must be equal to or less than the total mass of allowable NO

x

emissions for those units for both the ozone season and calendar year. The

following equation must be used to determine compliance:

N

act

≤

N

all

Where:

N

act

=

∑

=

n

i1

EM

act(i)

N

all

=

∑

=

n

i1

EM

all(i)

N

act

=

Total sum of the actual NO

x

mass emissions from

units included in the averaging plan for each fuel used (lbs

per ozone season and calendar year).

N

all

=

Total sum of the allowable NO

x

mass emissions from units

included in the averaging plan for each fuel used (lbs per

ozone season and calendar year).

12/20/2007 4:17 PM

Page

6

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

EM

all(i)

=

Total mass of allowable NO

x

emissions in lbs for a unit as

determined in subsection (g)(2) or (h)(2) of this Section.

EM

act(i)

=

Total mass of actual NO

x

emissions in lbs for a unit

as determined in subsection (g)(1) or (h)(1) of this Section.

i

=

Subscript denoting an individual unit and fuel used.

n

=

Number of different units in the averaging plan.

g)

For each unit in the averaging plan, and each fuel used by a unit, determine actual

and allowable NO

x

emissions using the following equations, except as provided

for in subsection (h) of this Section:

1)

Actual emissions must be determined as follows:

EM

act(i)

=

E

act(i)

x H

i

m

20.9 %O

C

xF x

20.9

E

m

j 1

2d(j)

d(act( j))

d

act(i)

∑

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

−

=

=

2)

Allowable emissions must be determined as follows:

EM

all(i)

=

E

all(i)

x H

i

m

20.9 %O

C

xF x

20.9

E

m

j 1

2d(j)

d(all)

d

all(i)

∑

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

−

=

=

Where:

EM

act(i)

=

Total mass of actual NO

x

emissions in lbs for a unit, except

as provided for in subsections (g)(3) and (g)(5) of this

Section.

EM

all(i)

=

Total mass of allowable NO

x

emissions in lbs for a unit,

except as provided for in subsection (g)(3) of this Section.

E

act

=

Actual NO

x

emission rate (lbs/mmBtu) calculated

according to the above equation.

E

all

=

Allowable NO

x

emission rate (lbs/mmBtu)

calculated according to the above equation.

H

=

Heat input (mmBtu/ozone season or mmBtu/year)

calculated from fuel flow meter and the heating

value of the fuel used.

C

d(act)

=

Actual concentration of NO

x

in lb/dscf (ppmv x

1.194 x 10

-7

) on a dry basis for the fuel used. Actual

concentration is determined on each of the most recent test

12/20/2007 4:17 PM

Page

7

Electronic Filing - Received, Clerk's Office, December 20, 2007

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8

run or monitoring pass performed pursuant to Section

217.394, whichever is higher.

C

d(all)

=

Allowable concentration of NO

x

in lb/dscf (allowable

emission limit in ppmv specified in Section 217.388(a),

except as provided for in subsection (g)(4), (g)(5), or (g)(6)

of this Section, if applicable.,(multiplied by 1.194 x 10

-7

)

on a dry basis for the fuel used.

F

d

=

The ratio of the gas volume of the products of combustion

to the heat content of the fuel (dscf/mmBtu) as given in the

table of F Factors included in 40 CFR 60, Appendix A,

Method 19 or as determined using 40 CFR 60, Appendix

A, Method 19.

%O

2d

=

Concentration of oxygen in effluent gas stream measured

on a dry basis during each of the applicable test or

monitoring runs used for determining emissions, as

represented by a whole number percent, e.g., for 18.7%O

2d

,

18.7 would be used.

i

=

Subscript denoting an individual unit and the fuel used.

j

=

Subscript denoting each test run or monitoring pass for an

affected unit for a given fuel.

m

=

The number of test runs or monitoring passes for an

affected unit using a given fuel.

3)

For a replacement unit that is electric-powered, the allowable NO

x

emissions from the affected unit that was replaced should be used in the

averaging calculations and the actual NO

x

emissions for the electric-

powered replacement unit (EM

(i)act elec

) are zero. Allowable NO

x

emissions for the electric-powered replacement are calculated using the

actual total bhp-hrs generated by the electric-powered replacement unit on

an ozone season and on an annual basis multiplied by the allowable NO

x

emission rate in lb/bhp-hr of the replaced unit. The allowable mass of

NO

x

emissions from an electric-powered replacement unit (EM

(i)all elec

)

must be determined by multiplying the nameplate capacity of the unit by

the hours operated during the ozone season or annually and the allowable

NO

x

emission rate of the replaced unit (E

all rep

) in lb/mmBtu converted to

lb/bhp-hr. For this calculation the following equation should be used:

EM

all elec(i)

= bhp x OP x F x E

all rep(i)

Where:

EM

all elec(i)

=

Mass of allowable NO

x

emissions from the electric-

powered replacement unit in pounds per ozone season or

calendar year.

bhp

=

Nameplate capacity of the electric-powered

Electronic Filing - Received, Clerk's Office, December 20, 2007

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12/20/2007 4:17 PM

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9

replacement unit in brake-horsepower.

OP

=

Operating hours during the ozone season or calendar

year.

F

=

Conversion factor of 0.0077 mmBtu/bhp-hr.

E

all rep(i)

=

Allowable NO

X

emission rate (lbs/mmBtu) of the replaced

unit.

i

=

Subscript denoting an individual electric unit and the fuel

used.

4)

For a replacement unit that is not electric, the allowable NO

x

emissions

rate used in the above equations set forth in subsection (g)(2) of this

Section must be the higher of the actual NO

x

emissions as determined by

testing or monitoring data or the applicable uncontrolled NO

x

emissions

factor from Compilation of Air pollutant emission Factors: AP-42,

Volume I: Stationary Point and Area Sources, as incorporated by reference

in Section 217.104 for the unit that was replaced.

5)

For a unit that is replaced with purchased power, the allowable NO

x

emissions rate used in the above equations set forth in subsection (g)(2) of

this Section must be the emissions concentration as set forth in Section

217.388(a) or subsection (g)(6) of this Section, when applicable, for the

type of unit that was replaced. For owners or operators replacing units

with purchased power, the annual hours of operations that must be used

are the calendar year hours of operation for the unit that was shutdown

averaged over the three-year period prior to the shutdown. The actual

NO

x

emissions for the units replaced by purchased power (EM

(i)act

) are

zero. These units may be included in any emissions averaging plan for no

more than five years beginning with the calendar year that the replaced

unit is shut down.

6)

For units that have a later compliance datenon-Appendix G units used in

an emissions averaging plan, allowable emissions rate used in the above

equations set forth in subsection (g)(2) of this Section must be:

A)

Prior to the applicable compliance date pursuant to Section

217.392, the higher of the actual NO

x

emissions as determined by

testing or monitoring data, or the applicable uncontrolled NO

x

emissions factor from Compilation of Air Pollutant Emission

Factors: AP-42, Volume I: Stationary Point and Areas Sources, as

incorporated by reference in Section 217.104); or

B)

On and after the unit’s applicable compliance date pursuant to

section 217.392, the applicable emissions concentration for that

type of unit pursuant to Section 217.388(a).

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

h)

For units that use CEMS the data must show that the total mass of actual NO

x

emissions determined pursuant to subsection (h)(1) of this Section is less than or

equal to the allowable NO

x

emissions calculated in accordance with the equations

in subsections (f) and (h)(2) of this Section for both the ozone season and

calendar year. The equations in subsection (g) of this Section will not apply.

1)

The total mass of actual NO

x

emissions in lbs for a unit (EM

act

) must be

the sum of the total mass of actual NO

x

emissions from each affected unit

using CEMS data collected in accordance with 40 CFR 60 or 75, or

alternate methodology that has been approved by the Agency or USEPA

and included in a federally enforceable permit.

2)

The allowable NO

x

emissions must be determined as follows:

∑

=

−

=

m

i

EM

all

i

Cd

i

flow

i

x

1

7

(

( )

)

(

*

*1.194 10 )

Where:

EM

all(i)

=

Total mass of allowable NO

x

emissions in lbs for a unit.

fFlow

i

=

Stack flow (dscf/hr) for a given stack.

Cd

i

=

Allowable concentration of NO

x

(ppmv) specified in

Section 217.388(a) of this subpart for a given stack. (1.194

x 10

-7

) converts to lb/dscf).

j

=

subscript denoting each hour operation of a given unit.

m

=

Total number of hours of operation of a unit.

i

=

Subscript denoting an individual unit and the fuel used.

(Source: Amended at

Ill. Reg.

, effective

)

Section 217.392

Compliance

a)

On and after January 1, 2008, an owner or operator of an affected engine listed in

Appendix G may not operate the affected engine unless the requirements of this

Subpart Q are met.

b)

On and after May 1, 2010, an owner or operator of a unit identified by Section

217.386(b)(2), and that is not listed in Appendix G, may not operate the affected

unit unless the requirements of this Subpart Q are met or the affected unit is

exempt pursuant to Section 217.386(b).

c)

Owners and operators of an affected unit may use NO

x

allowances to meet the

compliance requirements in Section 217.388 as specified below. A NO

x

allowance is defined as an allowance used to meet the requirements of a NO

x

12/20/2007 4:17 PM

Page

10

Electronic Filing - Received, Clerk's Office, December 20, 2007

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12/20/2007 4:17 PM

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11

trading program administered by USEPA where one allowance is equal to one ton

of NO

x

emissions.

1)

NO

x

allowances may be used only under the following circumstances:

A)

An anomalous or unforeseen operating scenario inconsistent with

historical operations for a particular ozone season or calendar year

that causes an exceedance of an emissions or operation hour

limitation;

B)

To achieve compliance no more than two events in any rolling

five-year period; and

C)

For a unit that is not listed in Appendix G.

2)

The owner or operator of the affected unit must surrender to the Agency a

NO

x

allowance for each ton or portion of a ton of NO

x

by which actual

emissions exceed allowed emissions. Where a low usage limitation under

Section 217.388(c)(2) has been exceeded, the owner or operator of the

affected unit must calculate the NO

x

emissions resulting from the number

of hours that exceeded the operating hour low usage limit and surrender to

the Agency one NO

x

allowance for each ton or portion of a ton of NO

x

that was calculated. For noncompliance with a seasonal limit in Section

217.388(b), only a NO

x

ozone season allowance must be used. For

noncompliance with the emissions concentration limits in Section

217.388(a), low usage limitations in Section 217.388(c) or an annual

limitation in an emissions averaging plan in Section 217.388(b), only a

NO

x

annual allowance may be used.

3)

The owner operator must submit a report documenting the circumstances

that required the use of NO

x

allowances and identify what actions will be

taken in subsequent years to address these circumstances and must transfer

the NO

x

allowances to the Agency’s federal NO

x

retirement account. The

report and the transfer of allowances must be submitted by October 31 for

exceedances during the ozone season and March 1 for exceedances of the

emissions concentration limits, the annual emissions averaging plan limits,

or low usage limitations. The report must contain the NATS serial

numbers of the NO

x

allowances.

(Source: Amended at

Ill. Reg.

, effective

)

Section 217.394

Testing and Monitoring

a)

An owner or operator must conduct an initial performance test pursuant to

subsection (c)(1) or (c)(2) of this Section as follows:

Electronic Filing - Received, Clerk's Office, December 20, 2007

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12/20/2007 4:17 PM

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1)

By January 1, 2008, for affected engines listed in Appendix G.

Performance tests must be conducted on units listed in Appendix G, even

if the unit is included in an emissions averaging plan pursuant to Section

217.388(b).

2)

By the applicable compliance date as set forth in Section 217.392, or

withinWithin the first 876 hours of operation per calendar year, which

ever is later:

A). Performance tests must be conducted on For affected units not listed

in Appendix G that operate more than 876 hours per calendar year;

and

B)

For units that are not affected units that are included in an

emissions averaging plan and operate more than 876 hours per

calendar year.

3)

Once within the five-year period after the applicable compliance date as

set forth in Section 217.392:

A)

For affected units that operate fewer than 876 hours per calendar

year; and. Performance tests must be conducted on

B)

For units that are not affected units that are included in an

emissions averaging plan and that operate fewer than 876 hours

per calendar year.

b)

An owner or operator of an engine or turbine must conduct subsequent

performance tests pursuant to subsection (c)(1), or (c)(2), or (c)(3) of this Section

as follows:

1)

For affected engines listed in Appendix G and all units included in an

emissions averaging plan, once every five years. Testing must be

performed in the calendar year by May 1 or within 60 days after starting

operation, whichever is later;

2)

If the monitored data shows that the unit is not in compliance with the

applicable emissions concentration or emissions averaging plan, the owner

or operator must report the deviation to the Agency in writing within 30

days and conduct a performance test pursuant to subsection (c) of this

Section within 90 days of the determination of noncompliance; and

3)

When in the opinion of the Agency or USEPA, it is necessary to conduct

testing to demonstrate compliance with Section 217.388, the owner or

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13

operator of a unit must, at his or her own expense, conduct the test in

accordance with the applicable test methods and procedures specified in

this Section within 90 days after receipt of a notice to test from the

Agency or USEPA.

c)

Testing Procedures:

1)

For an engine: The owner or operator must conduct a performance test

using Method 7 or 7E of 40 CFR 60, appendix A, as incorporated by

reference in Section 217.104. Each compliance test must consist of three

separate runs, each lasting a minimum of 60 minutes. NO

x

emissions must

be measured while the affected unit is operating at peak load. If the unit

combusts more than one type of fuel (gaseous or liquid) including backup

fuels, a separate performance test is required for each fuel.

2)

For a turbine included in an emissions averaging plan: The owner or

operator must conduct a performance test using the applicable procedures

and methods in 40 CFR 60.4400, as incorporated by reference in Section

217.104.

d)

Monitoring: Except for those years in which a performance test is conducted

pursuant to subsection (a) or (b) of this Section, the owner or operator of an

affected unit or a unit included in an emissions averaging plan must monitor NO

x

concentrations annually, once between January 1 and May 1 or within the first

876 hours of operation per calendar year, whichever is later. If annual operation

is less than 876 hours per calendar year, each affected unit must be monitored at

least once every five years. Monitoring must be performed as follows:

1)

A portable NO

x

monitor utilizing method ASTM D6522-00, as

incorporated by reference in Section 217.104, or a method approved by

the Agency must be used. If the engine or turbine combusts both liquid

and gaseous fuels as primary or backup fuels, separate monitoring is

required for each fuel.

2)

NO

x

and O

2

concentrations measurements must be taken three times for a

duration of at least 20 minutes. Monitoring must be done at highest

achievable load. The concentrations from the three monitoring runs must

be averaged to determine whether the affected unit is in compliance with

the applicable emissions concentration or emissions averaging plan as

specified in Section 217.388.

e)

Instead of complying with the requirements of subsections (a), (b), (c) and (d) of

this Section, an owner or operator may install and operate a CEMS on an affected

unit that meets the applicable requirements of 40 CFR 60, subpart A, and

appendix B, incorporated by reference in Section 217.104, and complies with the

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quality assurance procedures specified in 40 CFR 60, appendix F, or 40 CFR 75

as incorporated by reference in Section 217.104, or an alternate procedure as

approved by the Agency or USEPA in a federally enforceable permit. The CEMS

must be used to demonstrate compliance with the applicable emissions

concentration or emissions averaging plan only on an ozone season and annual

basis.

f)

The testing and monitoring requirements of this Section do not apply to affected

units in compliance with the requirements of the low usage limitations pursuant to

Section 217.388(c) or low usage units using NO

x

allowances to comply with the

requirements of this Subpart pursuant to Section 217.392(c). Notwithstanding the

above circumstances, when in the opinion of the Agency or USEPA, it is

necessary to conduct testing to demonstrate compliance with Section 217.388, the

owner or operator of a unit must, at his or her own expense, conduct the test in

accordance with the applicable test methods and procedures specified in this

Section within 90 days after receipt of a notice to test from the Agency or

USEPA.

(Source: Amended at

Ill. Reg.

, effective

)

Section 217.396

Recordkeeping and Reporting

a)

Recordkeeping. The owner or operator of a unit included in an emissions

averaging plan or an affected unit that is not exempt pursuant to Section

217.386(b) and is not subject to a the low usage exemption of Section 217.388(c)

of an Appendix G unit or a unit included in an emissions averaging plan must

maintain records that demonstrate compliance with the requirements of this

Subpart Q which include, but are not limited to:

1)

Identification, type (e.g., lean-burn, gas-fired), and location of each unit.

2)

Calendar date of the record.

3)

The number of hours the unit operated on a monthly basis, and during

each ozone season.

4)

Type and quantity of the fuel used on a daily basis.

5)

The results of all monitoring performed on the unit and reported

deviations.

6)

The results of all tests performed on the unit.

7)

The plan for performing inspection and maintenance of the units, air

pollution control equipment, and the applicable monitoring device

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pursuant to Section 217.388(d)(c).

8)

A log of inspections and maintenance performed on the unit’s air

emissions, monitoring device, and air pollution control device. These

records must include, at a minimum, date, load levels and any manual

adjustments along with the reason for the adjustment (e.g., air to fuel ratio,

timing or other settings).

9)

If complying with the emissions averaging plan provisions of Sections

217.388(b) and 217.390 copies of the calculations used to demonstrate

compliance with the ozone season and annual control period limits,

noncompliance reports for the ozone season, and ozone and annual control

period compliance reports submitted to the Agency.

10)

Identification of time periods for which operating conditions and pollutant

data were not obtained by either the CEMS or alternate monitoring

procedures including the reasons for not obtaining sufficient data and a

description of corrective actions taken.

11)

Any NO

x

allowance reconciliation reports submitted pursuant to Section

217.392(c)(3).

b)

The owner or operator of an affected unit or unit included in an emissions

averaging plan must maintain the records required by subsectionssubsection (a) or

(d) of this Section, as applicable, for a period of five-years at the source at which

the unit is located. The records must be made available to the Agency and

USEPA upon request.

c)

Reporting Requirements

1)

The owner or operator must notify the Agency in writing 30 days and five

days prior to testing pursuant to Section 217.394(a) and (b) and:

A)

If after the 30-days notice for an initially scheduled test is sent,

there is a delay (e.g., due to operational problems) in conducting

the performance test as scheduled, the owner or operator of the

unit must notify the Agency as soon as possible of the delay in the

original test date, either by providing at least seven days prior

notice of the rescheduled date of the performance test, or by

arranging a new test date with the Agency by mutual agreement;

B)

Provide a testing protocol to the Agency 60 days prior to testing;

and

C)

Not later than 30 days after the completion of the test, submit the

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16

results of the test to the Agency.

2)

Pursuant to the requirements for monitoring in Section 217.394(d), the

owner or operator of the unit must report to the Agency any monitored

exceedances of the applicable NO

x

concentration from Section 217.388(a)

or (b) within 30 days after performing the monitoring.

3)

Within 90 days after permanently shutting down an affected unit or a unit

included in an emissions averaging plan, the owner or operator of the unit

must withdraw or amend the applicable permit to reflect that the unit is no

longer in service.

4)

If demonstrating compliance through an emissions averaging plan:

A)

By October 31 following the applicable ozone season, the owner or

operator must notify the Agency if he or she cannot demonstrate

compliance for that ozone season; and

B)

By January 3130 following the applicable calendar year, the owner

or operator must submit to the Agency a report that demonstrates

the following:

i)

For all units that are part of the emissions averaging plan,

the total mass of allowable NO

x

emissions for the ozone

season and for the annual control period;

ii)

The total mass of actual NO

x

emissions for the ozone

season and annual control period for each unit included in

the averaging plan;

iii)

The calculations that demonstrate that the total mass of

actual NO

x

emissions are less than the total mass of

allowable NO

x

emissions using equations in Sections

217.390(f) and (g); and

iv)

The information required to determine the total mass of

actual NO

x

emissions and the calculations performed in

subsection (cd)(4)(B)(iii) of this Section.

5)

If operating a CEMS, the owner or operator must submit an excess

emissions and monitoring systems performance report in accordance with

the requirements of 40 CFR 60.7(c) and 60.13, or 40 CFR 75 incorporated

by reference in Section 217.104, or an alternate procedure approved by the

Agency or USEPA and included in a federally enforceable permit.

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17

6)

If using NO

x

allowances to comply with the requirements of Section

217.388, reconciliation reports as required by Section 217.392(c)(3).

d)

The owner or operator of an affected unit that is complying with the low usage

provisions of Section 217.388(c) must:

1)

For each unit complying with Section 217.388(c)(1), maintain a record of

the NO

x

emissions for each calendar year;

2)

For each unit complying with Section 217.388(c)(2), maintain a record of

bhp or MW hours operated each calendar year; and

3)

For each unit utilizing NO

x

allowances for compliance pursuant to Section

217.392(c)(3), maintain and submit any NO

x

allowance reconciliation

reports.

(Source: Amended at

Ill. Reg.

, effective

)

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18

Part 211:

Section 211.1920

Emergency or Standby Unit

“Emergency or Standby Unit” means, for a stationary gas turbine or a stationary reciprocating

internal combustion engine, a unit that:

a)

Supplies power for the source at which it is located but operates only when the

normal supply of power has been rendered unavailable by circumstances beyond

the control of the owner or operator of the source and only as necessary to assure

the availability of the engine or turbine. An emergency or standby unit may not

be operated to supplement a primary power source when the load capacity or

rating of the primary power source has been reached or exceeded.

b)

Operates exclusively for firefighting or flood control or both.

c)

Operates in response to and during the existence of any officially declared

disaster or state of emergency.

d)

Operates for the purpose of testing, repair or routine maintenance to verify its

readiness for emergency or standby use.

e)

Notwithstanding any other subsection in this Section, emergency or standby units

may operate an additional 50 hours per year in non-emergency situations.

The term does not include equipment used for purposes other than emergencies, as

described above, such as to supply power during high electric demand days.

(Source: Amended at

Ill. Reg.

