[Title 40 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2006 Edition]
[From the U.S. Government Printing Office]



[[Page i]]



          40


          Parts 50 to 51

                         Revised as of July 1, 2006


          Protection of Environment
          



________________________

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2006
          With Ancillaries
                    Published by
                    Office of the Federal Register
                    National Archives and Records
                    Administration
                    A Special Edition of the Federal Register

[[Page ii]]

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                            Table of Contents



                                                                    Page
  Explanation.................................................       v

  Title 40:
          Chapter I--Environmental Protection Agency                 3
  Finding Aids:
      Material Approved for Incorporation by Reference........     581
      Table of CFR Titles and Chapters........................     583
      Alphabetical List of Agencies Appearing in the CFR......     601
      List of CFR Sections Affected...........................     611

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                     ----------------------------

                     Cite this Code: CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 40 CFR 50.1 refers 
                       to title 40, part 50, 
                       section 1.

                     ----------------------------

[[Page v]]



                               EXPLANATION

    The Code of Federal Regulations is a codification of the general and 
permanent rules published in the Federal Register by the Executive 
departments and agencies of the Federal Government. The Code is divided 
into 50 titles which represent broad areas subject to Federal 
regulation. Each title is divided into chapters which usually bear the 
name of the issuing agency. Each chapter is further subdivided into 
parts covering specific regulatory areas.
    Each volume of the Code is revised at least once each calendar year 
and issued on a quarterly basis approximately as follows:

Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1

    The appropriate revision date is printed on the cover of each 
volume.

LEGAL STATUS

    The contents of the Federal Register are required to be judicially 
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie 
evidence of the text of the original documents (44 U.S.C. 1510).

HOW TO USE THE CODE OF FEDERAL REGULATIONS

    The Code of Federal Regulations is kept up to date by the individual 
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    To determine whether a Code volume has been amended since its 
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EFFECTIVE AND EXPIRATION DATES

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citations for the regulations are referred to by volume number and page 
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inserted following the text.

OMB CONTROL NUMBERS

    The Paperwork Reduction Act of 1980 (Pub. L. 96-511) requires 
Federal agencies to display an OMB control number with their information 
collection request.

[[Page vi]]

Many agencies have begun publishing numerous OMB control numbers as 
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placed as close as possible to the applicable recordkeeping or reporting 
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OBSOLETE PROVISIONS

    Provisions that become obsolete before the revision date stated on 
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INCORPORATION BY REFERENCE

    What is incorporation by reference? Incorporation by reference was 
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This material, like any other properly issued regulation, has the force 
of law.
    What is a proper incorporation by reference? The Director of the 
Federal Register will approve an incorporation by reference only when 
the requirements of 1 CFR part 51 are met. Some of the elements on which 
approval is based are:
    (a) The incorporation will substantially reduce the volume of 
material published in the Federal Register.
    (b) The matter incorporated is in fact available to the extent 
necessary to afford fairness and uniformity in the administrative 
process.
    (c) The incorporating document is drafted and submitted for 
publication in accordance with 1 CFR part 51.
    Properly approved incorporations by reference in this volume are 
listed in the Finding Aids at the end of this volume.
    What if the material incorporated by reference cannot be found? If 
you have any problem locating or obtaining a copy of material listed in 
the Finding Aids of this volume as an approved incorporation by 
reference, please contact the agency that issued the regulation 
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the material is not available, please notify the Director of the Federal 
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20408, or call 202-741-6010.

CFR INDEXES AND TABULAR GUIDES

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the revision dates of the 50 CFR titles.

[[Page vii]]


REPUBLICATION OF MATERIAL

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                              Raymond A. Mosley,
                                    Director,
                          Office of the Federal Register.

July 1, 2006.

[[Page ix]]



                               THIS TITLE

    Title 40--Protection of Environment is composed of thirty-one 
volumes. The parts in these volumes are arranged in the following order: 
parts 1-49, parts 50-51, part 52 (52.01-52.1018), part 52 (52.1019-End), 
parts 53-59, part 60 (60.1-End), part 60 (Appendices), parts 61-62, part 
63 (63.1-63.599), part 63 (63.600-63.1199), part 63 (63.1200-63.1439), 
part 63 (63.1440-63.6175), part 63 (63.6580-63.8830), part 63 (63.8980-
End) parts 64-71, parts 72-80, parts 81-85, part 86 (86.1-86.599-99) 
part 86 (86.600-1-End), parts 87-99, parts 100-135, parts 136-149, parts 
150-189, parts 190-259, parts 260-265, parts 266-299, parts 300-399, 
parts 400-424, parts 425-699, parts 700-789, and part 790 to End. The 
contents of these volumes represent all current regulations codified 
under this title of the CFR as of July 1, 2006.

    Chapter I--Environmental Protection Agency appears in all thirty-one 
volumes. An alphabetical Listing of Pesticide Chemicals Index appears in 
parts 150-189. Regulations issued by the Council on Environmental 
Quality appear in the volume containing part 790 to End. The OMB control 
numbers for title 40 appear in Sec.  9.1 of this chapter.

    For this volume, Elmer Barksdale was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Frances D. McDonald, assisted by Alomha S. Morris.

[[Page 1]]



                   TITLE 40--PROTECTION OF ENVIRONMENT


                   (This book contains parts 50 to 51)

  --------------------------------------------------------------------
                                                                    Part

chapter i--Environmental Protection Agency (Continued)......          50

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         CHAPTER I--ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)




  --------------------------------------------------------------------

                       SUBCHAPTER C--AIR PROGRAMS
Part                                                                Page
50              National primary and secondary ambient air 
                    quality standards.......................           5
51              Requirements for preparation, adoption, and 
                    submittal of implementation plans.......         121

[[Page 5]]



                        SUBCHAPTER C_AIR PROGRAMS





PART 50_NATIONAL PRIMARY AND SECONDARY AMBIENT AIR QUALITY STANDARDS
--Table of Contents




Sec.
50.1 Definitions.
50.2 Scope.
50.3 Reference conditions.
50.4 National primary ambient air quality standards for sulfur oxides 
          (sulfur dioxide).
50.5 National secondary ambient air quality standard for sulfur oxides 
          (sulfur dioxide).
50.6 National primary and secondary ambient air quality standards for 
          PM10.
50.7 National primary and secondary ambient air quality standards for 
          PM2.5.
50.8 National primary ambient air quality standards for carbon monoxide.
50.9 National 1-hour primary and secondary ambient air quality standards 
          for ozone.
50.10 National 8-hour primary and secondary ambient air quality 
          standards for ozone.
50.11 National primary and secondary ambient air quality standards for 
          nitrogen dioxide.
50.12 National primary and secondary ambient air quality standards for 
          lead.

Appendix A to Part 50--Reference Method for the Determination of Sulfur 
          Dioxide in the Atmosphere (Pararosaniline Method)
Appendix B to Part 50--Reference Method for the Determination of 
          Suspended Particulate Matter in the Atmosphere (High-Volume 
          Method)
Appendix C to Part 50--Measurement Principle and Calibration Procedure 
          for the Measurement of Carbon Monoxide in the Atmosphere (Non-
          Dispersive Infrared Photometry)
Appendix D to Part 50--Measurement Principle and Calibration Procedure 
          for the Measurement of Ozone in the Atmosphere
Appendix E to Part 50 [Reserved]
Appendix F to Part 50--Measurement Principle and Calibration Procedure 
          for the Measurement of Nitrogen Dioxide in the Atmosphere (Gas 
          Phase Chemiluminescence)
Appendix G to Part 50--Reference Method for the Determination of Lead in 
          Suspended Particulate Matter Collected From Ambient Air
Appendix H to Part 50--Interpretation of the 1-Hour Primary and 
          Secondary National Ambient Air Quality Standards for Ozone
Appendix I to Part 50--Interpretation of the 8-Hour Primary and 
          Secondary National Ambient Air Quality Standards for Ozone
Appendix J to Part 50--Reference Method for the Determination of 
          Particulate Matter as PM10 in the Atmosphere
Appendix K to Part 50--Interpretation of the National Ambient Air 
          Quality Standards for Particulate Matter
Appendix L to Part 50--Reference Method for the Determination of Fine 
          Particulate Matter as PM2.5 in the Atmosphere
Appendix M to Part 50 [Reserved]
Appendix N to Part 50--Interpretation of the National Ambient Air 
          Quality Standards for Particulate Matter

    Authority: 42 U.S.C. 7401, et seq.

    Source: 36 FR 22384, Nov. 25, 1971, unless otherwise noted.



Sec. 50.1  Definitions.