, effective

)

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19

35 Ill. Adm. Code 201.146

Use the language as it appeared in the first notice as set forth in the Ill. Reg. dated May 4,

2007.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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AMENDED

TECHNICAL SUPPORT DOCUMENT

FOR CONTROLLING NO

x

EMISSIONS

FROM STATIONARY RECIPROCATING INTERNAL

COMBUSTION ENGINES AND TURBINES

R07-19

AQPSTR 07-05

December 20, 2007

ILLINOIS ENVIRONMENTAL PROTECTION AGENCY

AIR QUALITY PLANNING SECTION

DIVISION OF AIR POLLUTION CONTROL

BUREAU OF AIR

1021 NORTH GRAND AVENUE EAST

P.O. BOX 19276

SPRINGFIELD, IL 62794-9276

Electronic Filing - Received, Clerk's Office, December 20, 2007

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Table of Contents

Page

List of Figures................................................................................................................. 3

List of Tables .................................................................................................................. 4

List of Acronyms............................................................................................................ 5

Executive Summary....................................................................................................... 7

1.0

Introduction........................................................................................................ 9

2.0

Background ........................................................................................................11

2.1

National Ambient Air Quality Standards (NAAQS) for Ozone and

Fine Particulates.......................................................................................11

2.2

Reasonably Available Control Technology (RACT)...............................13

2.3

Reasonable Further Progress (RFP).........................................................14

3.0

Process Description and Sources of Emissions................................................16

3.1

Stationary Reciprocating Internal Combustion Engines (RICE).............16

3.2

Stationary Turbines..................................................................................17

4.0

Technical Feasibility of Controls......................................................................19

4.1

Air/Fuel Ratio Adjustment.......................................................................19

4.2

Ignition Timing Retard ............................................................................20

4.3

Prestratified Charge .................................................................................21

4.4

Low Emission Combustion (LEC)...........................................................21

4.5

Water/Steam Injection .............................................................................22

4.6

Dry Low-NOx Combustors......................................................................23

4.7

Non-Selective Catalytic Reduction (NSCR)............................................24

4.8

Selective Catalytic Reduction (SCR).......................................................25

4.9

Technical Feasibility of Controls Summary ............................................25

5.0

Cost Effectiveness of Controls ..........................................................................27

5.1

Cost Effectiveness of Controls on RICE .................................................27

5.2

Cost Effectiveness of Controls on Turbines ............................................29

6.0

Existing and Proposed Regulations..................................................................31

6.1

Existing Illinois Regulations....................................................................31

6.2

Other States Regulations..........................................................................31

6.3

Proposed Illinois Regulations ..................................................................33

7.0

Potentially Affected Sources .............................................................................38

8.0

Emissions Reductions………………………………………………………….39

9.0

Summary.............................................................................................................40

10.0

References...........................................................................................................42

Attachment A

List of Impacted RICE and Turbines ..................................................44

Electronic Filing - Received, Clerk's Office, December 20, 2007

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List of Figures

Figure 2-1

PM

2.5

Nonattainment Areas .....................................................................12

Figure 2-2

8-Hour Ozone Nonattainment Areas .......................................................12

Electronic Filing - Received, Clerk's Office, December 20, 2007

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List of Tables

Table 3-1

Uncontrolled NO

x

Emissions from RICE and Turbines ................................18

Table 4-1

Potential Emissions Reductions from RICE ..................................................26

Table 4-2

Potential Emissions Reductions from Turbines.............................................26

Table 5-1

Cost Effectiveness for Retrofit of Various NO

x

Control Systems.................28

Table 5-2

Costs and Cost Effectiveness of LEC Controls in 2004 Dollars ...................29

Table 5-3

Cost Effectiveness for Various NO

x

Control Systems for Turbines..............30

Table 6-1

NO

x

Control Requirements for RICE in Other States ...................................32

Table 6-2

NO

x

Control Requirements for Turbines in Other States ..............................33

Table 6-3

Example of Averaging Plan-Case 1...............................................................36

Table 6-4

Example of Averaging Plan-Case 2...............................................................36

Table 7-1

Number of Affected Sources .........................................................................38

Table 8-1

Estimated NO

x

Emissions Reductions from Affected RICE .........................39

Electronic Filing - Received, Clerk's Office, December 20, 2007

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List of Acronyms

A/F

air-to-fuel

ACT

Alternative Control Techniques

document

ALAPCO

Association of Local Air Pollution Control Officials

BART

Best Available Retrofit Technology

bhp

brake horsepower

Board

Illinois Pollution Control Board

BOOS

burner out of service

Btu

British Thermal Unit

CAA

Clean Air Act

CAIR

Clean Air Interstate Rule

CO

carbon monoxide

CO

2

carbon dioxide

CPI

Consumer Price Index

CT

combustion tuning

EE

energy efficiency

EGU

electric generating unit

FIP

Federal Implementation Plan

HC

hydrocarbons

Illinois EPA

Illinois Environmental Protection Agency

ITR

ignition timing retard

Lb

pound

LADCO

Lake Michigan Air Directors’ Consortium

LEC

low emission combustion

mmBtu

million British Thermal Units

MW

megawatt

NAA

nonattainment area

NAAQS

National Ambient Air Quality Standards

NO

x

nitrogen oxide

O

2

oxygen

O

3

ozone

PM

2.5

fine particulate matter

ppm

parts per million

ppmv

parts per million by volume

PSC

prestratified charge

PTE

potential to emit

RACT

Reasonably Available Control Technology

RFP

Reasonable Further Progress

RIA

Regulatory Impact Analysis

RICE

stationary reciprocating internal combustion engine

SCR

selective catalytic reduction

SI

spark-ignited

SIP

State Implementation Plan

SNCR

selective non-catalytic reduction

SO

2

sulfur dioxide

STAPPA

State and Territorial Air Pollution Program

Electronic Filing - Received, Clerk's Office, December 20, 2007

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TSD

Technical Support Document

TPY

tons per year

VOM

volatile organic material

ug/m

3

microgram per cubic meter

U.S. EPA

United States Environmental Protection Agency

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

Executive Summary

This technical support document (TSD) presents the rationale, documentation, and methodology

developed by the Illinois Environmental Protection Agency (Illinois EPA) in support of its

proposal to amend regulations controlling nitrogen oxide (NO

x

) emissions from stationary

reciprocating internal combustion engines (RICE) and and propose regulations controlling NO

x

emissions from turbines. Reciprocating internal combustion engines and turbines are a

significant source category of NO

x

emissions in Illinois and a contributor to fine particulate

matter (PM

2.5

) and ozone levels in areas of Illinois that are designated as nonattainment areas

(NAAs) for these pollutants. This proposal is intended to address the requirement for NO

x

Reasonably Available Control Technology (RACT) for these source categories in Illinois’ 8-

hour ozone and PM

2.5

nonattainment areas (NAAs). The Illinois EPA intends to address RACT

requirements for other source categories in a separate rulemaking. This proposal will also

address, in part, federal requirements to achieve emission reductions needed to ensure

Reasonable Further Progress (RFP) toward attainment of the NAAQS.

The Illinois EPA is proposing to control NO

x

emissions from sources located in the NAAs that

have a potential to emit (PTE) of 100 tons per year (TPY) of NO

x

, aggregated from all the

affected units at the sources. Regulations to control NO

x

emissions from RICE down to 500

brake-horsepower (bhp) and turbines down to 3.5 megawatts (MW) are included in this proposal.

The proposed regulation does not apply to emergency standby engines; engines used in research

and testing for the purposes of performance verification of engines; engines/turbines used for

agricultural purpose; and certain portable engines. The Illinois EPA, in consultation with the

affected sources, is proposing a low-usage limit of 8 million bhp-hour/year, aggregated from all

affected engines at a source, and 20,000 MW-hour/year, aggregated from all affected turbines at

a source.

The NO

x

control levels proposed in this submittal are considered reasonable, attainable, and

cost-effective. The NO

x

emissions levels are prescribed in parts per million by volume (ppmv)

corrected to 15 percent oxygen (O

2

) on a dry basis. The NO

x

limits for engines are 150 ppmv for

spark-ignited rich-burn; 210 ppmv for spark-ignited lean-burn; 365 ppmv for Worthington

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

engines; and 660 ppmv for diesel engines. For turbines, the NO

x

limits are 42 ppmv for gas-

fired, and 96 ppmv for liquid-fired turbines. An owner or operator may comply with the control

requirements by averaging the emissions of affected units. Compliance with the emission limits

will be determined on both an ozone season (May 1 to September 30) and an annual (January 1

to December 31) basis each year.

The Illinois EPA relied on the cost data and cost effectiveness estimates contained in the U.S.

EPA’s alternative control technology (ACT) guidance documents prepared by the U.S EPA for

RICE and turbines. The proposed regulation amends 35 Ill. Adm. Code Subpart Q and will

potentially affect a total of 63 RICE and 58 turbines in Illinois not previously affected by

Subpart Q. When fully implemented, NO

x

emissions will be reduced statewide by

approximately 2,155 TPY and 1,020 tons per ozone control season.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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1.0

Introduction

This TSD presents the rationale, documentation, and methodology developed by the Illinois EPA

to support its proposed regulation to control NO

x

emissions from RICE and turbines. RICE and

turbines are significant sources of NO

x

emissions in Illinois. Based on the Illinois EPA’s 2002

base year emissions inventory, out of 277,899 TPY of NO

x

emissions from point sources in

Illinois, approximately 23,347 TPY of NO

x

were emitted from RICE and turbines. This

represents approximately 8.4 percent of Illinois’ total point source NO

x

emissions.

The Illinois EPA has the responsibility under the CAA to develop a State Implementation Plan

(SIP) which provides for Reasonably Available Control Technology (RACT) for NO

x

in

moderate 8-hour ozone and PM

2.5

NAAs. This proposal is intended to address the requirement

for RACT for NO

x

for these source categories. The Illinois EPA intends to address RACT

requirements for other source categories in a separate rulemaking. This proposal will also

address, in part, federal requirements to achieve emission reductions needed to meet the RFP

requirements for the 8-hour ozone standard.

A brief summary of the various sections in this TSD is as follows:

Section 2 provides background information on ozone and particulate matter air quality and the

effects of these pollutants on human health. The regulatory requirements that are being

addressed by this proposal are also described in Section 2.

Section 3 contains descriptions of the various types of internal combustion engines and turbines

and how NO

x

emissions are generated by these processes. Also presented in this Section are the

estimated uncontrolled levels of NO

x

emissions from RICE and turbines in Illinois.

Section 4 identifies control techniques available to reduce NO

x

emissions from RICE and

turbines.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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General cost information on various control technologies is discussed in Section 5. This Section

provides cost information for the various control technologies that are available to control NO

x

emissions from stationary RICE and turbines, described in terms of cost effectiveness of controls

(i.e., dollars per ton of NO

x

emission reduced) to comply with the proposed regulation.

Existing and proposed regulations are discussed in Section 6. This Section summarizes the

existing Illinois NO

x

regulations, and other states’ NO

x

regulations for RICE and turbines, and

concludes with an explanation of the proposed regulations.

Sources in Illinois that are potentially affected by the proposed regulations are listed in

Section 7. Also described in this Section is the methodology that the Illinois EPA used to

identify sources that may potentially be affected by the proposed regulations.

Section 8 provides an estimate of emissions reductions that will be achieved by implementing

the Illinois EPA’s proposal and explains the methodology used by the Illinois EPA to estimate

NO

x

emissions reductions from this proposal.

Finally, a summary of this TSD is provided in Section 9.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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2.0

Background

2.1

National Ambient Air Quality Standards for Ozone and Fine Particulates

The U.S. EPA revised the NAAQS for particulate matter and ozone in 1997.

1, 2

The revised

standards for particulate matter recognized that the smallest particles, those less than equal to 2.5

microns in diameter, have adverse health effects in the humans. In response to the establishment

of the NAAQS for PM

2.5

, U.S. EPA designated two areas in Illinois as NAAs: the Chicago area

(consisting of Cook, DuPage, Kane, Lake, McHenry, and Will counties, and the townships of

Oswego, in Kendall County, and Aux Sable and Goose Lake, in Grundy County), and the Metro-

East St. Louis area (consisting of Madison, Monroe, and St. Clair counties, and Baldwin

Township in Randolph County). Figure 2-1 shows the PM

2.5

NAAs for Illinois and nearby

states. These designations became effective on April 5, 2005 (70

FR

943).

3

The revised NAAQS for ozone replaced the previous 1-hour averaging time with an 8-hour

averaging time, and reduced the applicable ambient concentration threshold from 0.12 parts per

million (ppm) to 0.08 ppm. U.S. EPA designated certain areas in Illinois and other states as

nonattainment for this air quality standard. Figure 2-2 shows the 8-hour ozone NAAs for the

states in the central United States. These designations became effective on June 15, 2004 (69

FR

23858).

4

Geographically, the ozone NAAs in Illinois are roughly the same areas that were

designated as nonattainment for PM

2.5.

The exception is in the Metro-East area. The 8-hour

ozone NAA includes Jersey County and does not include Baldwin Township in Randolph

County, while the PM

2.5

NAA does not include Jersey County but does include Baldwin

Township.

Fine particles and ozone are associated with thousands of premature deaths and illnesses each

year in the United States. In revising the NAAQS for particulate matter, U.S. EPA found that

fine particles aggravate respiratory, lung, and cardiovascular diseases, decrease lung function,

and increase asthma attacks, heart attacks, and cardiac arrhythmia. As a consequence of

exposure to PM

2.5

, hospital admissions and emergency room visits increase as does absenteeism

from school and work. Older adults, people with heart and lung disease, and children are the

segments of society that are particularly sensitive to fine particle exposure. Attainment of the

Electronic Filing - Received, Clerk's Office, December 20, 2007

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PM

2.5

standard will prolong thousands of lives in Illinois and other states. Additional

information on the health effects of fine particles can be found on U.S. EPA’s website at

http://www.epa.gov/ttn/naaqs/standards/pm/s_pm_index.html.

Figure 2-1

Figure 2-2

PM

2.5

Nonattainment Areas

8-Hour Ozone Nonattainment Areas

U.S. EPA’s revised NAAQS for ozone was intended to provide increased protection to the

public, especially children and other at-risk populations, against a wide range of ozone-induced

health effects. In setting the 8-hour ozone standard, U.S. EPA found that exposures to ozone of

one to three hours in length had been found to irritate the respiratory system, causing coughing,

throat irritation, and chest pain. Ozone exposure can limit lung function and breathing capacity,

resulting in rapid and shallow breathing, thereby lowering or curtailing a person’s normal

activity level. As with PM

2.5

exposure, ozone exposure increases asthma attacks for people with

Electronic Filing - Received, Clerk's Office, December 20, 2007

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13

respiratory disorders. Longer-term ozone exposure may result in damage to the lung tissue and

lining from inflammation, which can produce permanent and irreversible changes in lung

function. Children and adults who are active outdoors are particularly susceptible to ozone, as

are people with asthma and respiratory diseases. Ozone also affects sensitive ecosystems and

vegetation, resulting in reduced crop yields, reduced growth and lowered pest resistance, and a

lowered ability for plants and trees to survive. Additional information on the health effects to

humans and vegetation from exposure to ozone is found on U.S. EPA’s website:

http://www.epa.gov/ttn/naaqs/standards/ozone/s_o3 _index.html

U.S. EPA has long recognized the relationship between emissions of NO

x

and adverse regional

air quality issues and federal efforts to reduce emissions of NO

x

were initiated in 1990. The

CAA placed several new requirements to reduce NO

x

emissions. The federal programs that

affect NO

x

emissions sources are discussed in the following subsections.

2.2 Reasonably Available Control Technology (RACT)

Pursuant to Sections 172, 182(b) and (f) of the CAA, RACT is required for all existing major

sources of the applicable criteria pollutant and its precursors located in NAAs. This rulemaking

addresses NO

x

as a precursor to ozone and PM

2.5

. U.S. EPA defines RACT as the lowest

emission limitation that a particular source is capable of meeting by the application of control

technology that is reasonably available considering technological feasibility and economic

reasonableness (70

Fed. Reg.

71612).

5

The major source threshold for moderate NAAs is

defined as 100 TPY. A source generally consists of several units that emit pollutants. The sum

of emissions from all units at the source determines if a unit is major and thus subject to RACT

requirements. This rulemaking addresses two RACT categories, engines and turbines.

Additional RACT categories will be addressed in subsequent rulemakings.

RACT is not a new requirement under the CAA, but one that had previously been waived with

respect to Illinois’ two ozone NAAs. For the implementation of the 1-hour ozone NAAQS,

Illinois requested and received a waiver under Section 182(f) of the CAA from the requirement

to implement NO

x

RACT for major sources located in ozone NAAs. With respect to the 8-hour

ozone NAAQS, the Illinois EPA will not pursue the NO

x

waiver because the local-scale, NO

x

Electronic Filing - Received, Clerk's Office, December 20, 2007

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14

disbenefit (i.e., the scavenging of ambient ozone by local nitrogen oxide emissions) is not as

important for the longer 8-hour averaging time. Also, the level of the 8-hour ozone standard is

closer to regional background levels in the Midwest, which argues for the application of controls

on a regional basis. The Illinois EPA therefore intends to submit a SIP revision to implement

NO

x

RACT requirements per Sections 182(b)(2) and 182(f) of the CAA. Pursuant to 40 CFR

51.912, the State is required to submit a RACT SIP no later than 27 months (September 2006)

after designation of NAAs that provides for implementation of the measures no later than the

first ozone season that occurs 30 months after the RACT SIP is due (2009 ozone season). (70

FR

71611, 71701)

5

U.S. EPA finalized its implementation guidance for the PM

2.5

NAAQS on April 25, 2007.

6

This

guidance document addresses RACT requirements for PM

2.5

and its precursors, including NO

x

.

Based on U.S. EPA’s implementation guidance, Illinois’ SIP must include a demonstration that

all Reasonably Available Control Measures (RACM), which includes RACT, have been adopted

as necessary to demonstrate attainment as expeditiously as practicable and to meet any RFP

requirements. In determining RACM, the state must adopt technically and economically feasible

measures if collectively the measures would advance the attainment date by one year. Therefore,

for PM

2.5

, RACT is part of RACM, unlike ozone, and is not an independent requirement. In the

case of electric generating units (EGUs) regulated under the Clean Air Interstate Rule (CAIR),

however, U.S. EPA’s guidance does require that EGUs with existing controls must operate those

controls year-round to satisfy RACT.

Since affected emission units, engines and turbines, under this proposal must comply with

seasonal emission limitations to satisfy RACT for ozone, it is appropriate to also require that

these limitations continue on an annual basis to improve PM

2.5

air quality. Continuing controls

on an annual basis will not, in most cases, cause significant additional costs to affected sources,

and is consistent with the regulations previously adopted for engines under Subpart Q.

2.3

Reasonable Further Progress (RFP)

For an area classified as an ozone NAA under Subpart 2 of Part D of the CAA, and the

requirements of Section 182, a state is required to submit a SIP revision that includes measures

Electronic Filing - Received, Clerk's Office, December 20, 2007

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15

that ensure RFP towards the emissions reductions targets needed for attainment (40 CFR

51.910). To meet RFP requirements of Section 172(c)(2) of CAA, the state is required to submit

no later than 3 years (June 2007) following designation for the 8-hour NAAQS, a SIP providing

for RFP from the baseline year (2002) within 6 years after the baseline year (2008). The state

may use either NO

x

for VOM emission reductions (or both) to achieve the RFP reduction

requirement. Use of NO

x

emissions reductions must meet the criteria in Section 182(c)(2)(C) of

the CAA. For each subsequent 3-year period out to the attainment date, the RFP SIP must

provide for an additional increment of progress.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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16

3.0

Process Description and Sources of Emissions

3.1

Stationary Reciprocating Internal Combustion Engines (RICE)

“Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options,”

7

a document

published in July 1994 by the State and Territorial Air Pollution Program Administrators

(STAPPA)/Association of Local Air Pollution Control Official (ALAPCO), summarizes how

RICE operate and how they generate NO

x

emissions. RICE are the stationary relatives of motor

vehicle engines, using the combustion of fuel in cylinders to drive pistons with crankshafts,

which convert the linear piston motion to rotary motion. Ignition of the fuel in reciprocating

engines may be initiated by a spark or by the heat generated in the compression stroke of a

piston. Spark ignited (“SI”) engines typically burn gasoline or, in large engines, natural gas,

while compression ignition engines burn diesel oil or a dual-fuel (diesel oil-natural gas) mixture.

Reciprocating engines have either four-stroke or two-stroke operating cycles. A typical

automotive engine uses a four-stroke cycle of intake, compression, power, and exhaust. Two-

stroke engines complete the power cycle in a single engine revolution compared to two

revolutions for four-stroke engines.

A final classification of reciprocating engines that influence the choice of NOx control

alternatives is based on the engine air-to-fuel ratio and the exhaust oxygen content. Rich-burn

engines, which include four-stroke spark ignition engines, typically operate with an air-to-fuel

ratio near stoichiometric and exhaust oxygen concentrations of one percent or less. Lean-burn

engines, which include two-stroke spark ignition and all compression ignition engines, have a

lean air-to-fuel ratio and typical exhaust oxygen concentrations of greater than one percent.

Reciprocating engines are used throughout the United States to drive compressors, pumps,

electric generators and other equipment. One prominent use of large engines is to drive natural

gas pipeline compressor stations. Except for three engines compressing ammonia at a chemical

plant, all engines affected by the NO

x

SIP Call-Phase 2 rule in Illinois are used to compress

natural gas at natural gas pipeline stations. All currently operating RICE that are large enough to

Electronic Filing - Received, Clerk's Office, December 20, 2007

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17

be affected by the Illinois EPA proposal are either rich-burn or lean-burn engines that burn

natural gas exclusively.

RICE are significant sources of NO

x

because they burn large amounts of fuel at high

temperatures and pressures, which cause the nitrogen and oxygen in the air that sustains the

combustion to unite and form the various oxides of nitrogen that constitute NO

x

. Thermal NO

x

is the predominant mechanism by which NO

x

is formed in RICE. Reducing combustion

temperatures and pressures are therefore effective in reducing NOx emissions from reciprocating

engines. Although in theory additional NO

x

could be formed from nitrogen found in the fuel,

virtually all RICE burn fuels containing little if any nitrogen. Therefore, fuel NO

x

formation is

minimal in RICE.

3.2

Stationary Turbines

The same STAPPA/ALAPCO document,

7

referenced to previously in Section 3.1 also provides a

description and sources of NO

x

emissions from turbines. A gas turbine is an internal combustion

engine that operates with rotary rather than reciprocating motion. There are three basic phases in

the operation of a turbine: compression, combustion, and conversion to power. Ambient air is

drawn in and compressed up to 30 times ambient pressure and directed to the combustor section

where fuel is introduced, ignited, and burned. Hot combustion gases are then diluted with

additional air from the compressor and directed to the turbine section at temperatures up to

2,350°F. Energy from the hot expanding exhaust gases are then recovered in the form of a shaft

horsepower, of which 50 percent is needed to drive the internal compressor, and the balance of

recovered shaft energy is available to drive external load units.

The heat content of gases exiting the turbine can either be discarded without heat recovery

(simple cycle); used with a heat exchanger to preheat combustion air entering the combustor

(regenerative cycle); used with or without supplementary firing, in a heat recovery steam

generator to raise process steam temperature (cogeneration); or used with or without

supplementary firing to raise steam temperature for a steam turbine Rankine cycle (combined

cycle or repowering). The majority of turbines used in large stationary installations are either

Electronic Filing - Received, Clerk's Office, December 20, 2007

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18

peaking simple cycle, two-shaft or base load, combined cycle turbines. Smaller turbines are

used to compress gas in natural gas pipelines or to generate electricity.

The principle type of NO

x

formed in a turbine firing natural gas or distillate oil is thermal NOx.

Most thermal NO

x

is formed in high temperature stoichiometric flame pockets downstream of

fuel injectors where combustion air has mixed sufficiently with the fuel to produce the peak

temperature fuel/air interface. The maximum thermal NO

x

production occurs at a slightly lean-

fuel mixture because of excess oxygen available for reaction. The control of stoichiometry is

critical in achieving reduction in thermal NO

x

. The thermal NO

x

generation also decreases

rapidly as the temperature drops below the adiabatic temperature (for a given stoichiometry).

Maximum reduction in thermal NO

x

generation can thus be achieved by control of both the

combustion temperature and the stoichiometry.

Table 3-1 describes the uncontrolled NO

x

emissions in parts per million by volume (ppmv)

corrected to 15 percent oxygen (O

2

) from various types of RICE and turbines.

Table 3-1

Uncontrolled NO

x

Emissions from RICE and Turbines

7,8

Type of Unit

Uncontrolled NO

x

Emissions (ppm@ 15% O

2

)

Range

Average

Rich-Burn SI Engines

880 – 1090

1060

Lean-Burn SI Engines

580 – 1360

1230

Diesel Engines

820 – 950

880

Dual-Fuel Engines

360 – 780

620

Natural Gas-fired Combustion Turbine

99 – 430

264

Distillate Oil fired Combustion

Turbine

150 – 680

415

Electronic Filing - Received, Clerk's Office, December 20, 2007

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19

4.0

Technical Feasibility of Controls

For reciprocating engines and turbines both combustion controls and post-combustion catalytic

reduction technologies can be applied to reduce NO

x

emissions. Combustion controls for

reciprocating engines, include air/fuel ratio adjustments, low emission combustion, and

prestratified charge. These controls function by modifying the combustion zone air/fuel ratio,

thus influencing oxygen availability and peak flame temperature. Ignition timing retard lowers

the peak flame temperature by delaying the onset of combustion. For turbines water/steam

injection and dry low-NO

x

combustors are the combustion control technologies used to reduce

NO

x

emissions. The two post-combustion control strategies that destroy NO

x

for RICE and

turbines are selective catalytic reduction and non-selective catalytic reduction. U.S. EPA’s

Alternative Control Techniques Document--NO

x

Emissions from Stationary Reciprocating

Internal Combustion Engines

8

, and NO

x

Emissions from Stationary Gas Turbines,

9

provide

additional details on these NO

x

control techniques.

4.1

Air/Fuel Ratio Adjustment

Lowering the air-to-fuel (A/F) ratio in rich-burn engines limits oxygen availability in the

cylinder, thus decreasing NO

x

emissions both by lowering peak flame temperature and by

producing a reducing atmosphere. It is generally applicable to rich-burn engines and, in addition

to simple adjustment of the A/F ratio, requires the installation of a feedback controller so that

changes in load and other operating conditions may be followed. Additional modification of

turbocharged engines may be necessary.

Air/fuel ratio adjustment is a well-demonstrated alternative in rich-burn engines and typically

yields 10-40 percent reductions in NO

x

emissions. This range is broad in part because a wide

range of existing air/fuel ratios translates into variable scope for emissions reductions using this

technique.

In lean-burn engines, increasing the A/F ratio decreases NO

x

emissions. Extra air dilutes the

combustion gases, thus lowering peak flame temperature and reducing thermal NO

x

formation.

In order to avoid an engine’s capacity being derated, air flow to the engine must be increased at

Electronic Filing - Received, Clerk's Office, December 20, 2007

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20

constant fuel flow, with the result that installation of a turbocharger (or modification of an

existing one) is necessary to implement this technique. An automatic A/F controller also will be

required for variable load operation.

Air/fuel ratio adjustment is generally applicable to lean-burn engines, although space constraints

may limit the extent to which turbocharger capacity may be increased. This control method is

most effective on fuel injected engines, in that carbureted engines do not have the same A/F in

each cylinder, thereby limiting changes in this ratio.

Reductions in lean-burn engine NO

x

emissions of 5-30 percent are possible by modifying the

A/F ratio. Achievable emissions reductions are limited by combustion instability and lean

misfire that occur as the lean flammability limit is approached, and by decreased engine

efficiency.

Air/fuel ratio adjustment is not applicable to compression ignition engines.

4.2 Ignition Timing Retard

Ignition timing retard (ITR) lowers NO

x

emissions by moving the ignition event to later in the

power stroke when the piston has begun to move downward. Because the combustion chamber

volume is not at its minimum, the peak flame temperature will be reduced, thus reducing thermal

NO

x

formation.

ITR is applicable to all engines. It is implemented in spark ignition engines by changing the

timing of the spark, and in compression ignition engines by changing the timing of the fuel

injection. While timing adjustments are straightforward, replacement of the ignition system with

an electronic ignition control or injecting timing system will provide better performance with

varying engine load and conditions.

Emissions reductions attainable using ITR are variable, depending upon the engine design and

operating conditions, and particularly on the air/fuel ratio. Reductions also are restricted by

limitations on the extent to which ignition may be delayed, in that excess retard results in engine

Electronic Filing - Received, Clerk's Office, December 20, 2007

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21

misfire. Retard also normally results in decreased fuel efficiency. For spark ignition engines,

achievable emissions reductions vary from 0-40 percent, and for compression ignition engines,

from 20-30 percent.

ITR results in increased exhaust temperatures, which may result in reduced exhaust valve and

turbocharger life. On diesel engines, it also may result in black smoke.

4.3

Prestratified Charge

Prestratified charge (PSC) is a technology for injecting fuel and air into the intake manifold in

distinct “slugs,” which become separate fuel and air layers upon intake into the cylinders. This

control alternative thus creates a fuel-rich, easily ignitable mixture around the spark plug and an

overall fuel-lean mixture in the piston. Combustion occurs at a lower temperature, thereby

producing much less thermal NO

x

, but without misfire even as the low flammability limit is

approached.

PSC is applicable to carbureted, spark ignition four-stroke engines. Engines, which are fuel-

injected or blower-scavenged, cannot use this technique. Kits for retrofitting prestratified charge

are available for most engines and require installation of new intake manifolds, air hoses and

filters, control valves, and a control system. Controlled emissions normally are less than 2

g/bhp-hr (140 ppm) on natural-gas-fueled engines, corresponding to emissions reductions of 80-

95 percent.

4.4 Low Emission Combustion

Low emission combustion (LEC) is the combustion of a very fuel-lean mixture. Under these

conditions, NO

x

emissions, as well as carbon monoxide (CO) and hydrocarbons (HC), are

severely reduced.

Implementation of LEC requires considerable engine modification. Rich-burn engines must be

entirely rebuilt, with addition or replacement of the turbocharger and installation of new air

intake and filtration, carburetor and exhaust systems. The difficulty of burning very lean

mixtures results in the need to modify the combustion chamber, which implies replacing pistons,

Electronic Filing - Received, Clerk's Office, December 20, 2007

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22

cylinder heads, the ignition system and the intake manifold. While small cylinder designs that

promote air-fuel mixing are available, precombustion chambers must be installed on larger

engines. The chambers have 5-10 percent of the cylinder volume and allow ignition of a fuel-

rich mixture that ignites the lean mixture in the cylinder.

The applicability of LEC is somewhat limited. Conversion kits are not available for all engines

and refitted engines may have degraded load-following capabilities. Achievable controlled

emissions are 1-2 g/bhp-hr (70-140 ppm) for rich-burn engines, which corresponds to an

emissions reduction of 70-90 percent, and 1.5-3 g/bhp-hr (105-210 ppm) for lean-burn spark

ignition engines, or an emissions reduction of about 80-93 percent.

LEC is not effective for diesel engines, but does work for dual-fuel engines, allowing a reduction

in the fraction of diesel oil pilot fuel to 1 percent of the total, and limiting emissions to 1-2

g/bhp-hr (70-140 ppm), a decrease in emissions of 60-80 percent. Some reductions in exhaust

opacity have been claimed when LEC is implemented on dual-fuel engines.

4.5

Water/Steam Injection

Water/steam injection lowers peak flame temperatures by providing an inert diluent, thus

limiting thermal NO

x

formation. Water may be injected directly into the turbine combustor, or

may be converted to steam using turbine exhaust waste heat (with a heat recovery steam

generator), and then injected into the combustor.

More steam than water must be used to achieve a comparable NO

x

reduction. However, the use

of steam results in a lower energy penalty than the use of water and may even provide NO

x

reductions with no energy penalty if the waste heat used to generate steam would otherwise not

be recovered.

Wet injection is applicable to most, if not all, turbines, and has been applied to a large number of

turbines in the United States. Required equipment, in addition to water/steam injection nozzles,

includes a water treatment system, pumps or a steam generator, metering valves, and controls

and piping. Untreated water will lead to deposits on turbine blades, lowering efficiency and

Electronic Filing - Received, Clerk's Office, December 20, 2007

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23

perhaps damaging the turbine. Most turbine manufacturers sell water and steam injection

systems.

Controlled NO

x

emissions are a function of the amount of water injected and of the fuel/nitrogen

content as wet injection limits only thermal NO

x

formation. For natural gas, controlled

emissions levels of 25-75 ppm are attained with water-to-fuel ratios of about 0.5 – 1.5 lb steam

/lb fuel. (Approximately 1-2 lb steam/lb fuel is needed for equivalent control, given the lower

heat capacity of steam relative to that of water.) For distillate oil, controlled emissions of 42-

110 ppm are attained with similar water-to-fuel ratios. These controlled emissions levels

correspond to 60-90 percent emissions reductions.

The need to increase water-to-fuel ratios for increased emission reductions limits NO

x

control

capabilities. High water-to-fuel ratios result in increased hydrocarbon and greatly increased CO

emissions. Further, because heating injected water consumes energy, turbine fuel efficiency may

decrease. Wet injection may increase required turbine maintenance as a result of pressure

oscillations or erosion caused by contaminates in the feed water.

Finally, the water treatment plant creates wastewater. This wastewater is enriched

approximately three-fold by the dissolved minerals and pollutants that were in the raw water.

4.6 Dry Low-NOx Combustors

Dry low-NO

x

combustors encompass several different technologies. Lean premixed combustion

is the commercially available technology that affords the largest NO

x

reductions. It functions by

providing a large amount of excess air to the combustion chamber, lowering peak temperatures

by dilution. Air and fuel are premixed in lean premixed combustors to avoid the creation of

local fuel-rich, and therefore high-temperature, regions.

While retrofit low-NO

x

combustors are not available for all turbine models, they have been

installed on many turbines in the United States. Lean premixed combustor retrofits face varying

difficulties. Because lean premixed combustors reduce thermal NO

x

generation only, they are

less effective on oil-fired than on gas-fired turbines. Except in the case of silo combustors,

Electronic Filing - Received, Clerk's Office, December 20, 2007

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24

which are external to the turbine body, the retrofits may require some modification of the

combustor section of the turbine. Water/steam injection provides comparable reductions on oil-

fired turbines without retrofit of low-NO

x

combustors.

Controlled emissions levels achievable on gas-fired turbines are on the order of 25-42 ppm. On

some larger turbines, manufacturers are guaranteeing emissions of 9 ppm, and more will

approach this limit with improvements in technology. These figures correspond to NO

x

emissions reductions of 60-95 percent. Maximum reductions are attained only at high turbine

loads. Given reduced fuel requirements at low loads, premixing would yield air/fuel mixtures

near the lean flammability limit, with resulting flame instability and high CO emissions. Thus,

lean premixed combustors use diffusion flames at low loads.

4.7 Non-Selective Catalytic Reduction (NSCR)

Non-selective catalytic reduction (NSCR) uses the three-way catalysts found in automotive

applications to promote the reduction of NO

x

to nitrogen and water. Exhaust CO and HC are

simultaneously oxidized to carbon dioxide and water in this process.

NSCR is applicable only to rich-burn engines with exhaust oxygen concentrations below about 1

percent. Lean-burn engine exhaust will contain insufficient CO and HC for the reduction of the

NO

x

present. NSCR retrofits, in addition to the catalyst and catalyst housing, require installation

of an oxygen sensor and feedback controller to maintain an appropriate A/F ratio under variable

load conditions. Controlled emissions achievable with NSCR are below 1 g/bhp-hr (70 ppm),

corresponding to emissions reductions greater than 90 percent. NSCR controls are not feasible

for turbines.

7

4.8

Selective Catalytic Reduction

The catalyzed reduction of NO

x

with injected ammonia, referred to as selective catalytic

reduction (SCR), has been implemented on a number of gas, diesel, and dual-fuel engines in the

United States. and abroad. SCR is applicable only to lean-burn engines with greater than about

one percent exhaust oxygen, as oxygen is a reagent in the selective reduction reaction.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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25

Retrofitting SCR involves installation of the reactor and catalyst, appropriate ductwork, an

ammonia storage and distribution system, and a control system for variable load operation.

Achievable emissions reductions are limited only by the amount of catalyst used, and typically

are on the order of 90 percent, yielding controlled emissions below two g/bhp-hr (140 ppm).

Achievable NO

x

emissions reductions using SCR exceed 90 percent, which corresponds to

controlled emissions below 10 ppm and 25 ppm for many gas-fired and oil-fired turbines.

4.9

Technical Feasibility of Controls Summary

In summary, there are a number of techniques and control options available for reducing

emissions of NO

x

from RICE and turbines. The degree to which these various methods reduce

NO

x

emissions depends upon the type of engine and the fuel used in the engine. In their

publication “Controlling Nitrogen Oxides Under the Clean Air Act,”

7

STAPPA/ALAPCO

summarizes the potential emissions reductions from RICE and turbines. Tables 4-1 and 4-2

describe the NO

x

emissions reductions potential of the various control strategies for

reciprocating engines and turbines.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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26

Table 4-1

Potential Emissions Reductions from Reciprocating I. C. Engines

7

NO

x

Reduction Potential (%)

Control

Rich-Burn

Gas SI

Lean-Burn

Gas SI

Diesel

Dual Fuel

Air/Fuel Ratio Adjustment

10 – 40

5 - 30

N/A

N/A

Ignition Timing Retard

0 – 40

0 - 20

20 - 30

20 – 30

Prestratified Charge

80 – 90

N/A

N/A

N/A

Low Emission Combustion

70 – 90

80 - 93

N/A

60 – 80

Non-selective Catalytic Reduction

90 – 98

N/A

N/A

N/A

Selective Catalytic Reduction

N/A

90

80 - 90

80 – 90

Table 4-2

Potential Emissions Reductions from Turbines

7

Control

Emissions Reduction Potential (%)

Water/Steam Injection

70 - 90

Low-NOx Combustors

60 – 90

Selective Catalytic Reduction

90

Electronic Filing - Received, Clerk's Office, December 20, 2007

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5.0

Cost Effectiveness of Controls

The U.S. EPA has prepared a number of estimates of the cost effectiveness of controlling NO

x

emissions from RICE. The most recent and significant estimates are contained in federal ACT

documents for RICE and turbines.

8 , 9

The Illinois EPA relied on these documents to estimate the

cost effectiveness of controlling Illinois NO

x

sources potentially affected by this proposed

rulemaking.

5.1 Cost Effectiveness of Controls on RICE

The Illinois EPA relied on U.S. EPA’s cost estimates from the ACT document for RICE.

8

To

estimate cost effectiveness of controls, U.S. EPA considers total capital costs and total annual

costs. The total capital cost is the sum of the purchased equipment costs, direct installation

costs, indirect installation costs, and contingency costs. Annual costs consist of the direct

operating costs of materials and labor for maintenance, operation, utilities, material replacement

and disposal, and indirect operating charges including plant overhead, general administration,

and capital recovery charges. Cost effectiveness, in dollars/ton of NO

x

removed, is calculated

for each control technique by dividing the total annual cost by the annual tons of NO

x

removed.

U.S. EPA’s ACT document describes the costs of various NO

x

controls applicable to RICE.

Depending on the type, size, and operating hours of the engine, the cost effectiveness of each

control varies from a few hundred to several thousands dollars per ton of NO

x

removed. The

cost information in the ACT document is reported in 1993 dollars. The Illinois EPA used

Consumer Price Index (CPI) conversion factor of 0.765 for 1993 to arrive at 2004 dollars. Table

5-1 summarizes the cost effectiveness of various control options for engines equal to or greater

than 500 bhp.

Based on the ACT, there are a number of control options available which achieve the control

levels proposed in this rulemaking. The cost effectiveness ranges from $163 to $5,961 per ton of

NO

x

removed on an annual basis.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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Table 5-1

Cost Effectiveness for Retrofit of Various NO

x

Controls Systems

8

Type of Control

Engine Size

(bhp)

Total Capital

Cost

(Thousands of 2004

dollars)

Cost

Effectiveness

(2004 dollars/ ton of

NO

x

removed)

Automatic A/F Control to Rich-Burn SI Engine

500 – 8000

14.9-32.0

567-1,080

Electronic Ignition to Rich-Burn SI Engine

500 – 8000

15.9-32.0

469-987

A/F + Electronic Ignition to Rich-Burn SI Engine

500 – 8000

30.8-63.9

540-1,065

Prestratified Charge to Rich-Burn SI Engine

500 – 8000

66.0-113.5

163-1,712

Prestratified Charge with Turbocharger to Rich-

Burn SI Engine

500 – 8000

146.4-279.7

204-2,026

NSCR to Rich-Burn Engine SI Engine

500 – 8000

35.4-330.7

319-1,647

Low Emission Combustion to Medium Speed

Rich-Burn or Lean-Burn SI Engine

500 – 8000

15.6-1,947.7

464-629

Low Emission Combustion to Low Speed Rich-

Burn or Lean-Burn SI Engine

500 – 8000

639.2-4,052.3

991-2,575

Automatic A/F control to Lean-Burn SI Engine

550 - 11000

98.8-169.9

427-2,000

Electronic Ignition to Lean-Burn SI Engine

550 - 11000

15.9-32.0

652-1,556

A/F + Electronic Ignition to Lean-Burn SI Engine

550 - 11000

112.4-197.4

477-1,961

SCR to Lean-Burn SI engine

550 - 11000

457.5-1,451.0

641-3,542

Electronic Injection to Diesel Engine

500 – 8000

15.9-101.8

482-1,012

SCR to Diesel Engine

500 – 8000

308.5-1,264.1

899-4,536

Electronic Injection to Dual-Fuel Engine

700 – 8000

15.9-32.0

627-1,288

SCR to Dual-Fuel Engine

700 – 8000

333.3-1,264.1

1,165-4,745

Low-Emission Combustion to Dual-Fuel Engine

700 – 8000

941.2-5,228.8

2,928-5,961

Another reference document that the Illinois EPA relied upon in the development of this

regulatory proposal is “Stationary Reciprocating Internal Combustion Engines .

10

It discusses

the uncontrolled and controlled levels of NO

x

emissions from RICE and the cost effectiveness of

LEC. U.S. EPA obtained information on LEC costs from several sources. The total capital cost,

annual operating cost, and cost effectiveness projections in Table 5-2 are based on actual costs

for several LEC retrofits obtained from one engine manufacturer and one third party LEC

vendor. Other inputs include uncontrolled NO

x

emissions of 16.8 g/bhp-hr, controlled emissions

of 2.0 g/bhp-hr, and capacity utilization of 7,000 operating hours per year (prorated for the five

months of the ozone season). In most respects, the analysis was conducted according to the

Electronic Filing - Received, Clerk's Office, December 20, 2007

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29

methodology of the 1993 ACT document. The cost data was reported in 1990 dollars and the

Illinois EPA adjusted the cost data to 2004 dollars based on the CPI.