    (a) As used in this part, all terms not defined herein shall have 
the meaning given them by the Act.
    (b) Act means the Clean Air Act, as amended (42 U.S.C. 1857-18571, 
as amended by Pub. L. 91-604).
    (c) Agency means the Environmental Protection Agency.
    (d) Administrator means the Administrator of the Environmental 
Protection Agency.
    (e) Ambient air means that portion of the atmosphere, external to 
buildings, to which the general public has access.
    (f) Reference method means a method of sampling and analyzing the 
ambient air for an air pollutant that is specified as a reference method 
in an appendix to this part, or a method that has been designated as a 
reference method in accordance with part 53 of this chapter; it does not 
include a method for which a reference method designation has been 
cancelled in accordance with Sec. 53.11 or Sec. 53.16 of this chapter.
    (g) Equivalent method means a method of sampling and analyzing the 
ambient air for an air pollutant that has been designated as an 
equivalent method in accordance with part 53 of this chapter; it does 
not include a method for which an equivalent method designation has been 
cancelled in accordance with Sec. 53.11 or Sec. 53.16 of this chapter.

[[Page 6]]

    (h) Traceable means that a local standard has been compared and 
certified either directly or via not more than one intermediate 
standard, to a primary standard such as a National Bureau of Standards 
Standard Reference Material (NBS SRM), or a USEPA/NBS-approved Certified 
Reference Material (CRM).
    (i) Indian country is as defined in 18 U.S.C. 1151.

[36 FR 22384, Nov. 25, 1971, as amended at 41 FR 11253, Mar. 17, 1976; 
48 FR 2529, Jan. 20, 1983; 63 FR 7274, Feb. 12, 1998]



Sec. 50.2  Scope.

    (a) National primary and secondary ambient air quality standards 
under section 109 of the Act are set forth in this part.
    (b) National primary ambient air quality standards define levels of 
air quality which the Administrator judges are necessary, with an 
adequate margin of safety, to protect the public health. National 
secondary ambient air quality standards define levels of air quality 
which the Administrator judges necessary to protect the public welfare 
from any known or anticipated adverse effects of a pollutant. Such 
standards are subject to revision, and additional primary and secondary 
standards may be promulgated as the Administrator deems necessary to 
protect the public health and welfare.
    (c) The promulgation of national primary and secondary ambient air 
quality standards shall not be considered in any manner to allow 
significant deterioration of existing air quality in any portion of any 
State or Indian country.
    (d) The proposal, promulgation, or revision of national primary and 
secondary ambient air quality standards shall not prohibit any State or 
Indian country from establishing ambient air quality standards for that 
State or area under a tribal CAA program or any portion thereof which 
are more stringent than the national standards.

[36 FR 22384, Nov. 25, 1971, as amended at 63 FR 7274, Feb. 12, 1998]



Sec. 50.3  Reference conditions.

    All measurements of air quality that are expressed as mass per unit 
volume (e.g., micrograms per cubic meter) other than for the particulate 
matter (PM2.5) standards contained in Sec. 50.7 shall be 
corrected to a reference temperature of 25 [deg]C and a reference 
pressure of 760 millimeters of mercury (1,013.2 millibars). Measurements 
of PM2.5 for purposes of comparison to the standards 
contained in Sec. 50.7 shall be reported based on actual ambient air 
volume measured at the actual ambient temperature and pressure at the 
monitoring site during the measurement period.

[69 FR 45595, July 30, 2004]



Sec. 50.4  National primary ambient air quality standards for sulfur 
oxides (sulfur dioxide).

    (a) The level of the annual standard is 0.030 parts per million 
(ppm), not to be exceeded in a calendar year. The annual arithmetic mean 
shall be rounded to three decimal places (fractional parts equal to or 
greater than 0.0005 ppm shall be rounded up).
    (b) The level of the 24-hour standard is 0.14 parts per million 
(ppm), not to be exceeded more than once per calendar year. The 24-hour 
averages shall be determined from successive nonoverlapping 24-hour 
blocks starting at midnight each calendar day and shall be rounded to 
two decimal places (fractional parts equal to or greater than 0.005 ppm 
shall be rounded up).
    (c) Sulfur oxides shall be measured in the ambient air as sulfur 
dioxide by the reference method described in appendix A to this part or 
by an equivalent method designated in accordance with part 53 of this 
chapter.
    (d) To demonstrate attainment, the annual arithmetic mean and the 
second-highest 24-hour averages must be based upon hourly data that are 
at least 75 percent complete in each calendar quarter. A 24-hour block 
average shall be considered valid if at least 75 percent of the hourly 
averages for the 24-hour period are available. In the event that only 
18, 19, 20, 21, 22, or 23 hourly averages are available, the 24-hour 
block average shall be computed as the sum of the available hourly 
averages using 18, 19, etc. as the divisor. If fewer than 18 hourly 
averages are available, but the 24-hour average would exceed the level 
of the standard when zeros are substituted for the

[[Page 7]]

missing values, subject to the rounding rule of paragraph (b) of this 
section, then this shall be considered a valid 24-hour average. In this 
case, the 24-hour block average shall be computed as the sum of the 
available hourly averages divided by 24.

[61 FR 25579, May 22, 1996]



Sec. 50.5  National secondary ambient air quality standard for sulfur 
oxides (sulfur dioxide).

    (a) The level of the 3-hour standard is 0.5 parts per million (ppm), 
not to be exceeded more than once per calendar year. The 3-hour averages 
shall be determined from successive nonoverlapping 3-hour blocks 
starting at midnight each calendar day and shall be rounded to 1 decimal 
place (fractional parts equal to or greater than 0.05 ppm shall be 
rounded up).
    (b) Sulfur oxides shall be measured in the ambient air as sulfur 
dioxide by the reference method described in appendix A of this part or 
by an equivalent method designated in accordance with part 53 of this 
chapter.
    (c) To demonstrate attainment, the second-highest 3-hour average 
must be based upon hourly data that are at least 75 percent complete in 
each calendar quarter. A 3-hour block average shall be considered valid 
only if all three hourly averages for the 3-hour period are available. 
If only one or two hourly averages are available, but the 3-hour average 
would exceed the level of the standard when zeros are substituted for 
the missing values, subject to the rounding rule of paragraph (a) of 
this section, then this shall be considered a valid 3-hour average. In 
all cases, the 3-hour block average shall be computed as the sum of the 
hourly averages divided by 3.

[61 FR 25580, May 22, 1996]



Sec. 50.6  National primary and secondary ambient air quality standards 
for PM[bdi1][bdi0].

    (a) The level of the national primary and secondary 24-hour ambient 
air quality standards for particulate matter is 150 micrograms per cubic 
meter ([micro]g/m\3\), 24-hour average concentration. The standards are 
attained when the expected number of days per calendar year with a 24-
hour average concentration above 150 [micro]g/m\3\, as determined in 
accordance with appendix K to this part, is equal to or less than one.
    (b) The level of the national primary and secondary annual standards 
for particulate matter is 50 micrograms per cubic meter ([micro]g/m\3\), 
annual arithmetic mean. The standards are attained when the expected 
annual arithmetic mean concentration, as determined in accordance with 
appendix K to this part, is less than or equal to 50 [micro]g/m\3\.
    (c) For the purpose of determining attainment of the primary and 
secondary standards, particulate matter shall be measured in the ambient 
air as PM10 (particles with an aerodynamic diameter less than 
or equal to a nominal 10 micrometers) by:
    (1) A reference method based on appendix J and designated in 
accordance with part 53 of this chapter, or
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.

[52 FR 24663, July 1, 1987, as amended at 62 FR 38711, July 18, 1997; 65 
FR 80779, Dec. 22, 2000]



Sec. 50.7  National primary and secondary ambient air quality standards 
for PM[bdi2].[bdi5].

    (a) The national primary and secondary ambient air quality standards 
for particulate matter are 15.0 micrograms per cubic meter ([micro]g/
m\3\) annual arithmetic mean concentration, and 65 [micro]g/m\3\ 24-hour 
average concentration measured in the ambient air as PM2.5 
(particles with an aerodynamic diameter less than or equal to a nominal 
2.5 micrometers) by either:
    (1) A reference method based on appendix L of this part and 
designated in accordance with part 53 of this chapter; or
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.
    (b) The annual primary and secondary PM2.5 standards are 
met when the annual arithmetic mean concentration, as determined in 
accordance with appendix N of this part, is less than or equal to 15.0 
micrograms per cubic meter.
    (c) The 24-hour primary and secondary PM2.5 standards are 
met when

[[Page 8]]

the 98th percentile 24-hour concentration, as determined in 
accordance with appendix N of this part, is less than or equal to 65 
micrograms per cubic meter.

[62 FR 38711, July 18, 1997, as amended at 69 FR 45595, July 30, 2004]



Sec. 50.8  National primary ambient air quality standards for carbon 
monoxide.