Table 5-2

Costs and Cost Effectiveness of LEC Controls in 2004 Dollars

10

Engine

NO

x

Reduction (tons)

Cost Effectiveness ($/ton NO

x

)

Size,

(bhp)

Total

Capital

Annual

Cost

Annual

O3 Season

Annual

O3 Season

80

$231,000

$59,100

9

4

7,730

18,510

240

242,000

61,400

27

11

2,680

6,430

500

259,000

65,200

57

24

1,360

3,270

1,000

293,000

72,400

114

48

750

1,820

2,000

359,000

86,900

228

95

450

1,090

4,000

493,000

116,000

457

190

300

730

6,000

627,000

146,000

685

285

250

610

8,000

760,000

175,000

914

381

230

550

5.2 Cost Effectiveness of Controls on Turbines

The Illinois EPA relied on cost data contained in U.S. EPA’s ACT

9

for determining cost

effectiveness estimates for control of turbines. A compilation of control costs complied by

STAPPA/ALAPCO

7

is also summarized here. U.S. EPA’s ACT document describes in detail the

capital cost and cost effectiveness of various controls for turbines based on 1990 dollars. The

1990 dollar estimates have been adjusted to 2004 dollars throughout this discussion as described

in Section 5.1. The cost effectiveness of two types of controls for smaller turbines of 3.3 MW

varies from $2,645 per ton of NO

x

on an annual basis removed for steam injection to $3,005 per

ton of NO

x

removed for water injection control. For dry low-NO

x

combustion, cost effectiveness

was $1,532 per ton of NO

x

removed for a four MW gas-fired turbine.

STAPPA/ALAPCO prepared a document which summarizes the cost of controlling various sizes

of turbines based on the cost information contained in the ACT for the turbines. The cost

information in the STAPPA/ALAPCO document

7

is reported in 1993 dollars. Table 5-3 shows

the cost effectiveness of controlling 5 to 25 MW turbines operating 8,000 hours annually.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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30

Table 5-3

Cost Effectiveness for Various NO

x

Controls Systems for Turbines

7

Type of Control

Turbine

Size

(MW)

Total

Capital Cost

(thousands of 2004

dollars)

Cost Effectiveness

(2004 dollars/ ton of

NO

x

removed)

Water Injection for Gas-Fired

5 – 25

711-1,490

902-2,327

Water Injection for Oil-Fired

5 – 25

745-1,582

732-1,699

Steam Injection for Gas-Fired

5 – 25

928-2,105

993-2,614

Steam Injection for Oil-Fired

5 – 25

974-2,261

680-1,699

Low-NOx Combustor for Gas-

Fired

5 – 25

630-1,438

314-1,046

SCR for Gas-Fired

5 – 25

748-2,013

1,606-3,203

SCR for Oil-Fired

5 – 25

748-2,018

1,072-2,039

The Illinois EPA believes that the impacted sources will meet the proposed limits by installing

combustion controls. Rich burn engines will install NSCR and lean burn engines will install LEC

technologies to comply the regulations. The Illinois EPA believes that retrofit costs of

controlling sources at proposed levels will be $319 to $2,575 per ton of NO

x

reduced for RICE

and $314 to $3,005 per ton of NO

x

reduced for turbines in 2004 dollars.

It should be recognized that reducing NO

x

emissions by combustion controls on RICE and

turbines may increase carbon monoxide emissions in some cases. The Illinois EPA believes that

the increases in CO emissions are not significant from an air quality perspective, but may be

high enough to trigger Prevention of Significant Deterioration (PSD) permitting requirements in

some cases.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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31

6.0 Existing and Proposed Regulations

6.1 Existing Illinois Regulations

In Part 217 of 35 Ill. Adm. Code, Illinois provides NO

x

limitations for certain fuel combustion

emission units, such as boilers and certain process emission units which use or produce nitric

acid. On July 20, 2007, the Board adopted 35 Ill. Adm. Code 217, Subpart Q, “Stationary

Reciprocating Internal Combustion Engines and Turbines,” in which it regulated the NOx

emissions from 28 large RICE engines identified by U.S. EPA under the NOx SIP Call Phase II

(R07-18). New Subpart Q contained provisions for NOx concentration levels, emissions

averaging plans, monitoring, testing, compliance, dates, recordkeeping, and reporting. Larger

non-EGU turbines greater than or equal to 250 mmBtu/hr capacities are regulated under 35 Il.

Adm. Code 217, Subpart U, which is the NO

x

SIP Call trading program for such units. The

owner or operator of any new RICE and turbines is subject to new source review requirements

and must meet any applicable New Source Performance Standards (NSPS) set by U.S. EPA.

Currently, there are no regulations to control NO

x

emissions from smaller turbines less than 250

mmBtu/hr capacities, nor are there regulations to control NOx emissions from reciprocating

engines not subject to the new Subpart Q.

6.2 Other States’ Regulations

Tables 6-1 and 6-2 contain summaries of the NO

x

control requirements in other states. Several

states have promulgated rules limiting NO

x

emissions from RICE. According to the

STAPPA/ALAPCO document

7

, Connecticut, Louisiana, New Jersey, New York, Rhode Island,

and Texas have established NOx limits based on the RACT requirements for NAAs. Typical

NO

x

RACT limits are 1.5 – 3.0 g/bhp-hr (105-210 ppm) for gas-fired rich- and lean-burn

engines, and 8-9 g/bhp-hr (584-660) for oil-fired lean-burn engines. In California, NO

x

emissions limits for RICE are based on the BART NO

x

limits. NO

x

limits in California’s

Ventura Bay Area County Air Quality Management Districts (AQMD), Santa Barbara County

AQMD, and South Coast AQMD are more stringent than RACT, and are set at 0.6 - 1.9 g/bhp-hr

(42 - 133 ppm) for lean-burn engines, 0.4 – 0.8 g/bhp-hr (28 - 70 ppm) for rich-burn engines, and

1.1 - 8.4 g/bhp-hr (80-613 ppm) for diesel engines. The size cut-off for engines to apply controls

varies from 50 bhp to 500 bhp in the states mentioned above.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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32

Table 6-1

NOx Control Requirements for RICE in Other States

State

Engine Size

Controlled (HP)

Control Level (g/hp-hr)

Gas-fired Rich Burn

Gas-fired Lean Burn

Compression Ignited

Liquid Fired

Texas

11

500 and greater

2 g/hp-hr (146 PPM)

under all operating

conditions

2 g/hp-hr (146 PPM)* at full load, 5

g/hp-hr (365 PPM) at 80-100% load

for new SI or CI dual fuel engines

manufactured after June 18, 1992; 5

g/hp-hr for older units at all loads, 8

g/hp-hr (584 PPM) at 80-100% load

11 g/hp-hr (803 ppm)

Indiana

12

NO

x

SIP Call

NO

x

SIP Call

NO

x

SIP Call

NO

x

SIP Call

Connecticut

13

≥

3 MMBtu/hr

(1175 HP)

2.5 g/hp-hr (183 PPM)

_

8 g/hp-hr (584 ppm)

Alabama

14

NO

x

SIP Call

NO

x

SIP Call

NO

x

SIP Call

NO

x

SIP Call

New York

15

200 HP in Severe

Ozone Area and

400 HP in rest of

State

2 g/hp-hr (146 PPM)

through March 31, 2005

& 1.5 g/hp-hr (110 PPM)

after April 1, 2005

3 g/hp-hr (220 PPM) through March

31, 2005 & 1.5 g/hp-hr (110 PPM)

after April 1, 2005

9 g/hp-hr (657 ppm)

through March 31, 2005

& 2.3 g/hp-hr (168 ppm)

after April 1, 2005

New Jersey

16

≥

500 HP

1.5 g/hp-hr (110 PPM)

2.5 g/hp-hr (182 ppm)

8 g/hp-hr (584 ppm)

Pennsylvania

17

153 ton

NOx/Season

1.5 g/hp-hr (110 PPM)

for >2,400

HP

3 g/hp-hr (220 PPM) for >

2,400

HP

2.3 g/hp-hr (168 ppm)

for >4,400

HP

Maryland

18

N.G. Pipeline

engines > 15%

capacity factor

Limits of 300 lb/hr for a

facility with 5 or less

engines, and 566 lb/hr

for a facility with more

than 5 engines

Antelope Valley Air

Quality Management

District(AVAQMD)

19

50 HP stationary

and 100 HP for

portable

Electric motor, 36 ppm

for stationary and 80

ppm for portable

Up to 770 ppm for >100

HP but less than 400 HP;

535 ppm for >

400HP

San Joanquin Valley

Unified Air Pollution

Control District

(SJVUAPCD)

20

50 HP

50 ppm or 90% red. For

waste gas/field gas

engine and 25 ppm or

96% red. for others

75 ppm or 85% red for two stroke

gaseous fuel < 100HP engine and

65 ppm for other

65ppm or 90% reduction

El Dorado County

Air Pollution Control

District

(EDCAPCD)

21

50 HP

25 ppm to 50 ppm based

on compliance dates

65 ppm to 125 ppm based on

compliance date

600 ppm to 700 ppm

based on compliance

date

IEPA Proposed

500 HP

150 ppm

210 ppm except 365 for

Worthington engines

660 ppm

Note:

1) NO

x

SIP Call requires 82 to 90 percent control on large engines that emitted one ton of NOx in any

1995 ozone season day.

22

2) 1 g/hp-hr = 73 ppm conversion factor was used to convert g/hp-hr to ppmv at 15 percent O

2

on a dry

basis.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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33

Table 6-2

NO

x

Control Requirements for Turbines in Other States

State

Turbine Size Controlled (HP)

Control Level

Texas

11

≥

500 HP (0.37 MW)

3 g/hp-hr (0.82 lb/mmBtu) (220 ppm)

Indiana

12

250 mmBtu/hr (≈ 25 MW)

Budget allowances under NOx Emissions Trading

Program

Up to 100 mmBtu/hr (≈ 10 MW)

55 ppm for Gas-fired, 75 ppm for Oil-fired

Connecticut

13

< 100 mmBtu/hr

0.9 lb/mmBtu (224 to 245 ppm)

New York

15

≥

10 mmBtu/hr (≈ 1 MW)

RACT, For Simple Cycle 50 ppm for gas, 100

ppm for oil; for combined cycle 42 ppm for gas

and 65 ppm for oil

New Jersey

16

≥

30 mmBtu/hr (≈ 3 MW)

For simple cycle gas-fired 0.2 lb/mmBtu (50

PPM), for oil-fired 0.4 lb/mmBtu (109 ppm); for

combined cycle gas-fired 0.15 lb/mmBtu (37

ppm), and for oil-fired 0.35 lb/mmBtu (95 ppm)

Maryland

18

≥

Capacity factor 15%

42 ppm for gas burning and 65 ppm for oil burning

South Coast Air

Quality

Management

District

(SCAQMD)

23

≥

0.3 MW

9 ppm to 25 ppm depending on the size and type

IEPA Proposed

≥

3.5 MW

42 ppm for gas-fired and 96 ppm for oil-fired

6.3 Proposed Illinois Regulations

The Illinois EPA considered other states NO

x

regulations, STAPPA/ALAPCO recommendations,

and U.S. EPA guidance documents in its proposal to establish reasonable levels of NO

x

controls

for reciprocating engines and turbines in Illinois. Size thresholds for the units affected by the

proposed regulation are based on their PTE for NO

x

on an annual basis. The Illinois EPA is

proposing to control NO

x

emissions from sources in the nonattainment area for 8-hr ozone

NAAQS that have a PTE of 100 TPY or more of NO

x

aggregated from all the affected units at

the source. The proposed regulation applies to RICE of 500 bhp capacities and above, and to

stationary turbines of capacities equal to or greater than 3.5 MW located at these 100 TPY

sources. The proposed amendments do not apply to emergency standby engines; engines used in

research and testing for the purposes of performance verification and testing of engines;

Electronic Filing - Received, Clerk's Office, December 20, 2007

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34

engines/turbines used for agricultural purpose; and certain portable engines. Sources can avoid

the proposed control requirement by staying below source-wide NO

x

emissions of 100 TPY from

all affected units or if the total operating rate for all affected engines is less than eight million

bhp per year and all affected turbines is less than 20 thousand MW-hr per year.

The Illinois EPA relied upon the U.S. EPA’s ACT

8,9

, and STAPPA/ALAPCO guidance

documents

7

to propose levels of controls for various types of units. All of the proposed controls

levels are based on the retrofit techniques available for each category of affected unit. From

review of the ACT and guidance documents and the comments received from the affected

sources during outreach, the Illinois EPA determined that LEC controls on Worthington engines

can achieve NO

x

emissions of 308-420 ppmv as compared to other spark-ignited lean burn

engine that can achieve NO

x

emissions below 210 ppmv. Therefore, an average limit of 365

ppmv is proposed for Worthington engines. Although, post-combustion controls, such as SCR,

are available and can achieve the greatest reductions, the proposed control levels do not require

SCR as a compliance method.

Section 182(f) of the CAA introduced the requirement for existing major stationary sources of

NO

x

in NAAs to install and operate RACT to control NO

x

emissions. The NO

x

control levels

proposed in this submittal are considered reasonable, attainable, and cost-effective. The NO

x

emissions levels are prescribed in ppmv corrected to 15 percent O

2

on a dry basis. The NO

x

limits for engines are 150 ppmv for spark-ignited rich-burn, 210 ppmv for spark-ignited lean-

burn, 365 ppmv for Worthington engines and 660 ppmv for diesel engines and for turbines the

NOx limits are 42 ppmv for gas-fired and 96 ppmv for liquid-fired. An owner or operator may

comply with the control requirements by averaging the emissions of affected units that

commenced operation on or before January 1, 2002, unless the unit is a replacement unit, in

which case such a unit may be included even if it commenced operation after January 1, 2002.

Compliance with the emission limits will be determined on both an ozone season (May 1, to

September 30) and an annual (January 1 to December 31) basis each year. For units included in

an averaging plan, and units using Continuous Emissions Monitoring Systems (CEMS),

compliance with the emission limits must be demonstrated each year. For all other units,

Electronic Filing - Received, Clerk's Office, December 20, 2007

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35

compliance will be demonstrated on a periodic basis using stack tests and portable monitoring

systems.

The Illinois EPA believes that most engines and turbines can reasonably achieve the proposed

NO

x

emission limitations. However, some engines or turbines may have difficulty in achieving

the proposed limits. Therefore, The Illinois EPA is also proposing a NO

x

emissions averaging

option to assist sources in complying with the regulations. To take advantage of this flexible

approach, a company must submit an emissions averaging plan which lists all of its units that

will be included under this option. The total sum of the

actual

NO

x

emissions from each engine

or turbine in an averaging plan (based on stack tests results and annually monitored data) must

be less than the total sum of the

allowable

NO

x

emissions from those engine and turbines in the

averaging plan based on the respective control level proposed. If sources, which are using an

averaging plan, replace their fuel combusting units with electric motors, the allowable NO

x

emissions from the affected units that were replaced should be used in the averaging calculations

and the actual NO

x

emissions for the electric motors are considered zero. The allowable NO

x

emissions from the electric motor is determined by multiplying the total bhp-hrs generated by the

motor (bhp rate of motor x operating hours) by the allowable NO

x

emission rate of the replaced

unit in lbs/mmBtu and converting the pounds of NO

x

emissions using the factor of 0.00077

mmBtu/bhp-hr. The conversion factor was derived by using a standard conversion factor of one

bhp-hr equals to 2545.1 Btu and engine thermal efficiency of 33%.

For a replacement unit which is not electric, the allowable NO

x

emission rate to be used in the

averaging plan prior to its compliance date will be the higher of the applicable uncontrolled NO

x

emission rate from the U.S. EPA’s AP-42 document or the actual NO

x

emission rate as

determined by testing or monitoring. On and after the applicable compliance date for the

replacement unit, the allowable NO

x

emission rate will be the allowable applicable NO

x

emission

concentration limit specified in the proposed rule.

For a unit that is replaced with purchased power, the allowable NO

x

emission rate will be the

applicable NO

x

emissions concentration specified in the proposed rule. The actual hours of

operation to be used will be the annual hours of operation for the replaced unit averaged over the

Electronic Filing - Received, Clerk's Office, December 20, 2007

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36

three-year period prior to the date of purchasing power. Purchased power units may be included

in an emission averaging plan for no more than five years.

Tables 6-3 and 6-4 provide examples of how the proposed emissions averaging plan will work.

Table 6-3 shows an example plan which includes four engines and one turbine. In this example,

actual NO

x

emissions of 812,965 pounds are greater than the allowable NO

x

emissions of

804,666 pounds; therefore, the source is not in compliance with the proposed rule. Table 6-4

shows that by adjusting the operating hours of each engine and turbine, the actual NO

x

emissions

of 783,316 pounds, therefore the company achieves compliance without any penalty in fuel

consumption and total bhp-hrs in a year.

Table 6-3

Example of Averaging Plan-Case 1

Engines

Rated

bhp

Allow.

NO

x

Limit

(ppm)

Actual

NO

x

Limit

(ppm)

Fuel Use

(mmBtu/yr)

Hours

of

Oper.

Bhpbhp-

hrs x10

3

Allow. NO

x

(lb)

Actual NO

x

(lb)

Engine 1

3,000

150

175

127,500

5,000

15,000

70,456

82,199

Engine 2

3,500

210

220

148,750

5,000

17,500

115,078

120,558

Engine 3

4,000

660

700

170,000

5,000

20,000

436,121

462,553

Engine 4

4,500

210

150

191,250

5,000

22,500

147,958

105,684

Turbine 5

5,361

42

50

227,843

5,000

26,805

35,253

41,968

Total

865,343

25,000

101,805

804,866

812,962

Table 6-4

Example of Averaging Plan-Case 2

Engines

Rated

bhp

Allow.

NO

x

Limit

(ppm)

Actual

NO

x

Limit

(ppm)

Fuel Use

(mmBtu/yr)

Hours

of

Oper.

Bhp-hrs

x10

3

Allow. NO

x

(lb)

Actual NO

x

(lb)

Engine 1

3,000

150

175

114,750

4,500

15,000

63,410

73,979

Engine 2

3,500

210

220

133,875

4,500

17,500

103,570

108,502

Engine 3

4,000

660

700

156,400

4,600

20,000

401,231

425,548

Engine 4

4,500

210

150

232,475

6,078

22,500

179,851

128,465

Turbine 5

5,361

42

50

227,843

5,000

26,805

35,253

41,968

Total

865,343

24,678

101,805

783,316

778,463

An owner or operator of any affected engine or turbine located in Cook, DuPage, Grundy, Kane,

Kendall, Lake, McHenry, Will, Jersey, Madison, Monroe, Randolph, or St. Clair counties (NAA

Electronic Filing - Received, Clerk's Office, December 20, 2007

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37

counties) are required to comply with the rule by May 1, 2010. This compliance date, although

later than the date required by U.S. EPA for NO

x

RACT, was chosen to allow companies the

ability to schedule equipment installations in a timely manner after promulgation of this

proposed rule.

The proposed regulations provides for the limited use of CAIR NO

x

allowances to comply with

the emission limitations. The use of CAIR NO

x

allowances are limited to documented

unforeseen or anomalous operating scenarios inconsistent with historical operations for a

particular ozone season or calendar year. This compliance option cannot be used more than

twice in any five-year rolling period. The owner or operator shall surrender one NO

x

allowance

for each ton or portion of a ton of NO

x

emissions on an annual basis by which actual emissions

exceed allowed emissions.

An owner or operator of an engine or a turbine subject to the proposed control limits shall

perform a compliance performance test once every five years to demonstrate compliance with

the rule. All affected units must be tested once every five years thereafter. Section 217.394 of

the proposal provides methods and procedures for testing and monitoring of the performance of

an affected unit. The test methods provided are approved by U.S. EPA as set forth in 40 CFR

60.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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38

7.0 Potentially Affected Sources

To determine potentially affected engines and turbines, the Illinois EPA reviewed its 2004

inventory of RICE and turbines. The Illinois EPA identified a total of 541 RICE and 220

turbines located in the NAAs that have the potential to be affected by the proposed regulations.

Some of these units will be regulated under the new Subpart Q. A list of potentially impacted

sources is included in Attachment A of this TSD.

Current Illinois regulations do not require sources to obtain permits to operate RICE with a

capacity of less than 1,500 bhp. Therefore, the Illinois NOx inventory does not include all the

engines from 500 to 1,500 bhp that may be affected by this proposal. To identify potentially

affected sources and to estimate NO

x

emissions reductions from sources, with smaller engines,

the, the Illinois EPA, with the assistance of the Department of Commerce and Economic

Opportunity (DCEO), conducted a statewide survey of industries and businesses and mailed

10,025 survey forms to determine how many engines in the 500 to 1,500 bhp size range are in

Illinois. Out of 10,025 surveys, only 458 were returned and, of those, only 8 reported having

RICE in the range of 500 to 1,500 bhp. Assuming the same proportion of affected engines per

number of responses applies to those that did not respond to the survey, the Illinois EPA

estimates that there are approximately 175 units that have the potential to be affected by the

proposed rule. The Illinois EPA further assumed that many of these units would qualify for

exemptions and therefore, only approximately 8 engines would be impacted by this proposal.

Table 7-1 summarizes the number of impacted sources estimated by the Illinois EPA that are less

than 1,500 bhp.

Table 7-1

Number of Affected Sources

Unit Type

Potentially Affected

Impacted

Illinois EPA Permitted IC Engines

541

55

Turbines

220

58

IC Engines

≥

500 bhp & < 1,500 bhp

79

8

Total

840

121

Electronic Filing - Received, Clerk's Office, December 20, 2007

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39

8.0 NO

x

Emissions Reductions

As described in Section 7 the Illinois EPA estimated that the total 2004 NO

x

emissions from the

55 RICE and 58 turbines potentially affected by this proposal to be 2,514 TPY and 1,235 tons

per ozone season. The Illinois EPA applied an 82 percent control level to gas-fired engines, 25

percent control efficiency to diesel engines, and 60 percent control efficiency to turbines to

estimate NO

x

emissions reductions from the proposed rule. No control was applied to a turbine

which is subject to NSPS for NO

x

emissions. The proposed rule will achieve estimated NO

x

emissions reductions from affected sources of 1,669 TPY and 814 tons per ozone season from

RICE in the Illinois EPA’s inventory and turbines greater than 3.5 MW as shown in Table 8-1.

Table 8-1

Estimated NO

x

Emissions Reductions from Affected RICE

Uncontrolled NO

x

NO

x

Emissions Reductions

Year

(TPY)

(tons/season)

(TPY)

(tons/season)

Illinois EPA

Permitted RICE

1,198

528

983

433

Turbines

1,316

706

686

381

Small units

593

247

486

203

Total

3,107

1,481

2,155

1,017

To estimate NO

x

emissions reductions from the smaller RICE, between 500 bhp and 1,500 bhp,

the Illinois EPA assumed the average capacity of the impacted RICE to be 1,000 bhp and the

estimated operating schedule to be 4,000 hours per year. At a NO

x

emission rate of 16.8 g/bhp-

hr, the estimated 2004 NOx emissions were determined to be 593 tons NO

x

per year and 247

tons per ozone season.. At a control efficiency of 82 percent, the NOx reduction from these

engines will be 486 TPY and 203 tons per ozone season. Table 8-1 shows the estimated NO

x

emissions reductions from “small units” with their corresponding total NO

x

emissions

reductions. As shown in Table 8-1, this proposal will provide NO

x

emissions reductions of

2,155 TPY and 1,017 tons per ozone season when fully implemented in 2010.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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40

9.0 Summary

This TSD presents the rationale, the documentation, and the methodology used by the Illinois

EPA in the development of its proposed regulation to control NO

x

emissions from reciprocating

internal combustion engines and turbines. NO

x

emissions are a contributor to fine particulate

matter and ozone levels in areas of Illinois that are designated as nonattainment areas for these

pollutants. The proposed regulation is being submitted to the Illinois Pollution Control Board to

satisfy the requirements of the CAA to implement RACT on these source categories. Illinois

EPA is in the process of developing regulations to control other NO

x

source categories, as

needed, to satisfy the CAA requirement for NO

x

RACT.

The Illinois EPA is proposing to control NO

x

emissions from sources in the NAA that have a

PTE of 100 TPY or more of NO

x

aggregated from all the affected units at the source. The

proposed regulation applies to RICE of 500 bhp capacities and above, and to stationary turbines

of capacities equal to or greater than 3.5 MW. The proposed regulation does not apply to

emergency standby engines; engines used in research and testing for the purposes of

performance verification and testing of engines; engines/turbines used for agricultural purposes;

and certain portable engines. Sources can avoid the proposed control requirement by staying

below source-wide NO

x

emission levels of 100 TPY from all affected units or by operating all

affected engines less than eight million bhp-hr/year and all affected turbines less than 20,000

MW-hr/year.

All affected engines and turbines are required to comply with the rule by May 1, 2010. From

outreach discussions, this approach was recommended to help alleviate anticipated equipment

and material delays, as well as demands on technical staffing needed for installation and testing

of new controls, without sacrificing critical emission reductions.

The Illinois EPA proposal includes a NO

x

emissions averaging option to assist sources in

complying with the regulations. To take advantage of this flexible approach, a company must

submit an averaging plan which lists all of its units that will be included under this option. The

total sum of the actual NO

x

emissions from each engine or turbine in an averaging plan (based on

Electronic Filing - Received, Clerk's Office, December 20, 2007

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41

stack tests results and annually monitored data) must be less than the total sum of the allowable

NO

x

emissions from those engine and turbines in the averaging plan based on the respective

control level proposed.

The proposed regulation will impact approximately 63 RICE and 58 turbines in Illinois when

fully implemented in 2010. When fully implemented, the proposed rule will reduce the NO

x

emissions from RICE by approximately 1,469 TPY and 636 tons per ozone control season at a

cost effectiveness of $319 to $2,575 per ton of NO

x

(in 2004 dollars). Emissions from gas

turbines will be reduced by approximately 686 TPY and 381 tons per ozone season at a cost

effectiveness of $314 to $3,005 per ton of NO

x

(in 2004 dollars).

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

42

10.0 References

1. National Ambient Air Quality Standards for Ozone, 62

FR

38855, July 18, 1997, (Ozone

Standards).

2. National Ambient Air Quality Standards for Particulate Matter, 62

FR

38652, July 18, 1997,

(PM

2.5

Standards).

3. Air Quality Designations and Classifications for fine Particles (PM

2.5

) National Ambient Air

Quality Standards, 70

FR

943, January 5, 2005.

4. 8-hour Ozone National Ambient Air Quality Standards, 69

FR

23858, April 30, 2004.

5. Final Rule to Implement the 8-Hour Ozone National Ambient Air Quality Standard, 70

FR

71612, November 29, 2005.

6. Clean Air Fine Particle Implementation; Final Rule, 40 C

FR Part 51

, April 25, 2007

.

7. Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options, July 1994, State

and Territorial Air Pollution Program Administrators/Association of Local Air Pollution

Control Officials.

8. Alternative Control Techniques Document--NOx Emissions from Stationary Reciprocating

Internal Combustion Engines EPA-453/R-93-032, July 1993, U.S. EPA, OAQPS, RTP, NC

27711.

9. Alternative Control Techniques Document – NOx Emissions from Stationary Gas Turbines,

EPA-453/R-93-007, January 1993, U.S. EPA, OAQPS, Research Triangle Park, NC 27711

10. Stationary Reciprocating Internal Combustion Engines, Updated Information on NOx

Emissions and Control Techniques, Revised Final Report, EPA Contract No. 68-D-026,

Work Assignment No. 2-28,EC/R Project No. ISD-228, September 1, 2000

.

11. Texas Administrative Code. Title 30, Rule 106.512: Stationary Engines and Turbines

12. Indiana Department of Environmental Management, Office of Air Quality, Section 9.326

IAC 10-5. Rule 5 Nitrogen Oxide Reduction Program for Internal Combustion Engines

(ICE).

13. Document Prepared by the State of Connecticut, Department of Environmental Protection.

Sec. 22a-174-22 Control of Nitrogen Oxides Emissions

.

14. Alabama Department of Environmental Management. Air Division, Chapter 335-3-8,

Nitrogen Oxides Emissions.

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

43

15. New York State, Department of Environmental Conservation Rule and Regulations, Subpart

227.2, Reasonable Available Control Technology (RACT) for Oxides of Nitrogen (NOx).

16. New Jersey State Department of Environmental Protection, New Jersey Administrative

Code Title 7, Chapter 27, Subchapter 19: Control and Prohibition of Air Pollution from

Oxides of Nitrogen.

17. Pennsylvania Department of Environmental Protection, Air Quality Regulations, Small

Source of NOx Cement Kilns and Large Internal Combustion Engines, 25 PA Code CHS

121,129 and 145.

18. Code of Maryland Regulations. Title 26 Department of the Environment. Subtitle 11 Air

Quality, Chapter 09: Control of Fuel-Burning Equipment, Stationary Internal Combustion

Engines, and Certain Fuel-Burning Installation.

19. Antelope Valley Air Quality Management District. Rule 1110.2: Emissions from Stationary,

Non-Road & Portable Internal Combustion Engines.

20. San Joaquin Valley Unified Air Pollution Control District Rule 4702: Internal Combustion

Engines – Phase 2.

21. El Dorado County Air Pollution Control District Rule 233: Stationary Internal Combustion

Engines.

22. Interstate Ozone Transport: Response to Court Decisions on the NOx SIP Call, NOx SIP

Call Technical Amendments, and Section 126 Rules; Final Rule. 69 FR 21603, April 21,

2004.

23. South Coast Air Quality Management District, Rule 1134 – Emissions of Oxides of

Nitrogen from Stationary Gas Turbines.

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

44

Attachment A

List of Impacted RICE and Turbines

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

45

List of Impacted RICE

Id Number

Plant Name

Emission

Point

No. of

Units

031600ATR

International Malting Company - United States

0011

2

031600ATR

International Malting Company - United States

0014

2

031600ATR

International Malting Company - United States

0012

2

031600CEV

University of Illinois At Chicago

0009

1

031600CEV

University of Illinois At Chicago

0010

1

031600CEV

University of Illinois At Chicago

0011

2

043065ADG

Nicor Gas

0003

4

097200ABC

Bio Energy (Illinois) LLC

0001

1

097200ABC

Bio Energy (Illinois) LLC

0002

1

097200ABC

Bio Energy (Illinois) LLC

0003

1

097200ABC

Bio Energy (Illinois) LLC

0004

1

097200ABC

Bio Energy (Illinois) LLC

0005

1

097811AAC

Naval Training Center

0050

2

097811AAC

Naval Training Center

0095

5

097811AAC

Naval Training Center

0055

6

097811AAC

Naval Training Center

0097

2

097811AAC

Naval Training Center

0108

2

097811AAC

Naval Training Center

0107

2

097811AAC

Naval Training Center

0106

2

097811AAC

Naval Training Center

0049

1

111816AAA

ANR Pipeline Co

0010

1

111816AAA

ANR Pipeline Co

0022

1

111816AAA

ANR Pipeline Co

0024

1

111816AAA

ANR Pipeline Co

0025

1

111816AAA

ANR Pipeline Co

0030

1

111816AAA

ANR Pipeline Co

0029

1

163050AAD

Milam Recycling and Disposal Facility

0012

3

197800ABU

Trunkline Gas Co

0001

5

Total RICE

55

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

46

List of Impacted Turbines

Id Number

Plant Name

Emission

Point

No. of

Units

031003ADA

Alsip Paper Condominium Assn

0002

1

197817AAA

Natural Gas Pipeline Co of America

0016

9

197817AAA

Natural Gas Pipeline Co of America

0020

10

031600AMJ

Midwest Generation LLC

0003

11

031600GKE

Calumet Peaking Facility

0001

8

097200ABB

Zion Energy Center

0001

3

197800AAA

Exxon Mobil

0043

1

197808AAG

Elwood Energy Facility

0007

3

197899AAC

PPL University Park LLC

0001

1

197899AAC

PPL University Park LLC

0002

1

197899AAC

PPL University Park LLC

0003

1

197899AAC

PPL University Park LLC

0004

1

197899AAC

PPL University Park LLC

0005

1

197899AAC

PPL University Park LLC

0006

1

197899AAC

PPL University Park LLC

0007

1

197899AAC

PPL University Park LLC

0008

1

197899AAC

PPL University Park LLC

0009

1

197899AAC

PPL University Park LLC

0010

1

197899AAC

PPL University Park LLC

0011

1

197899AAC

PPL University Park LLC

0012

1

Total

Turbines

58

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

Agency Analysis of Economic and

Budgetary Effects of Proposed Rulemaking

Agency:

Illinois Pollution Control Board

Part/Title:

Permits And General Provisions (35 Ill. Adm. Code Part 201.146)

Illinois Register Citation: _______________________________

Please attempt to provide as dollar-specific responses as possible and feel free to add any relevant

explanation.

1.

Anticipated effect on State expenditures and revenues.

(a)

Current cost to the agency for this program/activity.

$0 per year

(approximately)

(b)

If this rulemaking will result in an increase or decrease in cost, specify the fiscal

year in which this change will first occur and the dollar amount of the effect.

2010, the annual cost increase of approx. $50,000 per year

(c)

Indicate the funding source, including Fund and appropriation lines, for this

program/activity.

Clean Air Act Permit Program Fund (CAAPP)

(d)

If an increase or decrease in the costs of another State agency is anticipated,

specify the fiscal year in which this change will first occur and the estimated

dollar amount of the effect.

N/A

(e)

Will this rulemaking have any effect on State revenues or expenditures not

already indicated above?

No

2.

Economic effect on persons affected by the rulemaking:

(a)

Indicate the economic effect and specify the persons affected:

Positive ___ Negative ____ No effect _

X

__

Persons affected: __owners and operators of certain stationary internal

combustion engines and turbines__ ____

Dollar amount per person: _

0

__

Total statewide cost: ___

0

__

_____

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

(b)

If an economic effect is predicted, please briefly describe how the effect will

occur. _

N/A

__ ____

(c)

Will the rulemaking have an indirect effect that may result in increased

administrative costs?

No

Will there be any change in requirements such

as filing, documentation, reporting or completion of forms?

The rulemaking should have no indirect effect that may result in increased

administrative costs.

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

Agency Analysis of Economic and

Budgetary Effects of Proposed Rulemaking

Agency:

Illinois Pollution Control Board

Part/Title:

Definitions and General Provisions (35 Ill. Adm. Code Part 211)

Illinois Register Citation: _______________________________

Please attempt to provide as dollar-specific responses as possible and feel free to add any relevant

explanation.

1.

Anticipated effect on State expenditures and revenues.

(a)

Current cost to the agency for this program/activity.

$ 0 per year

(approximately)

(b)

If this rulemaking will result in an increase or decrease in cost, specify the fiscal year in

which this change will first occur and the dollar amount of the effect.

N/A

(c)

Indicate the funding source, including Fund and appropriation lines, for this

program/activity.

N/A

(d)

If an increase or decrease in the costs of another State agency is anticipated, specify the

fiscal year in which this change will first occur and the estimated dollar amount of the

effect.

N/A

(e)

Will this rulemaking have any effect on State revenues or expenditures not already

indicated above?

No

2.

Economic effect on persons affected by the rulemaking:

(a)

Indicate the economic effect and specify the persons affected:

Positive ___ Negative ____ No effect

_ X

Persons affected: __Owners and operators of affected stationary internal combustion

engines and turbines

Dollar amount per person: __

0_

Total statewide cost: ____

0

(b)

If an economic effect is predicted, please briefly describe how the effect will occur.

N/A

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

(c)

Will the rulemaking have an indirect effect that may result in increased

administrative costs?

No

Will there be any change in requirements such as filing,

documentation, reporting or completion of forms?

No

The rulemaking should have no indirect effect that may result in increased

administrative costs.

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

Agency Analysis of Economic and

Budgetary Effects of Proposed Rulemaking

Agency:

Illinois Pollution Control Board

Part/Title:

Nitrogen Oxides Emissions (35 Ill. Adm. Code Part 217 )

Illinois Register Citation: _______________________________

Please attempt to provide as dollar-specific responses as possible and feel free to add any relevant

explanation.

1.

Anticipated effect on State expenditures and revenues.

(a)

Current cost to the agency for this program/activity.

$

0 per year

(approximately)

(b)

If this rulemaking will result in an increase or decrease in cost, specify the fiscal

year in which this change will first occur and the dollar amount of the effect.

2010, the annual cost increase of approx. $75,000 per year

(c)

Indicate the funding source, including Fund and appropriation lines, for this

program/activity.

Clean Air Act Permit Program Fund (CAAPP)

(d)

If an increase or decrease in the costs of another State agency is anticipated,

specify the fiscal year in which this change will first occur and the estimated

dollar amount of the effect.

n/a

(e)

Will this rulemaking have any effect on State revenues or expenditures not

already indicated above?

no

2.

Economic effect on persons affected by the rulemaking:

(a)

Indicate the economic effect and specify the persons affected:

Positive ___ Negative __

X

__ No effect _ __

Persons affected:

__owners and operators of affected stationary internal

combustion engines

Dollar amount per person:

_$314 to $3,005 average annual cost per ton of NOx

reduced__

Total statewide cost:

__$677,000 to $6,476,000_per year

Electronic Filing - Received, Clerk's Office, December 20, 2007

---

(b)

If an economic effect is predicted, please briefly describe how the effect will

occur.

_The cost to install and to maintain required air pollution control

equipment.

(c)

Will the rulemaking have an indirect effect that may result in increased

administrative costs? Will there be any change in requirements such as

filing, documentation, reporting or completion of forms?

The rulemaking should have no indirect effect that may result in increased

administrative costs

.

Electronic Filing - Received, Clerk's Office, December 20, 2007

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Wednesday,

April 25, 2007

Part II

Environmental

Protection Agency

40 CFR Part 51

Clean Air Fine Particle Implementation

Rule; Final Rule

Agency Information Collection Activities:

Proposed Collection; Comment Request;

PM

2.5

Ozone National Ambient Air Quality

Standard Implementation Rule; EPA ICR

No. 2258.01; Notice

Electronic Filing - Received, Clerk's Office, December 20, 2007

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20586

Federal Register

/ Vol. 72, No. 79 / Wednesday, April 25, 2007 / Rules and Regulations

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 51

[EPA–HQ–OAR–2003–0062; FRL–8295–2]

RIN 2060–AK74

Clean Air Fine Particle Implementation

Rule

AGENCY:

Environmental Protection

Agency (EPA).

ACTION:

Final rule.

SUMMARY:

This final action provides

rules and guidance on the Clean Air Act

(CAA) requirements for State and Tribal

plans to implement the 1997 fine

particle (PM

2.5

) national ambient air

quality standards (NAAQS). Fine

particles and precursor pollutants are

emitted by a wide range of sources,

including power plants, cars, trucks,

industrial sources, and other burning or

combustion-related activities. Health

effects that have been associated with

exposure to PM

2.5

include premature

death, aggravation of heart and lung

disease, and asthma attacks. Those

particularly sensitive to PM

2.5

exposure

include older adults, people with heart

and lung disease, and children.

Air quality designations became

effective on April 5, 2005 for 39 areas

(with a total population of 90 million)

that were not attaining the 1997 PM

2.5

standards. By April 5, 2008, each State

having a nonattainment area must

submit to EPA an attainment

demonstration and adopted regulations

ensuring that the area will attain the

standards as expeditiously as

practicable, but no later than 2015. This

rule and preamble describe the

requirements that States and Tribes

must meet in their implementation

plans for attainment of the 1997 fine

particle NAAQS. (Note that this rule

does not include final PM

2.5

requirements for the new source review

(NSR) program; the final NSR rule will

be issued at a later date.)

DATES:

This rule is effective on May 29,

2007.

ADDRESSES:

The EPA has established a

docket for this action under Docket ID

EPA–HQ–OAR–2003–0062. All

documents relevant to this action are

listed in the Federal docket management

system at

www.regulations.gov

.

Although listed in the index, some

information is not publicly available

(e.g. Confidential Business Information

or other information whose disclosure is

restricted by statute). Certain other

material, such as copyrighted material,

is not placed on the Internet and will be

publicly available only in hard copy

form. Publicly available docket

materials are available either

electronically through

www.regulations.gov or in hard copy

format at the EPA Docket Center, EPA/

DC, EPA West, Room 3334, 1301

Constitution Avenue, NW., Washington,

DC. The Public Reading Room is open

from 8:30 a.m. to 4:30 p.m., Monday

through Friday, excluding legal

holidays. The telephone number for the

Public Reading Room is (202) 566–1744,

and the telephone number for the Office

of Air and Radiation Docket and

Information Center is (202) 566–1742. A

variety of information and materials

related to the fine particle NAAQS and

implementation program are also

available on EPA’s Web site:

http://

www.epa.gov/air/particles

.

FOR FURTHER INFORMATION CONTACT:

For

general information, contact Mr.

Richard Damberg, U.S. Environmental

Protection Agency, Office of Air Quality

Planning and Standards, Mail Code

C539–01, Research Triangle Park, NC

27711, phone number (919) 54l–5592 or

by e-mail at:

damberg.rich@epa.gov

.

SUPPLEMENTARY INFORMATION:

General Information

A. Does this action apply to me?

Entities potentially regulated by this

action are State and local air quality

agencies.

B. Where can I get a copy of this

document and other related

information?

In addition to being available in the

docket, an electronic copy of this final

rule will also be available on the World

Wide Web. Following signature by the

EPA Administrator, a copy of this final

rule will be posted at

http://

www.epa.gov/particles/actions.html

.

C. How is the preamble organized?

I. Background

II. Elements of the Clean Air Fine Particle

Implementation Rule

A. Precursors and Pollutants Contributing

to Fine Particle Formation

B. No Classification System

C. Due Dates and Basic Requirements for

Attainment Demonstrations

D. Attainment Dates

E. Modeling and Attainment

Demonstrations

F. Reasonably Available Control

Technology and Reasonably Available

Control Measures

G. Reasonable Further Progress

H. Contingency Measures

I. Transportation Conformity

J. General Conformity

K. Emission Inventory Requirements

L. Condensable Particulate Matter Test

Methods and Related Data Issues

M. Improving Source Monitoring

N. Guidance Specific to Tribes

O. Enforcement and Compliance

P. Emergency Episodes

Q. Ambient Monitoring

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory

Planning and Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation

and Coordination With Indian Tribal

Governments

G. Executive Order 13045: Protection of

Children From Environmental Health

and Safety Risks

H. Executive Order 13211: Actions That

Significantly Affect Energy Supply,

Distribution, or Use

I. National Technology Transfer

Advancement Act

J. Executive Order 12898: Federal Actions

To Address Environmental Justice in

Minority Populations and Low-Income

Populations

K. Congressional Review Act

L. Petitions for Judicial Review

M. Judicial Review

IV. Statutory Authority

I. Background

Fine particles in the atmosphere are

comprised of a complex mixture of

components. Common constituents

include: sulfate (SO

4

); nitrate (NO

3

);

ammonium; elemental carbon; a great

variety of organic compounds; and

inorganic material (including metals,

dust, sea salt, and other trace elements)

generally referred to as ‘‘crustal’’

material, although it may contain

material from other sources. Airborne

particles generally less than or equal to

2.5 micrometers in diameter are

considered to be ‘‘fine particles’’ (also

referred to as PM

2.5

). (A micrometer is

one-millionth of a meter, and 2.5

micrometers is less than one-seventh the

average width of a human hair.)

‘‘Primary’’ particles are emitted directly

into the air as a solid or liquid particle

(e.g., elemental carbon from diesel

engines or fire activities, or condensable

organic particles from gasoline engines).

‘‘Secondary’’ particles (e.g., sulfate and

nitrate) form in the atmosphere as a

result of various chemical reactions.

(Section II of the proposed rule included

detailed technical discussion on PM

2.5

,

its precursors, formation processes, and

emissions sources.)

The EPA established air quality

standards for PM

2.5

based on evidence

from numerous health studies

demonstrating that serious health effects

are associated with exposures to

elevated levels of PM

2.5

.

Epidemiological studies have shown

statistically significant correlations

between elevated PM

2.5

levels and

premature mortality. Other important

Electronic Filing - Received, Clerk's Office, December 20, 2007

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Federal Register

/ Vol. 72, No. 79 / Wednesday, April 25, 2007 / Rules and Regulations

20587

effects associated with PM

2.5

exposure

include aggravation of respiratory and

cardiovascular disease (as indicated by

increased hospital admissions,

emergency room visits, absences from

school or work, and restricted activity

days), changes in lung function and

increased respiratory symptoms, as well

as new evidence for more subtle

indicators of cardiovascular health.