    (a) The national primary ambient air quality standards for carbon 
monoxide are:
    (1) 9 parts per million (10 milligrams per cubic meter) for an 8-
hour average concentration not to be exceeded more than once per year 
and
    (2) 35 parts per million (40 milligrams per cubic meter) for a 1-
hour average concentration not to be exceeded more than once per year.
    (b) The levels of carbon monoxide in the ambient air shall be 
measured by:
    (1) A reference method based on appendix C and designated in 
accordance with part 53 of this chapter, or
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.
    (c) An 8-hour average shall be considered valid if at least 75 
percent of the hourly average for the 8-hour period are available. In 
the event that only six (or seven) hourly averages are available, the 8-
hour average shall be computed on the basis of the hours available using 
six (or seven) as the divisor.
    (d) When summarizing data for comparision with the standards, 
averages shall be stated to one decimal place. Comparison of the data 
with the levels of the standards in parts per million shall be made in 
terms of integers with fractional parts of 0.5 or greater rounding up.

[50 FR 37501, Sept. 13, 1985]



Sec. 50.9  National 1-hour primary and secondary ambient air quality 
standards for ozone.

    (a) The level of the national 1-hour primary and secondary ambient 
air quality standards for ozone measured by a reference method based on 
appendix D to this part and designated in accordance with part 53 of 
this chapter, is 0.12 parts per million (235 [micro]g/m\3\). The 
standard is attained when the expected number of days per calendar year 
with maximum hourly average concentrations above 0.12 parts per million 
(235 [micro]g/m\3\) is equal to or less than 1, as determined by 
appendix H to this part.
    (b) The 1-hour standards set forth in this section will remain 
applicable to all areas notwithstanding the promulgation of 8-hour ozone 
standards under Sec. 50.10. The 1-hour NAAQS set forth in paragraph (a) 
of this section will no longer apply to an area one year after the 
effective date of the designation of that area for the 8-hour ozone 
NAAQS pursuant to section 107 of the Clean Air Act. Area designations 
and classifications with respect to the 1-hour standards are codified in 
40 CFR part 81.
    (c) EPA's authority under paragraph (b) of this section to determine 
that the 1-hour standard no longer applies to an area based on a 
determination that the area has attained the 1-hour standard is stayed 
until such time as EPA issues a final rule revising or reinstating such 
authority and considers and addresses in such rulemaking any comments 
concerning (1) which, if any, implementation activities for a revised 
ozone standard (including but not limited to designation and 
classification of areas) would need to occur before EPA would determine 
that the 1-hour ozone standard no longer applies to an area, and (2) the 
effect of revising the ozone NAAQS on the existing 1-hour ozone 
designations.

[62 FR 38894, July 18, 1997, as amended at 65 FR 45200, July 20, 2000; 
68 FR 38163, June 26, 2003, 69 FR 23996, Apr. 30, 2004]



Sec. 50.10  National 8-hour primary and secondary ambient air quality 
standards for ozone.

    (a) The level of the national 8-hour primary and secondary ambient 
air quality standards for ozone, measured by a reference method based on 
appendix D to this part and designated in accordance with part 53 of 
this chapter, is 0.08 parts per million (ppm), daily maximum 8-hour 
average.
    (b) The 8-hour primary and secondary ozone ambient air quality 
standards are met at an ambient air quality monitoring site when the 
average of the annual fourth-highest daily maximum 8-hour average ozone 
concentration is

[[Page 9]]

less than or equal to 0.08 ppm, as determined in accordance with 
appendix I to this part.

[62 FR 38894, July 18, 1997]



Sec. 50.11  National primary and secondary ambient air quality standards 
for nitrogen dioxide.

    (a) The level of the national primary ambient air quality standard 
for nitrogen dioxide is 0.053 parts per million (100 micrograms per 
cubic meter), annual arithmetic mean concentration.
    (b) The level of national secondary ambient air quality standard for 
nitrogen dioxide is 0.053 parts per million (100 micrograms per cubic 
meter), annual arithmetic mean concentration.
    (c) The levels of the standards shall be measured by:
    (1) A reference method based on appendix F and designated in 
accordance with part 53 of this chapter, or
    (2) An equivalent method designated in accordance with part 53 of 
this chapter.
    (d) The standards are attained when the annual arithmetic mean 
concentration in a calendar year is less than or equal to 0.053 ppm, 
rounded to three decimal places (fractional parts equal to or greater 
than 0.0005 ppm must be rounded up). To demonstrate attainment, an 
annual mean must be based upon hourly data that are at least 75 percent 
complete or upon data derived from manual methods that are at least 75 
percent complete for the scheduled sampling days in each calendar 
quarter.

[50 FR 25544, June 19, 1985]



Sec. 50.12  National primary and secondary ambient air quality standards 
for lead.

    National primary and secondary ambient air quality standards for 
lead and its compounds, measured as elemental lead by a reference method 
based on appendix G to this part, or by an equivalent method, are: 1.5 
micrograms per cubic meter, maximum arithmetic mean averaged over a 
calendar quarter.

(Secs. 109, 301(a) Clean Air Act as amended (42 U.S.C. 7409, 7601(a)))

[43 FR 46258, Oct. 5, 1978]

Appendix A to Part 50--Reference Method for the Determination of Sulfur 
            Dioxide in the Atmosphere (Pararosaniline Method)

    1.0 Applicability.
    1.1 This method provides a measurement of the concentration of 
sulfur dioxide (SO2) in ambient air for determining 
compliance with the primary and secondary national ambient air quality 
standards for sulfur oxides (sulfur dioxide) as specified in Sec. 50.4 
and Sec. 50.5 of this chapter. The method is applicable to the 
measurement of ambient SO2 concentrations using sampling 
periods ranging from 30 minutes to 24 hours. Additional quality 
assurance procedures and guidance are provided in part 58, appendixes A 
and B, of this chapter and in references 1 and 2.
    2.0 Principle.
    2.1 A measured volume of air is bubbled through a solution of 0.04 M 
potassium tetrachloromercurate (TCM). The SO2 present in the 
air stream reacts with the TCM solution to form a stable 
monochlorosulfonatomercurate(3) complex. Once formed, this complex 
resists air oxidation(4, 5) and is stable in the presence of strong 
oxidants such as ozone and oxides of nitrogen. During subsequent 
analysis, the complex is reacted with acid-bleached pararosaniline dye 
and formaldehyde to form an intensely colored pararosaniline methyl 
sulfonic acid.(6) The optical density of this species is determined 
spectrophotometrically at 548 nm and is directly related to the amount 
of SO2 collected. The total volume of air sampled, corrected 
to EPA reference conditions (25 [deg]C, 760 mm Hg [101 kPa]), is 
determined from the measured flow rate and the sampling time. The 
concentration of SO2 in the ambient air is computed and 
expressed in micrograms per standard cubic meter ([micro]g/std m\3\).
    3.0 Range.
    3.1 The lower limit of detection of SO2 in 10 mL of TCM 
is 0.75 [micro]g (based on collaborative test results).(7) This 
represents a concentration of 25 [micro]g SO2/m\3\ (0.01 ppm) 
in an air sample of 30 standard liters (short-term sampling) and a 
concentration of 13 [micro]g SO2/m\3\ (0.005 ppm) in an air 
sample of 288 standard liters (long-term sampling). Concentrations less 
than 25 [micro]g SO2/m\3\ can be measured by sampling larger 
volumes of ambient air; however, the collection efficiency falls off 
rapidly at low concentrations.(8, 9) Beer's law is adhered to up to 34 
[micro]g of SO2 in 25 mL of final solution. This upper limit 
of the analysis range represents a concentration of 1,130 [micro]g 
SO2/m\3\ (0.43 ppm) in an air sample of 30 standard liters 
and a concentration of 590 [micro]g SO2/m\3\ (0.23 ppm) in an 
air sample of 288 standard liters. Higher concentrations can be measured 
by collecting a smaller volume of air, by increasing the volume of 
absorbing solution, or by diluting a suitable portion of

[[Page 10]]

the collected sample with absorbing solution prior to analysis.
    4.0 Interferences.
    4.1 The effects of the principal potential interferences have been 
minimized or eliminated in the following manner: Nitrogen oxides by the 
addition of sulfamic acid,(10, 11) heavy metals by the addition of 
ethylenediamine tetracetic acid disodium salt (EDTA) and phosphoric 
acid,(10, 12) and ozone by time delay.(10) Up to 60 [micro]g Fe (III), 
22 [micro]g V (V), 10 [micro]g Cu (II), 10 [micro]g Mn (II), and 10 
[micro]g Cr (III) in 10 mL absorbing reagent can be tolerated in the 
procedure.(10) No significant interference has been encountered with 2.3 
[micro]g NH3.(13)
    5.0 Precision and Accuracy.
    5.1 The precision of the analysis is 4.6 percent (at the 95 percent 
confidence level) based on the analysis of standard sulfite samples.(10)
    5.2 Collaborative test results (14) based on the analysis of 
synthetic test atmospheres (SO2 in scrubbed air) using the 
24-hour sampling procedure and the sulfite-TCM calibration procedure 
show that:

 The replication error varies linearly with 
concentration from 2.5 [micro]g/m\3\ at 
concentrations of 100 [micro]g/m\3\ to 7 [micro]g/
m\3\ at concentrations of 400 [micro]g/m\3\.
 The day-to-day variability within an individual 
laboratory (repeatability) varies linearly with concentration from 
18.1 [micro]g/m\3\ at levels of 100 [micro]g/m\3\ 
to 50.9 [micro]g/m\3\ at levels of 400 [micro]g/
m\3\.
 The day-to-day variability between two or more 
laboratories (reproducibility) varies linearly with concentration from 
36.9 [micro]g/m\3\ at levels of 100 [micro]g/m\3\ 
to 103.5 [micro] g/m\3\ at levels of 400 [micro]g/
m\3\.
 The method has a concentration-dependent bias, which 
becomes significant at the 95 percent confidence level at the high 
concentration level. Observed values tend to be lower than the expected 
SO2 concentration level.

    6.0 Stability.
    6.1 By sampling in a controlled temperature environment of 
15[deg]10 [deg]C, greater than 98.9 percent of the 
SO2-TCM complex is retained at the completion of sampling. 
(15) If kept at 5 [deg]C following the completion of sampling, the 
collected sample has been found to be stable for up to 30 days.(10) The 
presence of EDTA enhances the stability of SO2 in the TCM 
solution and the rate of decay is independent of the concentration of 
SO2.(16)
    7.0 Apparatus.
    7.1 Sampling.
    7.1.1 Sample probe: A sample probe meeting the requirements of 
section 7 of 40 CFR part 58, appendix E (Teflon[reg] or glass 
with residence time less than 20 sec.) is used to transport ambient air 
to the sampling train location. The end of the probe should be designed 
or oriented to preclude the sampling of precipitation, large particles, 
etc. A suitable probe can be constructed from Teflon[reg] 
tubing connected to an inverted funnel.
    7.1.2 Absorber--short-term sampling: An all glass midget impinger 
having a solution capacity of 30 mL and a stem clearance of 4 1 mm from the bottom of the vessel is used for sampling 
periods of 30 minutes and 1 hour (or any period considerably less than 
24 hours). Such an impinger is shown in Figure 1. These impingers are 
commercially available from distributors such as Ace Glass, 
Incorporated.
    7.1.3 Absorber--24-hour sampling: A polypropylene tube 32 mm in 
diameter and 164 mm long (available from Bel Art Products, Pequammock, 
NJ) is used as the absorber. The cap of the absorber must be a 
polypropylene cap with two ports (rubber stoppers are unacceptable 
because the absorbing reagent can react with the stopper to yield 
erroneously high SO2 concentrations). A glass impinger stem, 
6 mm in diameter and 158 mm long, is inserted into one port of the 
absorber cap. The tip of the stem is tapered to a small diameter orifice 
(0.4 0.1 mm) such that a No. 79 jeweler's drill 
bit will pass through the opening but a No. 78 drill bit will not. 
Clearance from the bottom of the absorber to the tip of the stem must be 
6 2 mm. Glass stems can be fabricated by any 
reputable glass blower or can be obtained from a scientific supply firm. 
Upon receipt, the orifice test should be performed to verify the orifice 
size. The 50 mL volume level should be permanently marked on the 
absorber. The assembled absorber is shown in Figure 2.
    7.1.4 Moisture trap: A moisture trap constructed of a glass trap as 
shown in Figure 1 or a polypropylene tube as shown in Figure 2 is placed 
between the absorber tube and flow control device to prevent entrained 
liquid from reaching the flow control device. The tube is packed with 
indicating silica gel as shown in Figure 2. Glass wool may be 
substituted for silica gel when collecting short-term samples (1 hour or 
less) as shown in Figure 1, or for long term (24 hour) samples if flow 
changes are not routinely encountered.
    7.1.5 Cap seals: The absorber and moisture trap caps must seal 
securely to prevent leaks during use. Heat-shrink material as shown in 
Figure 2 can be used to retain the cap seals if there is any chance of 
the caps coming loose during sampling, shipment, or storage.

[[Page 11]]




[[Page 12]]




    7.1.6 Flow control device: A calibrated rotameter and needle valve 
combination capable of maintaining and measuring air flow to within 
2 percent is suitable for short-term sampling but 
may not be used for long-term sampling. A critical orifice can be used 
for regulating flow rate for both long-term and short-term sampling. A 
22-gauge hypodermic

[[Page 13]]

needle 25 mm long may be used as a critical orifice to yield a flow rate 
of approximately 1 L/min for a 30-minute sampling period. When sampling 
for 1 hour, a 23-gauge hypodermic needle 16 mm in length will provide a 
flow rate of approximately 0.5 L/min. Flow control for a 24-hour sample 
may be provided by a 27-gauge hypodermic needle critical orifice that is 
9.5 mm in length. The flow rate should be in the range of 0.18 to 0.22 
L/min.
    7.1.7 Flow measurement device: Device calibrated as specified in 
9.4.1 and used to measure sample flow rate at the monitoring site.
    7.1.8 Membrane particle filter: A membrane filter of 0.8 to 2 
[micro]m porosity is used to protect the flow controller from particles 
during long-term sampling. This item is optional for short-term 
sampling.
    7.1.9 Vacuum pump: A vacuum pump equipped with a vacuum gauge and 
capable of maintaining at least 70 kPa (0.7 atm) vacuum differential 
across the flow control device at the specified flow rate is required 
for sampling.
    7.1.10 Temperature control device: The temperature of the absorbing 
solution during sampling must be maintained at 15[deg] 10 [deg]C. As soon as possible following sampling and 
until analysis, the temperature of the collected sample must be 
maintained at 5[deg] 5 [deg]C. Where an extended 
period of time may elapse before the collected sample can be moved to 
the lower storage temperature, a collection temperature near the lower 
limit of the 15 10 [deg]C range should be used to 
minimize losses during this period. Thermoelectric coolers specifically 
designed for this temperature control are available commercially and 
normally operate in the range of 5[deg] to 15 [deg]C. Small 
refrigerators can be modified to provide the required temperature 
control; however, inlet lines must be insulated from the lower 
temperatures to prevent condensation when sampling under humid 
conditions. A small heating pad may be necessary when sampling at low 
temperatures (<7 [deg]C) to prevent the absorbing solution from 
freezing.(17)
    7.1.11 Sampling train container: The absorbing solution must be 
shielded from light during and after sampling. Most commercially 
available sampler trains are enclosed in a light-proof box.
    7.1.12 Timer: A timer is recommended to initiate and to stop 
sampling for the 24-hour period. The timer is not a required piece of 
equipment; however, without the timer a technician would be required to 
start and stop the sampling manually. An elapsed time meter is also 
recommended to determine the duration of the sampling period.
    7.2 Shipping.
    7.2.1 Shipping container: A shipping container that can maintain a 
temperature of 5[deg] 5 [deg]C is used for 
transporting the sample from the collection site to the analytical 
laboratory. Ice coolers or refrigerated shipping containers have been 
found to be satisfactory. The use of eutectic cold packs instead of ice 
will give a more stable temperature control. Such equipment is available 
from Cole-Parmer Company, 7425 North Oak Park Avenue, Chicago, IL 60648.
    7.3 Analysis.
    7.3.1 Spectrophotometer: A spectrophotometer suitable for 
measurement of absorbances at 548 nm with an effective spectral 
bandwidth of less than 15 nm is required for analysis. If the 
spectrophotometer reads out in transmittance, convert to absorbance as 
follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.000

where:

A = absorbance, and
T = transmittance (0<=T<1).

    A standard wavelength filter traceable to the National Bureau of 
Standards is used to verify the wavelength calibration according to the 
procedure enclosed with the filter. The wavelength calibration must be 
verified upon initial receipt of the instrument and after each 160 hours 
of normal use or every 6 months, whichever occurs first.
    7.3.2 Spectrophotometer cells: A set of 1-cm path length cells 
suitable for use in the visible region is used during analysis. If the 
cells are unmatched, a matching correction factor must be determined 
according to Section 10.1.
    7.3.3 Temperature control device: The color development step during 
analysis must be conducted in an environment that is in the range of 
20[deg] to 30 [deg]C and controlled to 1 [deg]C. 
Both calibration and sample analysis must be performed under identical 
conditions (within 1 [deg]C). Adequate temperature control may be 
obtained by means of constant temperature baths, water baths with manual 
temperature control, or temperature controlled rooms.
    7.3.4 Glassware: Class A volumetric glassware of various capacities 
is required for preparing and standardizing reagents and standards and 
for dispensing solutions during analysis. These included pipets, 
volumetric flasks, and burets.
    7.3.5 TCM waste receptacle: A glass waste receptacle is required for 
the storage of spent TCM solution. This vessel should be stoppered and 
stored in a hood at all times.
    8.0 Reagents.
    8.1 Sampling.
    8.1.1 Distilled water: Purity of distilled water must be verified by 
the following procedure:(18)
 Place 0.20 mL of potassium permanganate solution 
(0.316 g/L), 500 mL of distilled water, and 1mL of concentrated sulfuric 
acid in a chemically resistant glass bottle, stopper the bottle, and 
allow to stand.