Individuals particularly sensitive to

PM

2.5

exposure include older adults,

people with heart and lung disease, and

children.

On July 18, 1997, we revised the

NAAQS for particulate matter (PM) to

add new standards for fine particles,

using PM

2.5

as the indicator. We

established health-based (primary)

annual and 24-hour standards for PM

2.5

(62 FR 38652).

1

The annual standard

was set at a level of 15 micrograms per

cubic meter, as determined by the 3-year

average of annual mean PM

2.5

concentrations. The 24-hour standard

was set at a level of 65 micrograms per

cubic meter, as determined by the 3-year

average of the 98th percentile of 24-hour

concentrations.

Attainment of the 1997 PM

2.5

standards is estimated to lead to

reductions in health impacts, including

tens of thousands fewer premature

deaths each year, thousands fewer

hospital admissions and emergency

room visits each year, hundreds of

thousands fewer absences from work

and school, and hundreds of thousands

fewer respiratory illnesses in children

annually. The EPA’s evaluation of the

science concluded that there was not

sufficient information to either support

or refute the existence of a threshold for

health effects from PM exposure.

2

We subsequently completed in

October 2006 another review of the

NAAQS for PM. With regard to the

primary standards, the 24-hour PM

2.5

standard was strengthened to a level of

35 micrograms per cubic meter, based

on the 3-year average of the 98th

percentile of 24-hour concentrations,

1

The original annual and daily standards for

particles generally less than or equal to 10

micrometers in diameter (also referred to as PM

10

)

were established in 1987. In the 1997 PM NAAQS

revision, EPA also revised the standards for PM

10

,

but these revised PM

10

standards were later vacated

by the court, and the 1987 PM

10

standards remained

in effect. In the 2006 NAAQS revision, the 24-hour

PM

10

standard was retained but the annual standard

was revoked. Today’s implementation rule and

guidance does not address PM

10

.

2

Environmental Protection Agency. (2004a). Air

Quality Criteria for Particulate Matter. Research

Triangle Park, NC: National Center for

Environmental Assessment—RTP, Office of

Research and Development, U.S. Environmental

Protection Agency, Research Triangle Park, NC

27711; report no. EPA/600/P–99/002aF and EPA/

600/P–99/002bF. October 2004.

and the level of the annual standard

remained unchanged.

3

Attainment of

the 2006 PM

2.5

standards is estimated to

lead to additional reductions in health

impacts, including approximately 1,200

to 13,000 fewer premature deaths each

year, 1,630 fewer hospital admissions

and 1,200 fewer emergency room visits

for asthma each year, 350,000 fewer

absences from work and school, and

155,300 fewer respiratory illnesses in

children annually.

4

In both 1997 and 2006 EPA

established welfare-based (secondary)

standards identical to the levels of the

primary standards. The secondary

standards are designed to protect against

major environmental effects of PM

2.5

such as visibility impairment, soiling,

and materials damage. The EPA also

established the regional haze regulations

in 1999 for the improvement of visual

air quality in national parks and

wilderness areas across the country.

Because regional haze is caused

primarily by light scattering and light

absorption by fine particles in the

atmosphere, EPA is encouraging the

States to integrate their efforts to attain

the PM

2.5

standards with those efforts to

establish reasonable progress goals and

associated emission reduction strategies

for the purposes of improving air quality

in our treasured natural areas under the

regional haze program.

The scientific assessments used in the

development of the PM

2.5

standards

included a scientific peer review and

public comment process. We developed

scientific background documents based

on the review of hundreds of peer-

reviewed scientific studies. The Clean

Air Scientific Advisory Committee, a

congressionally mandated group of

independent scientific and technical

experts, provided extensive review of

these assessments, and found that EPA’s

review of the science provided an

adequate basis for the EPA

Administrator to make a decision. More

detailed information on health effects of

PM

2.5

can be found on EPA’s Web site

at:

http://www.epa.gov/air/urbanair/

pm/index.html

. Additional information

on EPA’s scientific assessment

documents supporting the 1997

standards are available at

http://

www.epa.gov/ttn/oarpg/t1cd.html

;

additional scientific assessment

3

The revised fine particle NAAQS were

published on October 17, 2006 (71 FR 61144). See

EPA’s Web site for additional information:

http://

www.epa.gov/pm/index.html

.

4

Regulatory Impact Analysis for Particulate

Matter National Ambient Air Quality Standards

(September 2006), page ES–8. The mortality range

includes estimates based on the results of an expert

elicitation study, along with published

epidemiological studies.

information on the 2006 standards is

available at:

http://www.epa.gov/ttn/

naaqs/standards/pm/s

_

pm

_

cr

_

cd.html.

The EPA issued final PM

2.5

designations for areas violating the 1997

standards on December 17, 2004. They

were published in the

Federal Register

on January 5, 2005 (70 FR 944). On

April 5, 2005, EPA issued a

supplemental notice which changed the

designation status of eight areas from

nonattainment to attainment based on

newly updated 2002–2004 air quality

data (70 FR 19844; published in the

Federal Register

on April 14, 2005). A

total of 39 areas were designated as

nonattainment for the 1997 PM

2.5

standards. The population of these areas

is estimated at about 90 million (or more

than 30% of the U.S. population). Most

of these areas only violate the annual

standard, but a few violate both the

annual and 24-hour standards.

The nonattainment designation for an

area starts the process whereby a State

or Tribe must develop an

implementation plan that includes,

among other things, a demonstration

showing how it will attain the ambient

standards by the attainment dates

required in the CAA. Under section

172(b), States have up to 3 years after

EPA’s final designations to submit their

SIPs to EPA. These SIPs will be due on

April 5, 2008, 3 years from the effective

date of the designations.

Section 172(a)(2) of the Act requires

States to attain the standards as

expeditiously as practicable but within

5 years of designation (i.e. attainment

date of April 2010 based on air quality

data for 2007–2009), or within up to 10

years of designation (i.e. to April 2015)

if the EPA Administrator extends an

area’s attainment date by 1–5 years

based upon the severity of the

nonattainment problem or the feasibility

of implementing control measures.

Virtually all nonattainment problems

appear to result from a combination of

local emissions and transported

emissions from upwind areas. The

structure of the CAA requires EPA to

develop national rules for certain types

of sources which are also significant

contributors to local air quality

problems, including motor vehicles and

fuels. It also provides for States to

address emissions sources on an area-

specific basis through such

requirements as RACT, RACM, and RFP.

We believe that to attain the PM

2.5

standards, it is important to pursue

emissions reductions simultaneously on

the local, regional, and national levels.

The EPA issued the Clean Air Interstate

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Rule (CAIR)

5

on March 10, 2005 to

address the interstate transport of sulfur

dioxide and nitrogen oxide emissions

primarily from power plants. Section

110 gives EPA the authority to require

SIPs to ‘‘prohibit * * * any source or

other type of emission activity within

the State from emitting any air pollutant

in amounts which will contribute

significantly to nonattainment in, or

interfere with maintenance by, any

other State with respect to’’ any

NAAQS, and to prohibit sources or

emission activities from emitting

pollutants in amounts which will

interfere with measures required to be

included in State plans to prevent

significant deterioration of air quality or

to protect visibility (such as the

protection of 156 mandatory Federal

class I areas under the regional haze

rule

6

). CAIR employs the same

emissions trading approach used to

achieve cost-effective emission

reductions under the acid rain program.

It outlines a two-phase program with

increasingly tighter power plant

emissions caps for 28 eastern states and

the District of Columbia: SO

2

caps of 3.6

million tons in 2010, and 2.5 million in

2015; NO

X

caps of 1.5 in 2009 and 1.3

in 2015; and NO

X

ozone season caps of

580,000 tons in 2009 and 480,000 tons

in 2015. Emission caps are divided into

State SO

2

and NO

X

budgets. By the year

2015, the Clean Air Interstate Rule is

estimated to result in:

—$85 to $100 billion in annual health

benefits, including preventing 17,000

premature deaths, millions of lost

work and school days, and tens of

thousands of non-fatal heart attacks

and hospital admissions annually.

—Nearly $2 billion in annual visibility

benefits in southeastern national

parks, such as Great Smoky and

Shenandoah.

—Significant regional reductions in

sulfur and nitrogen deposition,

reducing the number of acidic lakes

and streams in the eastern U.S.

Over the past several years, EPA has

also issued a number of regulations

addressing emissions standards for new

cars, trucks and buses. These standards

are providing reductions in motor

vehicle emissions of volatile organic

compounds (VOCs, also referred to as

hydrocarbons), NO

X

, and direct PM

emissions (such as elemental carbon) as

older vehicles are retired and replaced.

Other existing rules are designed to

reduce emissions from several

categories of nonroad engines. The Tier

2 motor vehicle emission standards,

5

See

http://www.epa.gov/cair

.

6

See 64 FR 35714, July 1, 1999.

together with the associated

requirements to reduce sulfur in

gasoline, are estimated to provide

additional benefits nationally beginning

in 2004.

7

When the new tailpipe and

sulfur standards are fully implemented,

Americans are estimated to benefit from

the clean-air equivalent of removing 164

million cars from the road. These new

standards require passenger vehicles to

have emissions 77 to 95 percent cleaner

than those on the road today and require

fuel manufacturers to reduce the sulfur

content of gasoline by up to 90 percent.

In addition, the 2001 heavy-duty diesel

engine regulations

8

will lead to

continued emissions reductions as older

vehicles in that engine class are retired

and fleets turn over. New emission

standards began to take effect for model

year 2007 and apply to heavy-duty

highway engines and vehicles. These

standards are based on the use of high-

efficiency catalytic exhaust emission

control devices or comparably effective

advanced technologies. Because these

devices are damaged by sulfur, the level

of sulfur in highway diesel fuel was to

be reduced by 97 percent by mid-2006.

We project a 2.6 million ton reduction

of NO

X

emissions in 2030 when the

current heavy-duty vehicle fleet is

completely replaced with newer heavy-

duty vehicles that comply with these

emission standards. By 2030, we

estimate that this program will reduce

annual emissions of hydrocarbons by

115,000 tons and PM by 109,000 tons.

These emissions reductions are on par

with those that we anticipate from new

passenger vehicles and low sulfur

gasoline under the Tier 2 program.

The EPA also finalized national rules

in May 2004 to reduce significantly

PM

2.5

and NO

X

emissions from nonroad

diesel-powered equipment.

9

These

nonroad sources include construction,

agricultural, and industrial equipment,

and their emissions constitute an

important fraction of the inventory for

direct PM

2.5

emissions (such as

elemental carbon and organic carbon),

and NO

X

. The EPA estimates that

affected nonroad diesel engines

currently account for about 44 percent

of total diesel PM emissions and about

12 percent of total NO

X

emissions from

mobile sources nationwide. These

proportions are even higher in some

urban areas. The diesel emission

standards will reduce emissions from

this category by more than 90 percent,

7

See Tier II emission standards at 65 FR 6698,

February 10, 2000.

8

See heavy-duty diesel engine regulations at 66

FR 5002, January 18, 2001.

9

For more information on the proposed nonroad

diesel engine standards, see EPA’s Web site:

http://www.epa.gov/nonroad/.

and are similar to the onroad engine

requirements implemented for highway

trucks and buses. Because the emission

control devices can be damaged by

sulfur, EPA also established

requirements to reduce the allowable

level of sulfur in nonroad diesel fuel by

more than 99 percent by 2010. In 2030,

when the full inventory of older

nonroad engines has been replaced, the

nonroad diesel program will annually

prevent up to 12,000 premature deaths,

one million lost work days, 15,000 heart

attacks and 6,000 children’s asthma-

related emergency room visits.

The EPA expects the implementation

of regional and national emission

reduction programs such as CAIR and

the suite of mobile source rules

described above to provide significant

air quality improvements for PM

2.5

nonattainment areas. At the same time,

analyses for the final CAIR rule indicate

that without implementation of local

measures, a number of PM

2.5

areas are

projected to remain in nonattainment

status in the 2010–2015 timeframe.

Thus, EPA believes that local and State

emission reduction efforts will need to

play an important role in addressing the

PM

2.5

problem as well. The EPA will

work closely with States, Tribes, and

local governments to develop

appropriate in-state pollution reduction

measures to complement regional and

national strategies to meet the standards

expeditiously and in a cost-effective

manner. States will need to evaluate

technically and economically feasible

emission reduction opportunities and

determine which measures can be

reasonably implemented in the near

term. Local and regional emission

reduction efforts should proceed

concurrently and expeditiously.

The promulgation of a revised 24-

hour PM

2.5

standard effective on

December 18, 2006 has initiated another

process of State recommendations, and

the eventual designation by EPA of

areas not attaining the revised standard.

The additional designations are to be

completed within two years from the

effective date, although EPA may take

an additional year to complete the

designations if it determines it does not

have sufficient information. State plans

to attain the 24-hour standard would

then be due within three years of the

final designations. A number of areas,

including some that are already

designated as not attaining the 1997

standards, may be exceeding the revised

24-hour standard. The EPA encourages

State and local governments to be

mindful of the strengthened 24-hour

standard as they adopt emission

reduction strategies to attain the 1997

standards. Such steps may help with

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20589

future attainment efforts, or even help

some areas avoid a nonattainment

designation for the 24-hour standard in

the first place.

The public health benefits of meeting

the PM

2.5

standards are estimated to be

significant. Even small reductions in

PM

2.5

levels may have substantial health

benefits on a population level. For

example, in a moderate-sized

metropolitan area with a design value of

15.5

µ

g/m3, efforts to improve annual

average air quality down to the level of

the standard (15.0

µ

g/m3) are estimated

to result in as many as 25–50 fewer

mortalities per year due to air pollution

exposure. In a smaller city, the same air

quality improvement from 15.5 to 15.0

µ

g/m3 still are estimated to result in a

number of avoided mortalities per year.

These estimates are based on EPA’s

standard methodology for calculating

health benefits as used in recent

rulemakings.

10

In addition, because

many different precursors contribute to

the formation of fine particles,

reductions in pollutants that contribute

to PM

2.5

also can provide concurrent

benefits in addressing a number of other

air quality problems—such as ground-

level ozone, regional haze, toxic air

pollutants, and urban visibility

impairment.

In order to assist States in developing

effective plans to address the local

component of the PM

2.5

nonattainment

problem, EPA is issuing this final fine

particle implementation rule. The EPA

is issuing this rule to implement the

1997 PM

2.5

NAAQS in accordance with

the statutory requirements of the CAA

set forth in Subpart 1 of Part D of Title

1,

i.e.

, sections 171–179B of the Act.

The EPA believes that the CAA directs

the Agency to implement new or revised

NAAQS in nonattainment areas solely

in accordance with Subpart 1, unless

another Subpart of the Act also applies

to the particular NAAQS at issue. In this

case, EPA has concluded that Congress

did not intend the Agency to implement

particulate matter NAAQS other than

those using PM

10

as the indicator in

accordance with Subpart 4 of Part D of

Title 1,

i.e.

, sections 188–190 of the

CAA. Moreover, EPA believes that

implementation of the PM

2.5

NAAQS

under the provisions of Subpart 1 is

more appropriate, given the inherent

nature of the PM

2.5

nonattainment

problem. In contrast to PM

10

, EPA

10

See: U.S. EPA 2006. Regulatory Impact

Analysis for the Particulate Matter National

Ambient Air Quality Standards. Air Benefits and

Cost Group, Office of Air Quality Planning and

Standards, Research Triangle Park, N.C. October 6,

2006. Appendix A provides an analysis of estimated

benefits and costs of attaining the 1997 PM NAAQS

standards in 2015.

anticipates that achieving the NAAQS

for PM

2.5

will generally require States to

evaluate different sources for controls,

to consider controls of one or more

precursors in addition to direct PM

emissions, and to adopt different control

strategies. As a result, EPA has

concluded that the provisions of

Subpart 1 will allow States and EPA to

tailor attainment plans so that they can

be based more specifically upon the

facts and circumstances of each

nonattainment area.

The proposed clean air fine particle

implementation rule was issued on

November 1, 2005 (70 FR 65984). About

100 comments were received from

private citizens and parties representing

industry, state and local governments,

environmental groups, and federal

agencies. Section II of this document

describes the primary elements of the

fine particle implementation program.

Each section summarizes the relevant

policies and options discussed in the

proposed rule, discusses the final policy

set forth by EPA in the final rule, and

provides responses to the major

comments received on each issue.

II. Elements of the Clean Air Fine

Particle Implementation Rule

A. Precursors and Pollutants

Contributing to Fine Particle Formation

1. Introduction

The main precursor gases associated

with fine particle formation are SO

2

,

NO

X

, volatile organic compounds

(VOC), and ammonia. This section

provides technical background on each

precursor, discusses the policy

approach for addressing each precursor

under the PM

2.5

implementation

program, and responds to key issues

raised in the public comment process. A

subsection is also included on direct

PM

2.5

emissions to address key

comments received on this issue as

well.

Gas-phase precursors SO

2

, NO

X

, VOC,

and ammonia undergo chemical

reactions in the atmosphere to form

secondary particulate matter. Formation

of secondary PM depends on numerous

factors including the concentrations of

precursors; the concentrations of other

gaseous reactive species; atmospheric

conditions including solar radiation,

temperature, and relative humidity

(RH); and the interactions of precursors

with preexisting particles and with

cloud or fog droplets. Several

atmospheric aerosol species, such as

ammonium nitrate and certain organic

compounds, are semivolatile and are

found in both gas and particle phases.

Given the complexity of PM formation

processes, new information from the

scientific community continues to

emerge to improve our understanding of

the relationship between sources of PM

precursors and secondary particle

formation.

As an initial matter, it is helpful to

clarify the terminology we use

throughout this notice to discuss

precursors. We recognize NO

X

, SO

2

,

VOCs, and ammonia as precursors of

PM

2.5

in the scientific sense because

these pollutants can contribute to the

formation of PM

2.5

in the ambient air. In

section II.K on emission inventory

issues, we make the point that because

of the complex and variable interaction

of multiple pollutants and precursors in

the formation of fine particles, it is

important for States and EPA to

continue to characterize and improve

the emissions inventories for all PM

2.5

precursors. The States and EPA need to

use the best available information

available in conducting air quality

modeling and other assessments. At the

same time, the refinement of emissions

inventories, the overall contribution of

different fine particle precursors to

PM

2.5

formation, and the efficacy of

alternative potential control measures

will vary by location. This requires that

we further consider in this action how

States should address these PM

2.5

precursors in their PM

2.5

attainment

plan programs. Thus, we require

emission inventories to include the best

available information on all pollutants

and precursors that contribute to PM

2.5

concentrations, and at same time we use

the term ‘‘PM

2.5

attainment plan

precursor’’ to describe only those

precursors that are required to be

evaluated for control strategies in a

specific PM

2.5

nonattainment area or

maintenance area plan.

In this rule, EPA has not made a

finding that all precursors should be

evaluated for possible controls in each

specific nonattainment area. The policy

approach in the rule instead requires

sulfur dioxide to be evaluated for

control measures in all areas, and

describes general presumptive policies

for NO

X

, ammonia, and VOC for all

nonattainment areas. The rule provides

a mechanism by which the State and/or

EPA can make an area-specific

demonstration to reverse the general

presumption for these three precursors.

States must also consider any relevant

information brought forward by

interested parties in the SIP planning

and development process. (See section

II.A.8 for additional discussion on these

issues.)

In the following sections, we discuss

how States must evaluate PM

2.5

precursors for nonattainment program

issues in PM

2.5

implementation plans,

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including issues such as RACT, RACM,

and reasonable further progress. This

discussion in the final rule is linked to

precursor policies for the

implementation of the new source

review program, the transportation

conformity program, the general

conformity program, and the regional

haze program. All of these programs

take effect prior to approval of SIPs for

attaining the PM

2.5

NAAQS. In the case

of NSR, the program applies on the

effective date of the nonattainment area

designation. In the case of

transportation conformity and general

conformity, the program takes effect 1

year from the effective date of

designation of the nonattainment area

(i.e., April 5, 2006 for areas designated

nonattainment effective April 5, 2005).

Thus, for each of these programs there

is an interim period between the date

the program becomes applicable to a

given nonattainment area and the date

the State receives EPA approval of its

overall PM

2.5

implementation plan.

2. Legal Authority to Regulate

Precursors

a. Background

The CAA authorizes the Agency to

regulate criteria pollutant precursors.

The term ‘‘air pollutant’’ is defined in

section 302(g) to include ‘‘any

precursors to the formation of any air

pollutant, to the extent the

Administrator has identified such

precursor or precursors for the

particular purpose for which the term

‘air pollutant’ is used.’’ The first clause

of this second sentence in section 302(g)

explicitly authorizes the Administrator

to identify and regulate precursors as air

pollutants under other parts of the CAA.

In addition, the second clause of the

sentence indicates that the

Administrator has discretion to identify

which pollutants should be classified as

precursors for particular regulatory

purposes. Thus, we do not necessarily

construe the CAA to require that EPA

identify a particular precursor as an air

pollutant for all regulatory purposes

where it can be demonstrated that

various CAA programs address different

aspects of the air pollutant problem.

Likewise, we do not interpret the CAA

to require that EPA treat all precursors

of a particular pollutant the same under

any one program when there is a basis

to distinguish between such precursors.

For example, in a rule addressing PM

2.5

precursors for purposes of the

transportation conformity program, we

chose to adopt a different approach for

one precursor based on the limited

emissions of that precursor from onroad

mobile sources and the degree to which

it contributes to PM

2.5

concentrations.

(70 FR 24280; May 6, 2005).

Other provisions of the CAA reinforce

our reading of section 302(g) that

Congress intended precursors to

NAAQS pollutants to be subject to the

air quality planning and control

requirements of the CAA, but also

recognized that there may be

circumstances where it is not

appropriate to subject precursors to

certain requirements of the CAA.