[[Page 14]]

 If the permanganate color (pink) does not disappear 
completely after a period of 1 hour at room temperature, the water is 
suitable for use.
 If the permanganate color does disappear, the water 
can be purified by redistilling with one crystal each of barium 
hydroxide and potassium permanganate in an all glass still.

    8.1.2 Absorbing reagent (0.04 M potassium tetrachloromercurate 
[TCM]): Dissolve 10.86 g mercuric chloride, 0.066 g EDTA, and 6.0 g 
potassium chloride in distilled water and dilute to volume with 
distilled water in a 1,000-mL volumetric flask. (Caution: Mercuric 
chloride is highly poisonous. If spilled on skin, flush with water 
immediately.) The pH of this reagent should be between 3.0 and 5.0 (10) 
Check the pH of the absorbing solution by using pH indicating paper or a 
pH meter. If the pH of the solution is not between 3.0 and 5.0, dispose 
of the solution according to one of the disposal techniques described in 
Section 13.0. The absorbing reagent is normally stable for 6 months. If 
a precipitate forms, dispose of the reagent according to one of the 
procedures described in Section 13.0.
    8.2 Analysis.
    8.2.1 Sulfamic acid (0.6%): Dissolve 0.6 g sulfamic acid in 100 mL 
distilled water. Perpare fresh daily.
    8.2.2 Formaldehyde (0.2%): Dilute 5 mL formaldehyde solution (36 to 
38 percent) to 1,000 mL with distilled water. Prepare fresh daily.
    8.2.3 Stock iodine solution (0.1 N): Place 12.7 g resublimed iodine 
in a 250-mL beaker and add 40 g potassium iodide and 25 mL water. Stir 
until dissolved, transfer to a 1,000 mL volumetric flask and dilute to 
volume with distilled water.
    8.2.4 Iodine solution (0.01 N): Prepare approximately 0.01 N iodine 
solution by diluting 50 mL of stock iodine solution (Section 8.2.3) to 
500 mL with distilled water.
    8.2.5 Starch indicator solution: Triturate 0.4 g soluble starch and 
0.002 g mercuric iodide (preservative) with enough distilled water to 
form a paste. Add the paste slowly to 200 mL of boiling distilled water 
and continue boiling until clear. Cool and transfer the solution to a 
glass stopperd bottle.
    8.2.6 1 N hydrochloric acid: Slowly and while stirring, add 86 mL of 
concentrated hydrochloric acid to 500 mL of distilled water. Allow to 
cool and dilute to 1,000 mL with distilled water.
    8.2.7 Potassium iodate solution: Accurately weigh to the nearest 0.1 
mg, 1.5 g (record weight) of primary standard grade potassium iodate 
that has been previously dried at 180 [deg]C for at least 3 hours and 
cooled in a dessicator. Dissolve, then dilute to volume in a 500-mL 
volumetric flask with distilled water.
    8.2.8 Stock sodium thiosulfate solution (0.1 N): Prepare a stock 
solution by dissolving 25 g sodium thiosulfate (Na2 
S2 O3/5H2 O) in 1,000 mL freshly 
boiled, cooled, distilled water and adding 0.1 g sodium carbonate to the 
solution. Allow the solution to stand at least 1 day before 
standardizing. To standardize, accurately pipet 50 mL of potassium 
iodate solution (Section 8.2.7) into a 500-mL iodine flask and add 2.0 g 
of potassium iodide and 10 mL of 1 N HCl. Stopper the flask and allow to 
stand for 5 minutes. Titrate the solution with stock sodium thiosulfate 
solution (Section 8.2.8) to a pale yellow color. Add 5 mL of starch 
solution (Section 8.2.5) and titrate until the blue color just 
disappears. Calculate the normality (Ns) of the stock sodium 
thiosulfate solution as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.001

where:

M = volume of thiosulfate required in mL, and
W = weight of potassium iodate in g (recorded weight in Section 8.2.7).
[GRAPHIC] [TIFF OMITTED] TC08NO91.002

    8.2.9 Working sodium thiosulfate titrant (0.01 N): Accurately pipet 
100 mL of stock sodium thiosulfate solution (Section 8.2.8) into a 
1,000-mL volumetric flask and dilute to volume with freshly boiled, 
cooled, distilled water. Calculate the normality of the working sodium 
thiosulfate titrant (NT) as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.003

    8.2.10 Standardized sulfite solution for the preparation of working 
sulfite-TCM solution: Dissolve 0.30 g sodium metabisulfite 
(Na2 S2 O5) or 0.40 g sodium sulfite 
(Na2 SO3) in 500 mL of recently boiled, cooled, 
distilled water. (Sulfite solution is unstable; it is therefore 
important to use water of the highest purity to minimize this 
instability.) This solution contains the equivalent of 320 to 400 
[micro]g SO2/mL. The actual concentration of the solution is 
determined by adding excess iodine and back-titrating with standard 
sodium thiosulfate solution. To back-titrate, pipet 50 mL of the 0.01 N 
iodine solution (Section 8.2.4) into each of two 500-mL iodine flasks (A 
and B). To flask A (blank) add 25 mL distilled water, and to flask B 
(sample) pipet 25 mL sulfite solution. Stopper the flasks and allow to 
stand for 5 minutes. Prepare the working sulfite-TCM solution (Section 
8.2.11) immediately prior to adding the iodine solution to the flasks. 
Using a buret containing standardized 0.01 N thiosulfate titrant 
(Section 8.2.9), titrate the solution in each flask to a pale yellow 
color. Then add 5

[[Page 15]]

mL starch solution (Section 8.2.5) and continue the titration until the 
blue color just disappears.
    8.2.11 Working sulfite-TCM solution: Accurately pipet 5 mL of the 
standard sulfite solution (Section 8.2.10) into a 250-mL volumetric 
flask and dilute to volume with 0.04 M TCM. Calculate the concentration 
of sulfur dioxide in the working solution as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.004

where:

A = volume of thiosulfate titrant required for the blank, mL;
B = volume of thiosulfate titrant required for the sample, mL;
NT = normality of the thiosulfate titrant, from equation (3);
32,000 = milliequivalent weight of SO2, [micro]g;
25 = volume of standard sulfite solution, mL; and
0.02 = dilution factor.

    This solution is stable for 30 days if kept at 5 [deg]C. (16) If not 
kept at 5 [deg]C, prepare fresh daily.
    8.2.12 Purified pararosaniline (PRA) stock solution (0.2% nominal):
    8.2.12.1 Dye specifications--

 The dye must have a maximum absorbance at a 
wavelength of 540 nm when assayed in a buffered solution of 0.1 M sodium 
acetate-acetic acid;
 The absorbance of the reagent blank, which is 
temperature sensitive (0.015 absorbance unit/ [deg]C), must not exceed 
0.170 at 22 [deg]C with a 1-cm optical path length when the blank is 
prepared according to the specified procedure;
 The calibration curve (Section 10.0) must have a 
slope equal to 0.030 0.002 absorbance unit/
[micro]g SO2 with a 1-cm optical path length when the dye is 
pure and the sulfite solution is properly standardized.

    8.2.12.2 Preparation of stock PRA solution--A specially purified (99 
to 100 percent pure) solution of pararosaniline, which meets the above 
specifications, is commercially available in the required 0.20 percent 
concentration (Harleco Co.). Alternatively, the dye may be purified, a 
stock solution prepared, and then assayed according to the procedure as 
described below.(10)
    8.2.12.3 Purification procedure for PRA--
    1. Place 100 mL each of 1-butanol and 1 N HCl in a large separatory 
funnel (250-mL) and allow to equilibrate. Note: Certain batches of 1-
butanol contain oxidants that create an SO2 demand. Before 
using, check by placing 20 mL of 1-butanol and 5 mL of 20 percent 
potassium iodide (KI) solution in a 50-mL separatory funnel and shake 
thoroughly. If a yellow color appears in the alcohol phase, redistill 
the 1-butanol from silver oxide and collect the middle fraction or 
purchase a new supply of 1-butanol.
    2. Weigh 100 mg of pararosaniline hydrochloride dye (PRA) in a small 
beaker. Add 50 mL of the equilibrated acid (drain in acid from the 
bottom of the separatory funnel in 1.) to the beaker and let stand for 
several minutes. Discard the remaining acid phase in the separatory 
funnel.
    3. To a 125-mL separatory funnel, add 50 mL of the equilibrated 1-
butanol (draw the 1-butanol from the top of the separatory funnel in 
1.). Transfer the acid solution (from 2.) containing the dye to the 
funnel and shake carefully to extract. The violet impurity will transfer 
to the organic phase.
    4. Transfer the lower aqueous phase into another separatory funnel, 
add 20 mL of equilibrated 1-butanol, and extract again.
    5. Repeat the extraction procedure with three more 10-mL portions of 
equilibrated 1-butanol.
    6. After the final extraction, filter the acid phase through a 
cotton plug into a 50-mL volumetric flask and bring to volume with 1 N 
HCl. This stock reagent will be a yellowish red.
    7. To check the purity of the PRA, perform the assay and adjustment 
of concentration (Section 8.2.12.4) and prepare a reagent blank (Section 
11.2); the absorbance of this reagent blank at 540 nm should be less 
than 0.170 at 22 [deg]C. If the absorbance is greater than 0.170 under 
these conditions, further extractions should be performed.
    8.2.12.4 PRA assay procedure--The concentration of pararosaniline 
hydrochloride (PRA) need be assayed only once after purification. It is 
also recommended that commercial solutions of pararosaniline be assayed 
when first purchased. The assay procedure is as follows:(10)
    1. Prepare 1 M acetate-acetic acid buffer stock solution with a pH 
of 4.79 by dissolving 13.61 g of sodium acetate trihydrate in distilled 
water in a 100-mL volumetric flask. Add 5.70 mL of glacial acetic acid 
and dilute to volume with distilled water.
    2. Pipet 1 mL of the stock PRA solution obtained from the 
purification process or from a commercial source into a 100-mL 
volumetric flask and dilute to volume with distilled water.

[[Page 16]]

    3. Transfer a 5-mL aliquot of the diluted PRA solution from 2. into 
a 50-mL volumetric flask. Add 5mL of 1 M acetate-acetic acid buffer 
solution from 1. and dilute the mixture to volume with distilled water. 
Let the mixture stand for 1 hour.
    4. Measure the absorbance of the above solution at 540 nm with a 
spectrophotometer against a distilled water reference. Compute the 
percentage of nominal concentration of PRA by
[GRAPHIC] [TIFF OMITTED] TC08NO91.005

where:

A = measured absorbance of the final mixture (absorbance units);
W = weight in grams of the PRA dye used in the assay to prepare 50 mL of 
stock solution (for example, 0.100 g of dye was used to prepare 50 mL of 
solution in the purification procedure; when obtained from commercial 
sources, use the stated concentration to compute W; for 98% PRA, W=.098 
g.); and
K = 21.3 for spectrophotometers having a spectral bandwidth of less than 
15 nm and a path length of 1 cm.

    8.2.13 Pararosaniline reagent: To a 250-mL volumetric flask, add 20 
mL of stock PRA solution. Add an additional 0.2 mL of stock solution for 
each percentage that the stock assays below 100 percent. Then add 25 mL 
of 3 M phosphoric acid and dilute to volume with distilled water. The 
reagent is stable for at least 9 months. Store away from heat and light.
    9.0 Sampling Procedure.
    9.1 General Considerations. Procedures are described for short-term 
sampling (30-minute and 1-hour) and for long-term sampling (24-hour). 
Different combinations of absorbing reagent volume, sampling rate, and 
sampling time can be selected to meet special needs. For combinations 
other than those specifically described, the conditions must be adjusted 
so that linearity is maintained between absorbance and concentration 
over the dynamic range. Absorbing reagent volumes less than 10 mL are 
not recommended. The collection efficiency is above 98 percent for the 
conditions described; however, the efficiency may be substantially lower 
when sampling concentrations below 25 [micro][gamma]SO2/
m\3\.(8,9)
    9.2 30-Minute and 1-Hour Sampling. Place 10 mL of TCM absorbing 
reagent in a midget impinger and seal the impinger with a thin film of 
silicon stopcock grease (around the ground glass joint). Insert the 
sealed impinger into the sampling train as shown in Figure 1, making 
sure that all connections between the various components are leak tight. 
Greaseless ball joint fittings, heat shrinkable Teflon[reg] 
tubing, or Teflon[reg] tube fittings may be used to attain 
leakfree conditions for portions of the sampling train that come into 
contact with air containing SO2. Shield the absorbing reagent 
from direct sunlight by covering the impinger with aluminum foil or by 
enclosing the sampling train in a light-proof box. Determine the flow 
rate according to Section 9.4.2. Collect the sample at 1 0.10 L/min for 30-minute sampling or 0.500 0.05 L/min for 1-hour sampling. Record the exact 
sampling time in minutes, as the sample volume will later be determined 
using the sampling flow rate and the sampling time. Record the 
atmospheric pressure and temperature.
    9.3 24-Hour Sampling. Place 50 mL of TCM absorbing solution in a 
large absorber, close the cap, and, if needed, apply the heat shrink 
material as shown in Figure 3. Verify that the reagent level is at the 
50 mL mark on the absorber. Insert the sealed absorber into the sampling 
train as shown in Figure 2. At this time verify that the absorber 
temperature is controlled to 15 10 [deg]C. During 
sampling, the absorber temperature must be controlled to prevent 
decomposition of the collected complex. From the onset of sampling until 
analysis, the absorbing solution must be protected from direct sunlight. 
Determine the flow rate according to Section 9.4.2. Collect the sample 
for 24 hours from midnight to midnight at a flow rate of 0.200 0.020 L/min. A start/stop timer is helpful for 
initiating and stopping sampling and an elapsed time meter will be 
useful for determining the sampling time.

[[Page 17]]



    9.4 Flow Measurement.
    9.4.1 Calibration: Flow measuring devices used for the on-site flow 
measurements required in 9.4.2 must be calibrated against a reliable 
flow or volume standard such as an NBS traceable bubble flowmeter or 
calibrated wet test meter. Rotameters or critical orifices used in the 
sampling train may be calibrated, if desired, as a quality control 
check, but such calibration shall not replace the on-site flow 
measurements required by 9.4.2. In-line rotameters, if they are to be 
calibrated, should be calibrated in situ, with the appropriate volume of 
solution in the absorber.
    9.4.2 Determination of flow rate at sampling site: For short-term 
samples, the standard flow rate is determined at the sampling site at 
the initiation and completion of sample collection with a calibrated 
flow measuring device connected to the inlet of the absorber. For 24-
hour samples, the standard flow rate is determined at the time the 
absorber is placed in the sampling train and again when the absorber is 
removed from the train for shipment to the analytical laboratory with a 
calibrated flow measuring device connected to the inlet of the sampling 
train. The flow rate determination must be made with all components of 
the sampling system in operation (e.g., the absorber temperature 
controller and any sample box heaters must also be operating). Equation 
6 may be used to determine the standard flow rate when a calibrated 
positive displacement meter is used as the flow measuring device. Other 
types of calibrated flow measuring devices may also be used to determine 
the flow rate at the sampling site provided that the user applies any 
appropriate corrections to devices for which output is dependent on 
temperature or pressure.

[[Page 18]]

[GRAPHIC] [TIFF OMITTED] TC08NO91.006

where:

Qstd = flow rate at standard conditions, std L/min (25 [deg]C 
and 760 mm Hg);
Qact = flow rate at monitoring site conditions, L/min;
Pb = barometric pressure at monitoring site conditions, mm Hg 
or kPa;
RH = fractional relative humidity of the air being measured;
PH2O = vapor pressure of water at the temperature 
of the air in the flow or volume standard, in the same units as 
Pb, (for wet volume standards only, i.e., bubble flowmeter or 
wet test meter; for dry standards, i.e., dry test meter, 
PH2O=0);
Pstd = standard barometric pressure, in the same units as 
Pb (760 mm Hg or 101 kPa); and
Tmeter = temperature of the air in the flow or volume 
standard, [deg]C (e.g., bubble flowmeter).

    If a barometer is not available, the following equation may be used 
to determine the barometric pressure:
[GRAPHIC] [TIFF OMITTED] TC08NO91.007

where:

H = sampling site elevation above sea level in meters.

    If the initial flow rate (Qi) differs from the flow rate 
of the critical orifice or the flow rate indicated by the flowmeter in 
the sampling train (Qc) by more than 5 percent as determined 
by equation (8), check for leaks and redetermine Qi.
[GRAPHIC] [TIFF OMITTED] TC08NO91.008

    Invalidate the sample if the difference between the initial 
(Qi) and final (Qf) flow rates is more than 5 
percent as determined by equation (9):
[GRAPHIC] [TIFF OMITTED] TC08NO91.009

    9.5 Sample Storage and Shipment. Remove the impinger or absorber 
from the sampling train and stopper immediately. Verify that the 
temperature of the absorber is not above 25 [deg]C. Mark the level of 
the solution with a temporary (e.g., grease pencil) mark. If the sample 
will not be analyzed within 12 hours of sampling, it must be stored at 
5[deg] 5 [deg]C until analysis. Analysis must 
occur within 30 days. If the sample is transported or shipped for a 
period exceeding 12 hours, it is recommended that thermal coolers using 
eutectic ice packs, refrigerated shipping containers, etc., be used for 
periods up to 48 hours. (17) Measure the temperature of the absorber 
solution when the shipment is received. Invalidate the sample if the 
temperature is above 10 [deg]C. Store the sample at 5[deg] 5 [deg]C until it is analyzed.
    10.0 Analytical Calibration.
    10.1 Spectrophotometer Cell Matching. If unmatched spectrophotometer 
cells are used, an absorbance correction factor must be determined as 
follows:
    1. Fill all cells with distilled water and designate the one that 
has the lowest absorbance at 548 nm as the reference. (This reference 
cell should be marked as such and continually used for this purpose 
throughout all future analyses.)
    2. Zero the spectrophotometer with the reference cell.
    3. Determine the absorbance of the remaining cells (Ac) 
in relation to the reference cell and record these values for future 
use. Mark all cells in a manner that adequately identifies the 
correction.
    The corrected absorbance during future analyses using each cell is 
determining as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.010

where:

A = corrected absorbance,
Aobs = uncorrected absorbance, and
Ac = cell correction.