Section 182 of the CAA provides for the

regulation of NO

X

and VOCs as

precursors to ozone in ozone

nonattainment areas, but also provides

in section 182(f) that major stationary

sources of NO

X

(an ozone precursor) are

not subject to emission reductions

controls for ozone where the State

shows through modeling that NO

X

reductions do not decrease ozone.

Section 189(e) provides for the

regulation of PM

10

precursors in PM

10

nonattainment areas, but also recognizes

that there may be certain circumstances

(e.g. if precursor emission sources do

not significantly contribute to PM

10

levels) where it is not appropriate to

apply control requirements to PM

10

precursors. The legislative history of

Section 189(e) recognized the

complexity behind the science of

precursor transformation into PM

10

ambient concentrations and the need to

harmonize the regulation of PM

10

precursors with other provisions of the

CAA:

The Committee notes that some of these

precursors may well be controlled under

other provisions of the CAA. The Committee

intends that * * * the Administrator will

develop models, mechanisms, and other

methodology to assess the significance of the

PM

10

precursors in improving air quality and

reducing PM

10

. Additionally, the

Administrator should consider the impact on

ozone levels of PM

10

precursor controls. The

Committee expects the Administrator to

harmonize the PM

10

reduction objective of

this section with other applicable regulations

of this CAA regarding PM

10

precursors, such

as NO

X

. See H. Rpt. 101–490, Pt. 1, at 268

(May 17, 1990), reprinted in S. Prt. 103–38,

Vol. II, at 3292.

In summary, section 302(g) of the

CAA clearly calls for the regulation of

precursor pollutants, but the CAA also

identifies circumstances when it may

not be appropriate to regulate precursors

and gives the Administrator discretion

to determine how to address particular

precursors under various programs

required by the CAA. Due to the

complexities associated with precursor

emissions and their variability from

location to location, we believe that in

certain situations it may not be effective

or appropriate to control a certain

precursor under a particular regulatory

program or for EPA to require similar

control of a particular precursor in all

areas of the country.

b. Final Rule

The final rule maintains the same

legal basis for regulating precursors as

was described in the proposal and in the

background section above. We also

include a clarification of the term

‘‘significant contributor.’’

In the proposal, when considering the

impacts of the precursors NO

X

, VOC

and ammonia on ambient

concentrations of particulate matter, we

referred to the possibility of reversing

the presumed approach for regulating or

not regulating a precursor if it can be

shown that the precursor in question is

or is not a ‘‘significant contributor’’ to

PM

2.5

concentrations within the specific

nonattainment area. ‘‘Significant

contribution’’ in this context is a

different concept than that in Section

110(a)(2)(D). Section 110(a)(2)(D)

prohibits States from emitting air

pollutants in amounts which

significantly contribute to

nonattainment or other air quality

problems in other states. Consistent

with the discussion of sections 189(e)

and 302(g) above, we are clarifying that

the use in this implementation rule of

the term ‘‘significant contribution’’ to

the nonattainment area’s PM

2.5

concentration means that a significant

change in emissions of the precursor

from sources in the state would be

projected to provide a significant change

in PM

2.5

concentrations in the

nonattainment area. For example, if

modeling indicates that a reduction in a

state’s NO

X

emissions would reduce

ambient PM

2.5

levels in the

nonattainment area, but that a reduction

in ammonia emissions would result in

virtually no change in ambient PM

2.5

levels, this would suggest that NO

X

is a

significant contributor but that ammonia

is not. The EPA in this rule is not

establishing a quantitative test for

determining whether PM

2.5

levels in a

nonattainment area change significantly

in response to reductions in precursor

emissions in a state. However, in

considering this question, it is relevant

to consider that relatively small

reductions in PM

2.5

levels are estimated

to result in worthwhile public health

benefits.

This approach to identifying a

precursor for regulation reflects

atmospheric chemistry conditions in the

area and the magnitude of emissions of

the precursor in the area or State.

Assessments of which source categories

are more cost effective or technically

feasible to control should be part of the

later RACT and RACM assessment, to

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occur after the basic assessment of

which precursors are to be regulated is

completed.

In the proposed regulatory text, the

provisions for reversing presumptions

for NO

X

, VOC and ammonia included

consideration of whether the precursor

would significantly contribute to ‘‘other

downwind air quality concerns.’’ In the

final rule we have removed that

language to clarify that identification of

attainment plan precursors involves

evaluation of the impact on PM

2.5

levels

in a nonattainment area of precursor

emissions from sources within the

state(s) where the nonattainment area is

located. Other parts of the Act, notably

section 110(a)(2)(D) and section 126,

focus on interstate transport of

pollutants.

c. Comments and Responses

Comment:

The EPA received several

comments supporting EPA’s

interpretation of 302(g) to determine the

appropriate regulatory status of each

precursor pollutant.

Response:

The EPA agrees with the

commenters. In establishing section

302(g), Congress intended that

precursors to NAAQS pollutants be

subject to the air quality planning and

control requirements of the CAA.

However, the CAA also recognizes that

there may be circumstances where it is

not appropriate to subject precursors to

certain requirements of the CAA.

Comment:

The EPA received several

comments regarding the applicability of

section 189(e), noting that it requires

states to presumptively control sources

of PM

10

precursors except where the

EPA ‘‘determines that such sources [of

precursors] do not significantly

contribute to PM

10

levels which exceed

the standard in the area.’’ Several

commenters stated that EPA does not

have the legal authority to regulate

PM

2.5

precursors in a different manner.

Several commenters maintained that all

PM

2.5

precursors presumptively should

be subject to regulation unless

demonstrated by the State as not a

significant contributor to PM

2.5

concentrations in a specific area.

Response:

As stated above, EPA

believes that section 302(g) allows the

Administrator to presumptively not

require certain precursors to be

addressed in PM

2.5

implementation

plans generally, while allowing the

State or EPA to make a finding for a

specific area to override the general

presumption. In the following pollutant-

specific sections of this preamble, EPA

finds that at this time there is sufficient

uncertainty regarding whether certain

precursors significantly contribute to

PM

2.5

concentrations in all

nonattainment areas such that the

policy set forth in this rule does not

presumptively require certain

precursors (ammonia, VOC) to be

controlled in each area. However, the

State or EPA may reverse the

presumption and regulate a precursor if

it provides a demonstration showing

that the precursor is a significant

contributor to PM

2.5

concentrations in

the area. In addition, if in the State’s SIP

planning and adoption process a

commenter provides additional

information suggesting an alternative

policy for regulating a particular

precursor, the State will need to

respond to this information in its

rulemaking action.

3. Policy for Ammonia

[Section II.E.2 of November 1, 2005

proposed rule (70 FR 65999); sec.

51.1002 in draft and final regulatory

text.]

a. Background

Ammonia (NH

3

) is a gaseous pollutant

that is emitted by natural and

anthropogenic sources. Emissions

inventories for ammonia are considered

to be among the most uncertain of any

species related to PM. Ammonia serves

an important role in neutralizing acids

in clouds, precipitation and particles. In

particular, ammonia neutralizes sulfuric

acid and nitric acid, the two key

contributors to acid deposition (acid

rain). Deposited ammonia also can

contribute to problems of eutrophication

in water bodies, and deposition of

ammonium particles may effectively

result in acidification of soil as

ammonia is taken up by plants. The

NARSTO Fine Particle Assessment

11

indicates that reducing ammonia

emissions where sulfate concentrations

are high may reduce PM

2.5

mass

concentrations, but may also increase

the acidity of particles and

precipitation. An increase in particle

acidity is suspected to be linked with

human health effects and with an

increase in the formation of secondary

organic compounds. Based on the above

information and further insights gained

from the NARSTO Fine Particle

Assessment, it is apparent that the

formation of particles related to

ammonia emissions is a complex,

nonlinear process.

Though recent studies have improved

our understanding of the role of

ammonia in aerosol formation, ongoing

research is required to better describe

11

NARSTO (2004) (

Particulate Matter

Assessment for Policy Makers:

A NARSTO

Assessment. P. McMurry, M. Shepherd, and J.

Vickery, eds. Cambridge University Press,

Cambridge, England. ISBN 0 52 184287 5.

the relationships between ammonia

emissions, particulate matter

concentrations, and related impacts.

The control techniques for ammonia

and the analytical tools to quantify the

impacts of reducing ammonia emissions

on atmospheric aerosol formation are

both evolving. Also, area-specific data

are needed to evaluate the effectiveness

of reducing ammonia emissions on

reducing PM

2.5

concentrations in

different areas, and to determine where

ammonia decreases may increase the

acidity of particles and precipitation.

The proposal showed consideration

for the uncertainties about ammonia

emissions inventories and about the

potential efficacy of ammonia control

measures by providing for a case-by-

case approach. It was recommended that

each State should evaluate whether

reducing ammonia emissions would

lead to PM

2.5

reductions in their specific

PM

2.5

nonattainment areas. The

proposed policy did not require States

to address ammonia as a PM

2.5

attainment plan precursor, unless a

technical demonstration by the State or

EPA showed that ammonia emissions

from sources in the State significantly

contribute to PM

2.5

concentrations in a

given nonattainment area or to other

downwind air quality concerns. Where

the State or EPA has determined that

ammonia is a significant contributor to

PM

2.5

formation in a nonattainment

area, the State would be required to

evaluate control measures for ammonia

emissions in its nonattainment SIP due

in 2008, in the implementation of the

PM program, and in other associated

programs in that area.

b. Final Rule

In the final rule, ammonia is

presumed not to be a PM

2.5

attainment

plan precursor, meaning that the State is

not required to address ammonia in its

attainment plan or evaluate sources of

ammonia emissions for reduction

measures. This presumption can be

reversed based on an acceptable

technical demonstration for a particular

area by the State or EPA. If a technical

demonstration by the State or EPA

shows that ammonia emissions from

sources in the State significantly

contribute to PM

2.5

concentrations in a

given nonattainment area, the State

must then evaluate and consider control

strategies for reducing ammonia

emissions in its nonattainment SIP due

in 2008, in the implementation of the

PM

2.5

program. Technical

demonstrations on ammonia should also

consider the potential for atmospheric

and particle acidity to increase with

ammonia reductions. Further discussion

about technical demonstrations to

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support reversing a PM

2.5

precursor

presumption is included in section

II.A.8 below.

This approach was retained from the

proposal because of continued

uncertainties regarding ammonia

emission inventories and the effects of

ammonia emission reductions.

Ammonia emission inventories are

presently very uncertain in most areas,

complicating the task of assessing

potential impacts of ammonia emissions

reductions. In addition, data necessary

to understand the atmospheric

composition and balance of ammonia

and nitric acid in an area are not widely

available across PM

2.5

nonattainment

areas, making it difficult to predict the

results of potential ammonia emission

reductions. Ammonia reductions may

be effective and appropriate for

reducing PM

2.5

concentrations in

selected locations, but in other locations

such reductions may lead to minimal

reductions in PM

2.5

concentrations and

increased atmospheric acidity. Research

projects continue to expand our

collective understanding of these issues,

but at this time EPA believes this case-

by-case policy approach is appropriate.

In light of these uncertainties, we

encourage States to continue efforts to

better understand the role of ammonia

in its fine particle problem areas.

c. Comments and Responses

Comment:

One commenter stated that

scientific understanding of the

complexities of PM formation from

ammonia is limited. The commenter

claimed that the reduction of ammonia

will not reduce PM in many areas, and

speciated PM data to investigate the

potential decrease in PM from ammonia

emissions reductions is not available in

all areas.

Response:

The final rule takes these

uncertainties into consideration by

allowing ammonia to be addressed on a

case-by-case basis. For any area about

which enough information is available

to determine that ammonia emission

reductions would lead to a beneficial

reduction in PM

2.5

, the State can

develop a technical demonstration

justifying the control of ammonia. If the

State chooses to develop such a

demonstration, preferably it should be

completed as part of the SIP

development process and prior to the

adoption of control measures, in

consultation with the appropriate EPA

regional office.

Comment:

Some commenters claimed

that requiring no action on some

precursors is counter to the requirement

in sections 172(a)(2) and 188 to attain

the NAAQS as expeditiously as

practicable. They also asserted that

presuming that ammonia is not a PM

2.5

attainment plan precursor violates

302(g) by improperly delegating

authority to the States.

Response:

In many areas, reducing

ammonia emissions could have little

effect on PM

2.5

concentrations and could

lead to the potentially harmful effect of

increased atmospheric acidity. While

States are not required to take action on

ammonia sources under this policy,

States would be required to address

information on ammonia brought to

their attention during the planning and

rule adoption process. Under this

approach, States should assess whether

ammonia reductions would lead to

reduced PM

2.5

concentrations in specific

nonattainment areas. If the State decides

that ammonia reductions could yield

beneficial reductions in PM

2.5

, the State

should complete a technical

demonstration supporting a reversal of

the presumption. The EPA does not

believe that this approach improperly

delegates authority to the States. It

establishes a general presumption for all

areas through this rulemaking process,

and allows for the presumption to be

modified by the State or EPA on a case-

by-case basis. EPA still retains the

ability to make a technical

demonstration for any area if

appropriate to reverse the presumption

and require ammonia to be addressed in

its attainment plan.

Comment:

Some commenters stated

that the results of a large study on air

emissions from concentrated animal

feeding operations (CAFOs) should be

evaluated before requiring control of

ammonia in areas where agriculture is

alleged to be a major source.

Response:

The $15 million national

CAFO consent agreement study

coordinated by Purdue University will

greatly improve ammonia and VOC

emissions inventories and our

understanding of the impacts of

agricultural emissions on particle

formation. The EPA recognizes that the

agricultural emissions study is expected

to provide data for future planning

purposes, and we expect that some of

the results of the study will not be

available in time to be considered in the

development of PM

2.5

State

Implementation Plans dues in April

2008. However, if a State believes it has

sufficient technical information to

warrant regulation of ammonia

emissions in their 2008 implementation

plans, it may include in its plan a

demonstration to reverse the

presumption as well as emission

reduction measures. The EPA will

review each submittal on a case-by-case

basis.

Comment:

A presumption to not

address ammonia will impede certain

states (

i.e.

those that have provisions

requiring their regulations to be ‘‘no

stricter than Federal’’ provisions) from

regulating ammonia.

Response:

This presumptive approach

to ammonia will not restrict States from

addressing ammonia in their PM

2.5

attainment plans. If a State has

information indicating that reductions

in ammonia emissions would cause

beneficial reductions in PM

2.5

concentrations, the State can make a

technical demonstration to reverse the

presumption. In such cases, inclusion of

ammonia as a PM

2.5

attainment plan

precursor would not be considered

stricter than Federal requirements.

Under the policy in the final rule, the

Federal government or the State may

assess the impact of ammonia in a

particular area and determine whether

the presumption of insignificance is

appropriate or whether ammonia is in

fact a significant contributor to the PM

2.5

problem in the area.

4. Policy for VOC

[Section II.E.2 of November 1, 2005

proposed rule (70 FR 65999); sec.

51.1002 in draft and final regulatory

text.]

a. Background

The VOC policy in this rule addresses

volatile and semivolatile organic

compounds, generally up to 24 carbon

atoms. High molecular weight organic

compounds (typically 25 carbon atoms

or more) are emitted directly as primary

organic particles and exist primarily in

the condensed phase at ambient

temperatures. Accordingly, high

molecular weight organic compounds

are to be regulated as primary PM

2.5

emissions for the purposes of the PM

2.5

implementation program.

The organic component of ambient

particles is a complex mixture of

hundreds or even thousands of organic

compounds. These organic compounds

are either emitted directly from sources

(i.e. primary organic aerosol) or can be

formed by reactions in the ambient air

(i.e. secondary organic aerosol, or SOA).

Volatile organic compounds are key

precursors in the formation processes

for both SOA and ozone. The relative

importance of organic compounds in the

formation of secondary organic particles

varies from area to area, depending

upon local emissions sources,

atmospheric chemistry, and season of

the year.

The lightest organic molecules (i.e.,

molecules with six or fewer carbon

atoms) occur in the atmosphere mainly

as vapors and typically do not directly

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form organic particles at ambient

temperatures due to the high vapor

pressure of their products. However,

they participate in atmospheric

chemistry processes resulting in the

formation of ozone and certain free

radical compounds (such as the

hydroxyl radical [OH]) which in turn

participate in oxidation reactions to

form secondary organic aerosols,

sulfates, and nitrates. These VOCs

include all alkanes with up to six

carbon atoms (from methane to hexane

isomers), all alkenes with up to six

carbon atoms (from ethene to hexene

isomers), benzene and many low-

molecular weight carbonyls, chlorinated

compounds, and oxygenated solvents.

Intermediate weight organic

molecules (i.e., compounds with 7 to 24

carbon atoms) often exhibit a range of

volatilities and can exist in both the gas

and aerosol phase at ambient

conditions. For this reason they are also

referred to as semivolatile compounds.

Semivolatile compounds react in the

atmosphere to form secondary organic

aerosols. These chemical reactions are

accelerated in warmer temperatures,

and studies show that SOA typically

comprises a higher percentage of

carbonaceous PM in the summer as

opposed to the winter. The production

of SOA from the atmospheric oxidation

of a specific VOC depends on four

factors: Its atmospheric abundance, its

chemical reactivity, the availability of

oxidants (O

3

, OH, HNO

3

), and the

volatility of its products. In addition,

recent work suggests that the presence

of acidic aerosols may lead to an

increased rate of SOA formation.

Aromatic compounds such as toluene,

xylene, and trimethyl benzene are

considered to be the most significant

anthropogenic SOA precursors and have

been estimated to be responsible for 50

to 70 percent of total SOA in some

airsheds. Man-made sources of

aromatics gases include mobile sources,

petrochemical manufacturing and

solvents. Some of the biogenic

hydrocarbons emitted by trees are also

considered to be important precursors of

secondary organic particulate matter.

Terpenes (and b-pinene, limonene,

carene, etc.) and the sesquiterpenes are

expected to be major contributors to

SOA in areas with significant vegetation

cover, but isoprene is not. Terpenes are

very prevalent in areas with pine

forests, especially in the southeastern

U.S. The rest of the anthropogenic

hydrocarbons (higher alkanes, paraffins,

etc.) have been estimated to contribute

5–20 percent to the SOA concentration

depending on the area.

The contribution of the primary and

secondary components of organic

aerosol to the measured organic aerosol

concentrations remains a complex issue.

Most of the research performed to date

has been done in southern California,

and more recently in central California,

while fewer studies have been

completed on other parts of North

America. Many studies suggest that the

primary and secondary contributions to

total organic aerosol concentrations are

highly variable, even on short time

scales. Studies of pollution episodes

indicate that the contribution of SOA to

the organic particulate matter can vary

from 20 percent to 80 percent during the

same day.

Despite significant advances in

understanding the origins and

properties of SOA, it remains probably

the least understood component of

PM

2.5

. The reactions forming secondary

organics are complex, and the number

of intermediate and final compounds

formed is voluminous. Some of the best

efforts to unravel the chemical

composition of ambient organic aerosol

matter have been able to quantify the

concentrations of hundreds of organic

compounds representing only 10–20

percent of the total organic aerosol

mass. For this reason, SOA continues to

be a significant topic of research and

investigation.

Current scientific and technical

information clearly shows that

carbonaceous material is a significant

fraction of total PM

2.5

mass in most

areas, that certain VOC emissions are

precursors to the formation of secondary

organic aerosol, and that a considerable

fraction of the total carbonaceous

material is likely from local as opposed

to regional sources. However, while

significant progress has been made in

understanding the role of gaseous

organic material in the formation of

organic PM, this relationship remains

complex. We recognize that further

research and technical tools are needed

to better characterize emissions

inventories for specific VOC

compounds, and to determine the extent

of the contribution of specific VOC

compounds to organic PM mass.

In light of these factors, the proposed

rule did not require States to address

VOCs as PM

2.5

attainment plan

precursors and evaluate them for control

measures, unless the State or EPA

makes a finding that VOCs significantly

contribute to a PM

2.5

nonattainment

problem in the State or to other

downwind air quality concerns. Many

PM

2.5

nonattainment areas are also

nonattainment areas for the 8-hour

ozone standard; control measures for

VOCs will be implemented in some of

these areas, potentially providing a co-

benefit for PM

2.5

concentrations.

b. Final Rule

The final rule maintains the same

policy as proposed.

12

States are not

required to address VOC in PM

2.5

implementation plans and evaluate

control measures for such pollutants

unless the State or EPA makes a

technical demonstration that emissions

of VOCs from sources in the State

significantly contribute to PM

2.5

concentrations in a given nonattainment

area. Technical demonstrations are

discussed in section II.A.8 below. If a

State chooses to make a technical

demonstration, it should be developed

in advance of the attainment

demonstration.

c. Comments and Responses

Comment:

One commenter stated that

our understanding of the complexities

of PM

2.5

formation from VOCs is

limited, that speciated PM data are not

available in all areas, and that VOC

reductions will not reduce PM

2.5

in

many areas.

Response:

The EPA acknowledges the

uncertainties regarding the role of VOC

in secondary organic aerosol formation.

For this reason the final rule does not

presumptively include VOC as a

regulated pollutant for PM planning.

However, if available data demonstrates

that control of VOC would reduce PM

2.5

concentrations in an area, the State or

EPA may include VOC as an attainment

plan precursor.

Comment:

One commenter stated that

the rationale that VOC should not be

considered a PM

2.5

attainment plan

precursor because most PM areas are

also ozone areas is not appropriate

because many ozone areas will attain

soon and VOC reductions will still be

needed for PM.

Response:

The primary rationale for

not including VOC as a PM

2.5

attainment

plan precursor in every nonattainment

area is the uncertainty regarding the

contribution of anthropogenic VOCs to

the formation of the organic carbon

portion of fine particles. In certain areas,

EPA expects that VOC control measures

will have some co-benefits in the

reduction of fine particulates. However,

this reason should not be considered the

principal reason for the policy in the

final rule that VOCs presumptively

should not be considered PM

2.5

attainment plan precursors. If a State or

EPA determines that VOCs do

contribute significantly to PM

2.5

concentrations in an area, the State will

be required to evaluate control measures

for VOC as a PM

2.5

attainment plan

12

The policy is the same as proposed, with the

clarification regarding downwind areas discussed

above (Section A.2.b).