    10.2 Static Calibration Procedure (Option 1). Prepare a dilute 
working sulfite-TCM solution by diluting 10 mL of the working sulfite-
TCM solution (Section 8.2.11) to 100 mL with TCM absorbing reagent. 
Following the table below, accurately pipet the indicated volumes of the 
sulfite-TCM solutions into a series of 25-mL volumetric flasks. Add TCM 
absorbing reagent as indicated to bring the volume in each flask to 10 
mL.

[[Page 19]]



------------------------------------------------------------------------
                                         Volume of               Total
                                          sulfite-  Volume of   [micro]g
          Sulfite-TCM solution              TCM      TCM, mL      SO2
                                          solution             (approx.*
------------------------------------------------------------------------
Working................................        4.0        6.0       28.8
Working................................        3.0        7.0       21.6
Working................................        2.0        8.0       14.4
Dilute working.........................       10.0        0.0        7.2
Dilute working.........................        5.0        5.0        3.6
                                               0.0       10.0        0.0
------------------------------------------------------------------------
*Based on working sulfite-TCM solution concentration of 7.2 [micro]g SO2/
  mL; the actual total [micro]g SO2 must be calculated using equation 11
  below.

    To each volumetric flask, add 1 mL 0.6% sulfamic acid (Section 
8.2.1), accurately pipet 2 mL 0.2% formaldehyde solution (Section 
8.2.2), then add 5 mL pararosaniline solution (Section 8.2.13). Start a 
laboratory timer that has been set for 30 minutes. Bring all flasks to 
volume with recently boiled and cooled distilled water and mix 
thoroughly. The color must be developed (during the 30-minute period) in 
a temperature environment in the range of 20[deg] to 30 [deg]C, which is 
controlled to 1 [deg]C. For increased precision, a 
constant temperature bath is recommended during the color development 
step. After 30 minutes, determine the corrected absorbance of each 
standard at 548 nm against a distilled water reference (Section 10.1). 
Denote this absorbance as (A). Distilled water is used in the reference 
cell rather than the reagant blank because of the temperature 
sensitivity of the reagent blank. Calculate the total micrograms 
SO2 in each solution:
[GRAPHIC] [TIFF OMITTED] TC08NO91.011

where:

VTCM/SO2 = volume of sulfite-TCM solution used, mL;
CTCM/SO2 = concentration of sulfur dioxide in the working 
sulfite-TCM, [micro]g SO2/mL (from equation 4); and
D = dilution factor (D = 1 for the working sulfite-TCM solution; D = 0.1 
for the diluted working sulfite-TCM solution).

    A calibration equation is determined using the method of linear 
least squares (Section 12.1). The total micrograms SO2 
contained in each solution is the x variable, and the corrected 
absorbance (eq. 10) associated with each solution is the y variable. For 
the calibration to be valid, the slope must be in the range of 0.030 
0.002 absorbance unit/[micro]g SO2, the 
intercept as determined by the least squares method must be equal to or 
less than 0.170 absorbance unit when the color is developed at 22 [deg]C 
(add 0.015 to this 0.170 specification for each [deg]C above 22 [deg]C) 
and the correlation coefficient must be greater than 0.998. If these 
criteria are not met, it may be the result of an impure dye and/or an 
improperly standardized sulfite-TCM solution. A calibration factor 
(Bs) is determined by calculating the reciprocal of the slope 
and is subsequently used for calculating the sample concentration 
(Section 12.3).
    10.3 Dynamic Calibration Procedures (Option 2). Atmospheres 
containing accurately known concentrations of sulfur dioxide are 
prepared using permeation devices. In the systems for generating these 
atmospheres, the permeation device emits gaseous SO2 at a 
known, low, constant rate, provided the temperature of the device is 
held constant (0.1 [deg]C) and the device has been 
accurately calibrated at the temperature of use. The SO2 
permeating from the device is carried by a low flow of dry carrier gas 
to a mixing chamber where it is diluted with SO2-free air to 
the desired concentration and supplied to a vented manifold. A typical 
system is shown schematically in Figure 4 and this system and other 
similar systems have been described in detail by O'Keeffe and Ortman; 
(19) Scaringelli, Frey, and Saltzman, (20) and Scaringelli, O'Keeffe, 
Rosenberg, and Bell. (21) Permeation devices may be prepared or 
purchased and in both cases must be traceable either to a National 
Bureau of Standards (NBS) Standard Reference Material (SRM 1625, SRM 
1626, SRM 1627) or to an NBS/EPA-approved commercially available 
Certified Reference Material (CRM). CRM's are described in Reference 22, 
and a list of CRM sources is available from the address shown for 
Reference 22. A recommended protocol for certifying a permeation device 
to an NBS SRM or CRM is given in Section 2.0.7 of Reference 2. Device 
permeation rates of 0.2 to 0.4 [micro]g/min, inert gas flows of about 50 
mL/min, and dilution air flow rates from 1.1 to 15 L/min conveniently 
yield standard atmospheres in the range of 25 to 600 [micro]g 
SO2/m\3\ (0.010 to 0.230 ppm).
    10.3.1 Calibration Option 2A (30-minute and 1-hour samples): 
Generate a series of six standard atmospheres of SO2 (e.g., 
0, 50, 100, 200, 350, 500, 750 [micro]g/m\3\) by adjusting the dilution 
flow rates appropriately. The concentration of SO2 in each 
atmosphere is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.014

where:


[[Page 20]]


Ca = concentration of SO2 at standard conditions, 
[micro]g/m\3\;
Pr = permeation rate, [micro]g/min;
Qd = flow rate of dilution air, std L/min; and
Qp = flow rate of carrier gas across permeation device, std 
L/min.



[[Page 21]]


    Be sure that the total flow rate of the standard exceeds the flow 
demand of the sample train, with the excess flow vented at atmospheric 
pressure. Sample each atmosphere using similar apparatus as shown in 
Figure 1 and under the same conditions as field sampling (i.e., use same 
absorbing reagent volume and sample same volume of air at an equivalent 
flow rate). Due to the length of the sampling periods required, this 
method is not recommended for 24-hour sampling. At the completion of 
sampling, quantitatively transfer the contents of each impinger to one 
of a series of 25-mL volumetric flasks (if 10 mL of absorbing solution 
was used) using small amounts of distilled water for rinse (<5mL). If 
10 mL of absorbing solution was used, bring the absorber 
solution in each impinger to orginal volume with distilled H2 
O and pipet 10-mL portions from each impinger into a series of 25-mL 
volumetric flasks. If the color development steps are not to be started 
within 12 hours of sampling, store the solutions at 5[deg] 5 [deg]C. Calculate the total micrograms SO2 
in each solution as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.015

where:

Ca = concentration of SO2 in the standard 
atmosphere, [micro]g/m\3\;
Os = sampling flow rate, std L/min;
t=sampling time, min;
Va = volume of absorbing solution used for color development 
(10 mL); and
Vb = volume of absorbing solution used for sampling, mL.

    Add the remaining reagents for color development in the same manner 
as in Section 10.2 for static solutions. Calculate a calibration 
equation and a calibration factor (Bg) according to Section 
10.2, adhering to all the specified criteria.
    10.3.2 Calibration Option 2B (24-hour samples): Generate a standard 
atmosphere containing approximately 1,050 [micro]g SO2/m\3\ 
and calculate the exact concentration according to equation 12. Set up a 
series of six absorbers according to Figure 2 and connect to a common 
manifold for sampling the standard atmosphere. Be sure that the total 
flow rate of the standard exceeds the flow demand at the sample 
manifold, with the excess flow vented at atmospheric pressure. The 
absorbers are then allowed to sample the atmosphere for varying time 
periods to yield solutions containing 0, 0.2, 0.6, 1.0, 1.4, 1.8, and 
2.2 [micro]g SO2/mL solution. The sampling times required to 
attain these solution concentrations are calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.016

where:

t = sampling time, min;
Vb = volume of absorbing solution used for sampling (50 mL);
Cs = desired concentration of SO2 in the absorbing 
solution, [micro]g/mL;
Ca = concentration of the standard atmosphere calculated 
according to equation 12, [micro]g/m\3\; and
Qs = sampling flow rate, std L/min.