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precursor for that area. This approach

will provide for regulation of VOCs in

locations where it is most appropriate.

Comment:

One commenter suggested

that EPA wait for the results of the

pending agricultural emissions study

before requiring control of VOCs in

agricultural areas.

Response:

The $15 million national

CAFO consent agreement study

coordinated by Purdue University will

greatly improve ammonia and VOC

emissions inventories and our

understanding of the impacts of

agricultural emissions on particle

formation. The EPA recognizes that the

agricultural emissions study is expected

to provide data for future planning

purposes, and we expect that some of

the results of the study will not be

available in time to be considered in the

development of PM

2.5

State

Implementation Plans dues in April

2008. However, if a State believes it has

sufficient technical information to

warrant regulation of VOC emissions in

their 2008 implementation plans, it may

include in its plan a demonstration to

reverse the presumption as well as

emission reduction measures. The EPA

will review each submittal on a case-by-

case basis.

5. Policy for NO

X

[Section II.E.2 of November 1, 2005

proposed rule (70 FR 65999); sec.

51.1002 in draft and final regulatory

text.]

a. Background

The sources of NO

X

are numerous and

widespread. The combustion of fossil

fuel in boilers for commercial and

industrial power generation and in

mobile source engines each account for

approximately 30 percent of NO

X

emissions in PM

2.5

nonattainment areas

(based on 2001 emission inventory

information). Nitrates are formed from

the oxidation of oxides of nitrogen into

nitric acid either during the daytime

(reaction with OH) or during the night

(reactions with ozone and water). Nitric

acid continuously transfers between the

gas and the condensed phases through

condensation and evaporation processes

in the atmosphere. However, unless it

reacts with other species (such as

ammonia, sea salt, or dust) to form a

neutralized salt, it will volatilize and

not be measured using standard PM

2.5

measurement techniques. The formation

of aerosol ammonium nitrate is favored

by the availability of ammonia, low

temperatures, and high relative

humidity. Because ammonium nitrate is

semivolatile and not stable in higher

temperatures, nitrate levels are typically

lower in the summer months and higher

in the winter months. The resulting

ammonium nitrate is usually in the sub-

micrometer particle size range.

Reactions with sea salt and dust lead to

the formation of nitrates in coarse

particles. Nitric acid may be dissolved

in ambient aerosol particles.

Based on a review of speciated

monitoring data analyses, it is apparent

that nitrate concentrations vary

significantly across the country. For

example, in some southeastern

locations, annual average nitrate levels

are in the range of 6 to 8 percent of total

PM

2.5

mass, whereas nitrate comprises

40 percent or more of PM

2.5

mass in

certain California locations. Nitrate

formation is favored by the availability

of ammonia, low temperatures, and high

relative humidity. It is also dependent

upon the relative degree of nearby SO

2

emissions because ammonia reacts

preferentially with SO

2

over NO

X

. NO

X

reductions are expected to reduce PM

2.5

concentrations in most areas. However,

it has been suggested that in a limited

number of areas, NO

X

control would

result in increased PM

2.5

mass by

disrupting the ozone cycle and leading

to increased oxidation of SO

2

to form

sulfate particles, which are heavier than

nitrate particles. Because of the above

factors, the proposed rule presumed that

States must evaluate and implement

reasonable controls on sources of NO

X

in all nonattainment areas, but allowed

for the State and EPA to develop a

technical demonstration to reverse this

presumption.

b. Final Rule

The EPA is retaining the proposed

approach in the final rule.

13

Under this

policy, States are required to address

NO

X

as a PM

2.5

attainment plan

precursor and evaluate reasonable

controls for NO

X

in PM

2.5

attainment

plans, unless the State and EPA make a

finding that NO

X

emissions from

sources in the State do not significantly

contribute to PM

2.5

concentrations in the

relevant nonattainment area. This

presumptive policy is consistent with

other recent EPA regulations requiring

NO

X

reductions which will reduce fine

particle pollution, such as the Clean Air

Interstate Rule and a number of rules

targeting onroad and nonroad engine

emissions.

Technical demonstrations that would

reverse the presumption should be

developed in advance of the attainment

demonstration and are discussed in

section II.A.8 below.

13

The policy is the same as proposed, with the

clarification regarding downwind areas discussed

above (Section A.2.b).

c. Comments and Responses

Comment:

Most commenters generally

agreed with the proposed inclusion of

NO

X

as a presumptive PM

2.5

attainment

plan precursor.

Response:

The EPA agrees with these

commenters.

Comment:

Some commenters

requested guidance on what would

constitute an acceptable demonstration

to reverse the presumption that NO

X

is

a PM

2.5

attainment plan precursor.

Response:

Guidance on technical

demonstrations to reverse the

presumptive inclusion of NO

X

in all

state implementation plans is discussed

in section II.A.8 below.

Comment:

One commenter raised

concerns that the proposed policy for

NO

X

would allow a State to find NO

X

to be an insignificant contributor to an

area’s PM

2.5

nonattainment problem and

effectively keep the State from

controlling the area’s NO

X

emissions for

other purposes, such as to address

interstate transport under section 110 of

the CAA. Section 110 requires SIPs to

prohibit emissions within the State that

would contribute significantly to

another State’s nonattainment problem

or interfere with another State’s

maintenance plan.

Response:

The identification of

precursors for regulation under this rule

is for purposes of PM

2.5

nonattainment

and maintenance plans under Part D of

the CAA. The PM

2.5

implementation

rule does not prevent a State from

regulating NO

X

sources under any other

Federal or State rule, including

interstate transport rules under Section

110.

6. Policy for SO

2

[Section II.E.2 of November 1, 2005

proposed rule (70 FR 65999); sec.

51.1002 in draft and final regulatory

text.]

a. Background

Sulfur dioxide is emitted mostly from

the combustion of fossil fuels in boilers

operated by electric utilities and other

industry. Less than 20 percent of SO

2

emissions nationwide are from other

sources, mainly other industrial

processes such as oil refining and pulp

and paper production. The formation of

sulfuric acid from the oxidation of SO

2

is an important process affecting most

areas in North America. There are three

different pathways for this

transformation.

First, gaseous SO

2

can be oxidized by

the hydroxyl radical (OH) to create

sulfuric acid. This gaseous SO

2

oxidation reaction occurs slowly and

only in the daytime. Second, SO

2

can

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dissolve in cloud water (or fog or rain

water), and there it can be oxidized to

sulfuric acid by a variety of oxidants, or

through catalysis by transition metals

such as manganese or iron. If ammonia

is present and taken up by the water

droplet, then ammonium sulfate will

form as a precipitate in the water

droplet. After the cloud changes and the

droplet evaporates, the sulfuric acid or

ammonium sulfate remains in the

atmosphere as a particle. This aqueous

phase production process involving

oxidants can be very fast; in some cases

all the available SO

2

can be oxidized in

less than an hour. Third, SO

2

can be

oxidized in reactions in the particle-

bound water in the aerosol particles

themselves. This process takes place

continuously, but only produces

appreciable sulfate in alkaline (dust, sea

salt) coarse particles. Oxidation of SO

2

has also been observed on the surfaces

of black carbon and metal oxide

particles. During the last 20 years, much

progress has been made in

understanding the first two major

pathways, but some important questions

still remain about the smaller third

pathway. Models indicate that more

than half of the sulfuric acid in the

eastern United States and in the overall

atmosphere is produced in clouds.

The sulfuric acid formed from the

above pathways reacts readily with

ammonia to form ammonium sulfate,

(NH

4

)

2

SO

4

. If there is not enough

ammonia present to fully neutralize the

produced sulfuric acid (one molecule of

sulfuric acid requires two molecules of

ammonia), part of it exists as

ammonium bisulfate, NH

4

HSO

4

(one

molecule of sulfuric acid and one

molecule of ammonia) and the particles

are more acidic than ammonium sulfate.

In certain situations (in the absence of

sufficient ammonia for neutralization),

sulfate can exist in particles as sulfuric

acid, H

2

SO

4

. Sulfuric acid often exists in

the plumes of stacks where SO

2

, SO

3

,

and water vapor are in much higher

concentrations than in the ambient

atmosphere, but these concentrations

become quite small as the plume is

cooled and diluted by mixing.

Because sulfate is a significant

contributor (e.g. ranging from 9 percent

to 40 percent) to PM

2.5

concentrations in

nonattainment areas and to other air

quality problems in all regions of the

country, EPA proposed that States

would be required to address sulfur

dioxide as a PM

2.5

attainment plan

precursor in all areas.

b. Final Rule

The final rule includes the same

policy for sulfur dioxide as in the

proposal. States are required to address

sulfur dioxide as a PM

2.5

attainment

plan precursor and evaluate SO

2

for

possible control measures in all areas.

Sulfate is an important precursor to

PM

2.5

formation in all areas, and has a

strong regional impact on PM

2.5

concentrations. This policy is consistent

with past EPA regulations, such as the

CAIR, the Clean Air Visibility Rule, the

Acid Rain rules, and the Regional Haze

rule, that require SO

2

reductions to

address fine particle pollution and

related air quality problems.

Under the transportation conformity

program, sulfur dioxide is not required

to be addressed in transportation

conformity determinations

before

a SIP

is submitted unless either the state air

agency or EPA regional office makes a

finding that on-road emissions of sulfur

dioxide are significant contributors to

the area’s PM

2.5

problem. Sulfur dioxide

would be addressed

after

a PM

2.5

SIP is

submitted if the area’s SIP contains an

adequate or approved motor vehicle

emissions budget for sulfur dioxide.

EPA based this decision on the

de

minimis

level of sulfur dioxide

emissions from on-road vehicles

currently, and took into consideration

the fact that sulfur dioxide emissions

from on-road sources will decline in the

future due to the implementation of

requirements for low sulfur gasoline

(which began in 2004) and for low

sulfur diesel fuel (beginning in 2006).

For more information, see the May 6,

2005 transportation conformity rule on

PM

2.5

precursors at 70 FR 24283.

c. Comments and Responses

Comment:

Most commenters agreed

with the proposed policy for SO

2

. One

commenter stated, ‘‘* * * requiring

states to address sulfur dioxide in

attainment planning in all areas is

consistent with the science of PM

2.5

formation and essential to effective

implementation of the PM

2.5

NAAQS.’’

Another commenter concluded that

EPA’s proposal ‘‘* * * is justified based

on the fact that SO

2

has been found to

be a significant contributor to PM

2.5

nonattainment in all areas.’’

Response:

The EPA agrees with these

comments.

Comment:

Some commenters believe

States should be able to make a

demonstration that SO

2

not be

addressed as an attainment plan

precursor. The commenters claim that

the urban increment of sulfate is

generally small, and SO

2

control will

not matter in many areas. Commenters

also note that a large percentage of the

SO

2

emission inventory is being

reduced and will be reduced further

through existing programs, and that if

attainment can be demonstrated without

additional SO

2

controls, a State should

be allowed to make that demonstration

in its SIP. One commenter stated that

whether SO

2

emissions from a given

source located in a nonattainment area

in fact contribute significantly to

ambient concentrations of sulfate and

PM

2.5

in that nonattainment area likely

will depend on a range of factors,

including source type, stack height,

location, and meteorology. The

commenter asserted that sulfate forms

over significant geographic distances

from the source of the SO

2

emissions

and may not form significant

concentrations of PM

2.5

in the local

nonattainment area.

Response:

As in the proposal, the

final rule requires SO

2

to be considered

a PM

2.5

attainment plan precursor in all

cases. Sulfate is a significant fraction of

PM

2.5

mass in all nonattainment areas

currently, and although large SO

2

reductions are projected from electric

generating units with the

implementation of the CAIR program,

sulfate is still projected to be a key

contributor to PM

2.5

concentrations in

the future. SO

2

emissions also lead to

sulfate formation on both regional and

local scales. The EPA agrees that the

extent of the contribution from a

particular source in a nonattainment

area to PM

2.5

concentrations in the area

will depend on a number of factors, and

that at times the reaction of SO

2

emissions in the atmosphere to form

sulfate particles may occur less rapidly

and extend over a significant distance.

However, at other times the conversion

of SO

2

to sulfate can occur rapidly and

local impacts from a particular source

can be more significant. States are

required to develop plans to attain as

expeditiously as practicable through the

identification of technically and

economically feasible control measures

from the full range of source categories

contributing to PM

2.5

nonattainment

areas. In developing these plans, each

State will need to consider whether

controls on local SO

2

sources would be

cost-effective and would be needed to

attain expeditiously.

7. Policy for Direct PM

[Section II.E.2 of November 1, 2005

proposed rule (70 FR 65999); sec.

51.1002 in draft and final regulatory

text.]

a. Background

This section addresses inorganic and

organic forms of directly emitted PM.

Although these direct emissions are by

definition not precursors to PM

2.5

, this

section is included to provide

information on the full range of

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components that commonly make up

fine particulate matter.

The main anthropogenic sources of

inorganic (or crustal) particles are:

entrainment by vehicular traffic on

unpaved or paved roads; mechanical

disturbance of soil by highway,

commercial, and residential

construction; and agricultural field

operations (tilling, planting and

harvesting). Industrial processes such as

quarries, minerals processing, and

agricultural crop processing can also

emit crustal materials. While much of

these emissions are coarse PM, the size

distribution can have a tail of particles

smaller than PM

2.5

.

In general, coarse PM is most

important close to the source, and not

generally a significant contributor to

regional scale PM problems. Even so,

during certain high wind events, fine

crustal PM has been shown to be

transported over very long distances.

Emission estimates of mechanically

suspended crustal PM from sources

within the U.S. are often quite high.

However, this PM is often released very

close to the ground, and with the

exception of windblown dust events,

thermal or turbulent forces sufficient to

lift and transport these particles very far

from their source are not usually

present. Thus, crustal material is only a

minor part of PM

2.5

annual average

concentrations.

Primary carbonaceous particles are

largely the result of incomplete

combustion of fossil or biomass fuels.

This incomplete combustion usually

results in emissions of both black

carbon and organic carbon particles.

High molecular weight organic

molecules (i.e., molecules with 25 or

more carbon atoms) are either emitted as

solid or liquid particles, or as gases that

rapidly condense into particle form.

These heavy organic molecules

sometimes are referred to as volatile

organic compounds, but because their

characteristics are most like direct PM

emissions, they will be considered to be

primary emissions for the purposes of

this regulation. Primary organic carbon

also can be formed by condensation of

semi-volatile compounds on the surface

of other particles.

The main combustion sources

emitting carbonaceous PM

2.5

are certain

industrial processes, managed burning,

wildland fires, open burning of waste,

residential wood combustion, coal and

oil-burning boilers (utility, commercial

and industrial), and mobile sources

(both onroad and nonroad). Certain

organic particles also come from natural

sources such as decomposition or

crushing of plant detritus. Most

combustion processes emit more organic

particles than black carbon particles. A

notable exception to this is diesel

engines, which typically emit more

black carbon particles than organic

carbon. Because photochemistry is

typically reduced in the cooler winter

months for much of the country, studies

indicate that the carbon fraction of PM

mass in the winter months is likely

dominated by direct PM emissions as

opposed to secondarily formed organic

aerosol.

Particles from the earth’s crust may

contain a combination of metallic

oxides and biogenic organic matter. The

combustion of surface debris will likely

entrain some soil. Additionally,

emissions from many processes and

from the combustion of fossil fuels

contain elements that are chemically

similar to soil. Thus, a portion of the

emissions from combustion activities

may be classified as crustal in a

compositional analysis of ambient

PM

2.5

. The proposed rule required that

States address the direct emissions of

particulate matter in their PM

2.5

attainment plans. During the comment

period, EPA received several comments

regarding the definition of what should

be regulated as ‘‘direct PM

2.5

.’’

b. Final Rule

This rule defines direct PM

2.5

emissions as ‘‘air pollutant emissions of

direct fine particulate matter, including

organic carbon, elemental carbon, direct

sulfate, direct nitrate, and miscellaneous

inorganic material (i.e. crustal

material).’’ Development of attainment

plans will include direct PM

2.5

emissions and specific PM

2.5

attainment

plan precursors.

c. Comments and Responses

Comment:

A few commenters noted

that 40 CFR 51.1000 of the proposed

rule includes definitions for both

‘‘direct PM

2.5

emissions’’ and for ‘‘PM

2.5

direct emissions.’’ They recommend

including just one definition in the final

rule.

Response:

The EPA acknowledges this

oversight and has included in the final

rule a single definition for ‘‘direct PM

2.5

emissions.’’ It reads: ‘‘Direct PM

2.5

emissions means solid particles emitted

directly from an air emissions source or

activity, or gaseous emissions or liquid

droplets from an air emissions source or

activity which condense to form

particulate matter at ambient

temperatures. Direct PM

2.5

emissions

include elemental carbon, directly

emitted organic carbon, directly emitted

sulfate, directly emitted nitrate, and

other inorganic particles (including but

not limited to crustal material, metals,

and sea salt).’’

8. Optional Technical Demonstrations

for NO

X

, VOC, and Ammonia

[Section II.E.2 of November 1, 2005

proposed rule (70 FR 65999); sec.

51.1002 in draft and final regulatory

text.]

a. Background

The proposed rule required States to

evaluate and consider control strategies

for sources of SO

2

and direct PM

2.5

emissions in all nonattainment areas.

For the precursors NO

X

, VOC, and

ammonia, the proposed rule included

presumptive policies that could be

reversed with an acceptable technical

demonstration by the State or EPA. (The

policy in the proposal presumptively

required that NO

X

emissions must be

addressed in all areas, and that VOC and

ammonia emissions do not need to be

addressed in all areas.) A number of

commenters requested additional

guidance on the criteria for an

acceptable technical demonstration.

b. Final Rule

The final rule retains provisions for

the State or EPA to conduct a technical

demonstration to reverse the

presumptive inclusion of NO

X

or to

reverse the presumptive exclusions of

ammonia and VOC as PM

2.5

attainment

plan precursors. Demonstrations to

reverse the presumptions for ammonia,

VOC, or NO

X

are to be based on the

weight of evidence of available

information, and any demonstration by

the State must be approved by EPA. The

State must demonstrate that based on

the sum of available technical and

scientific information, it would be

appropriate for a nonattainment area to

reverse the presumptive approach for a

particular precursor. The demonstration

should include information from

multiple sources, including results of

speciation data analyses, air quality

modeling studies, chemical tracer

studies, emission inventories, or special

intensive measurement studies to

evaluate specific atmospheric chemistry

in an area.

Because of the variation among

nonattainment areas in terms of such

factors as local emissions sources,

growth patterns, topography, and

severity of the nonattainment problem,

EPA believes that it would not be

appropriate to define a prescriptive set

of analyses that must be included in all

PM

2.5

precursor technical

demonstrations. The key criterion is that

any technical demonstration must fairly

represent available information.

In developing the implementation

plan for a nonattainment area, the State

should use all relevant information

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available (from EPA, the State, or other

sources) to determine the scientifically

most appropriate approach to regulating

NO

X

, ammonia, and VOC emissions in

the area. As required under any State

rulemaking process, the State must

consider and provide a response in the

record to any information or evidence

brought forward by commenters during

the SIP planning, development and

review process which indicates that the

presumption for a precursor should be

reversed. In its review of the

forthcoming State implementation plan

submittal, EPA will review the State’s

proposed precursor policies in light of

all currently available information. If

information brought forward by

commenters or the State in the SIP

development process shows that the

presumption in this rule for ammonia,

VOC or NO

X

is not technically justified

for a particular nonattainment area, the

State must conduct a technical

demonstration to reverse the

presumption. In the case of ammonia or

VOC, the State then would evaluate

control measures and implement those

measures that are technically and

economically feasible and that will

contribute to expeditious attainment of

the standards.

In the section below we suggest

examples of the types of analyses that

would be appropriate to use in

developing such a demonstration. States

are encouraged to consult with EPA in

formulating appropriate technical

demonstrations.

i.

Emission Inventory Information:

An

analysis might show that a precursor

composes a significant fraction of the

emissions inventory in an area and

therefore requires greater consideration.

Example:

Several stationary sources

emitting particular VOCs known to

contribute to SOA formation make up a

significant portion of the area’s VOC

inventory. This analysis may be useful in

conjunction with other analyses included in

a weight of evidence demonstration.

ii.

Speciation Data Information:

Analysis of data from speciation

networks might lead a State to

determine the relative importance of a

precursor to seasonal or yearly average

PM concentrations. Individual

precursors require different approaches.

Collection of new data could be used to

understand the impacts of precursors in

an area.

Example:

Nitrate ion is a large portion of

winter average PM

2.5

mass. Nitrate ion is a

major portion of PM

2.5

mass on the 10 highest

PM

2.5

days in winter in the past 3 years. The

days with the highest mass concentrations

might be indicative of inversion conditions

and/or local impacts, rather than large-scale

transport processes. For these reasons, nitrate

should be addressed in the PM

2.5

attainment

plan.

Example:

Ammonium ion data combined

with total calculated nitrate data indicates

that reductions in ammonia would reduce

PM concentrations without a sharp related

increase in particle acidity. PM speciation

data shows that PM in the area is generally

within 10% of calculated neutralization. In

places for which the needed atmospheric

data are available to determine whether

increased acidity is estimated to lead to

negative environmental effects, analysis

showing that increased acidity of particles

and precipitation would likely result from

ammonia reductions would support the

presumption against ammonia regulation.

Analysis showing that ammonia reductions

would be unlikely to increase the acidity of

particles and precipitation, and that potential

reductions in ammonia would significantly

reduce PM

2.5

levels, would support a

technical demonstration to reverse the

presumption.

iii.

Modeling Information:

Results of

atmospheric modeling may help a State

characterize the impacts of potential

precursor emission reductions on PM

2.5

concentrations in an area.

Example:

Modeling of SO

2

, NO

X

, and VOC

emission reductions result in lower sulfate

and nitrate levels but not lower secondary

organic aerosol levels. This likely indicates

that VOC reductions are not as vital as

reductions of the other precursors.