    At the completion of sampling, bring the absorber solutions to 
original volume with distilled water. Pipet a 10-mL portion from each 
absorber into one of a series of 25-mL volumetric flasks. If the color 
development steps are not to be started within 12 hours of sampling, 
store the solutions at 5[deg] 5 [deg]C. Add the 
remaining reagents for color development in the same manner as in 
Section 10.2 for static solutions. Calculate the total [micro]g 
SO2 in each standard as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.017

where:

Va = volume of absorbing solution used for color development 
(10 mL).
All other parameters are defined in equation 14.

    Calculate a calibration equation and a calibration factor 
(Bt) according to Section 10.2 adhering to all the specified 
criteria.
    11.0 Sample Preparation and Analysis.
    11.1 Sample Preparation. Remove the samples from the shipping 
container. If the shipment period exceeded 12 hours from the completion 
of sampling, verify that the temperature is below 10 [deg]C. Also, 
compare the solution level to the temporary level mark on the absorber. 
If either the temperature is above 10 [deg]C or there was significant 
loss (more than 10 mL) of the sample during shipping, make an 
appropriate notation in the record and invalidate the sample. Prepare 
the samples for analysis as follows:
    1. For 30-minute or 1-hour samples: Quantitatively transfer the 
entire 10 mL amount of absorbing solution to a 25-mL volumetric flask 
and rinse with a small amount (<5 mL) of distilled water.
    2. For 24-hour samples: If the volume of the sample is less than the 
original 50-mL volume (permanent mark on the absorber), adjust the 
volume back to the original volume with distilled water to compensate 
for water lost to evaporation during sampling. If the final volume is 
greater than the original volume, the volume must be measured using a 
graduated cylinder. To analyze, pipet 10 mL

[[Page 22]]

of the solution into a 25-mL volumetric flask.
    11.2 Sample Analysis. For each set of determinations, prepare a 
reagent blank by adding 10 mL TCM absorbing solution to a 25-mL 
volumetric flask, and two control standards containing approximately 5 
and 15 [micro]g SO2, respectively. The control standards are 
prepared according to Section 10.2 or 10.3. The analysis is carried out 
as follows:
    1. Allow the sample to stand 20 minutes after the completion of 
sampling to allow any ozone to decompose (if applicable).
    2. To each 25-mL volumetric flask containing reagent blank, sample, 
or control standard, add 1 mL of 0.6% sulfamic acid (Section 8.2.1) and 
allow to react for 10 min.
    3. Accurately pipet 2 mL of 0.2% formaldehyde solution (Section 
8.2.2) and then 5 mL of pararosaniline solution (Section 8.2.13) into 
each flask. Start a laboratory timer set at 30 minutes.
    4. Bring each flask to volume with recently boiled and cooled 
distilled water and mix thoroughly.
    5. During the 30 minutes, the solutions must be in a temperature 
controlled environment in the range of 20[deg] to 30 [deg]C maintained 
to 1 [deg]C. This temperature must also be within 
1 [deg]C of that used during calibration.
    6. After 30 minutes and before 60 minutes, determine the corrected 
absorbances (equation 10) of each solution at 548 nm using 1-cm optical 
path length cells against a distilled water reference (Section 10.1). 
(Distilled water is used as a reference instead of the reagent blank 
because of the sensitivity of the reagent blank to temperature.)
    7. Do not allow the colored solution to stand in the cells because a 
film may be deposited. Clean the cells with isopropyl alcohol after use.
    8. The reagent blank must be within 0.03 absorbance units of the 
intercept of the calibration equation determined in Section 10.
    11.3 Absorbance range. If the absorbance of the sample solution 
ranges between 1.0 and 2.0, the sample can be diluted 1:1 with a portion 
of the reagent blank and the absorbance redetermined within 5 minutes. 
Solutions with higher absorbances can be diluted up to sixfold with the 
reagent blank in order to obtain scale readings of less than 1.0 
absorbance unit. However, it is recommended that a smaller portion (<10 
mL) of the original sample be reanalyzed (if possible) if the sample 
requires a dilution greater than 1:1.
    11.4 Reaqent disposal. All reagents containing mercury compounds 
must be stored and disposed of using one of the procedures contained in 
Section 13. Until disposal, the discarded solutions can be stored in 
closed glass containers and should be left in a fume hood.
    12.0 Calculations.
    12.1 Calibration Slope, Intercept, and Correlation Coefficient. The 
method of least squares is used to calculate a calibration equation in 
the form of:
[GRAPHIC] [TIFF OMITTED] TC08NO91.012

where:

y = corrected absorbance,
m = slope, absorbance unit/[micro]g SO2,
x = micrograms of SO2,
b = y intercept (absorbance units).

    The slope (m), intercept (b), and correlation coefficient (r) are 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.018

[GRAPHIC] [TIFF OMITTED] TR31AU93.019

[GRAPHIC] [TIFF OMITTED] TR31AU93.020

where n is the number of calibration points.
    A data form (Figure 5) is supplied for easily organizing calibration 
data when the slope, intercept, and correlation coefficient are 
calculated by hand.
    12.2 Total Sample Volume. Determine the sampling volume at standard 
conditions as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.021

where:

Vstd = sampling volume in std L,
Qi = standard flow rate determined at the initiation of 
sampling in std L/min,
Qf = standard flow rate determined at the completion of 
sampling is std L/min, and
t = total sampling time, min.

    12.3 Sulfur Dioxide Concentration. Calculate and report the 
concentration of each sample as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.022

where:

A = corrected absorbance of the sample solution, from equation (10);
Ao = corrected absorbance of the reagent blank, using 
equation (10);
BX = calibration factor equal to Bs, 
Bg, or Bt depending on the calibration procedure 
used, the reciprocal of the slope of the calibration equation;
Va = volume of absorber solution analyzed, mL;
Vb = total volume of solution in absorber (see 11.1-2), mL; 
and
Vstd = standard air volume sampled, std L (from Section 
12.2).

[[Page 23]]



                                                    Data Form
                                             [For hand calculations]
----------------------------------------------------------------------------------------------------------------
                                                      Absor- bance
     Calibration point no.       Micro- grams So2        units
----------------------------------------------------------------------------------------------------------------
                                       (x)                (y)                x\2\               xy          y\2\
1.............................  .................  .................  .................  ................  .....
2.............................  .................  .................  .................  ................  .....
3.............................  .................  .................  .................  ................  .....
4.............................  .................  .................  .................  ................  .....
5.............................  .................  .................  .................  ................  .....
6.............................  .................  .................  .................  ................  .....
----------------------------------------------------------------------------------------------------------------

[Sigma] x=------ [Sigma] y=------ [Sigma] x\2\=------ [Sigma]xy------ 
[Sigma]y\2\------
n=------ (number of pairs of coordinates.)
[fxsp0]_________________________________________________________________

Figure 5. Data form for hand calculations.

    12.4 Control Standards. Calculate the analyzed micrograms of 
SO2 in each control standard as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.070

where:

Cq = analyzed [micro]g SO2 in each control 
standard,
A = corrected absorbance of the control standard, and
Ao = corrected absorbance of the reagent blank.

    The difference between the true and analyzed values of the control 
standards must not be greater than 1 [micro]g. If the difference is 
greater than 1 [micro]g, the source of the discrepancy must be 
identified and corrected.
    12.5 Conversion of [micro]g/m\3\ to ppm (v/v). If desired, the 
concentration of sulfur dioxide at reference conditions can be converted 
to ppm SO2 (v/v) as follows:
[GRAPHIC] [TIFF OMITTED] TR31AU93.023

    13.0 The TCM absorbing solution and any reagents containing mercury 
compounds must be treated and disposed of by one of the methods 
discussed below. Both methods remove greater than 99.99 percent of the 
mercury.
    13.1 Disposal of Mercury-Containing Solutions.
    13.2 Method for Forming an Amalgam.
    1. Place the waste solution in an uncapped vessel in a hood.
    2. For each liter of waste solution, add approximately 10 g of 
sodium carbonate until neutralization has occurred (NaOH may have to be 
used).
    3. Following neutralization, add 10 g of granular zinc or magnesium.
    4. Stir the solution in a hood for 24 hours. Caution must be 
exercised as hydrogen gas is evolved by this treatment process.
    5. After 24 hours, allow the solution to stand without stirring to 
allow the mercury amalgam (solid black material) to settle to the bottom 
of the waste receptacle.
    6. Upon settling, decant and discard the supernatant liquid.
    7. Quantitatively transfer the solid material to a container and 
allow to dry.
    8. The solid material can be sent to a mercury reclaiming plant. It 
must not be discarded.
    13.3 Method Using Aluminum Foil Strips.
    1. Place the waste solution in an uncapped vessel in a hood.
    2. For each liter of waste solution, add approximately 10 g of 
aluminum foil strips. If all the aluminum is consumed and no gas is 
evolved, add an additional 10 g of foil. Repeat until the foil is no 
longer consumed and allow the gas to evolve for 24 hours.
    3. Decant the supernatant liquid and discard.
    4. Transfer the elemental mercury that has settled to the bottom of 
the vessel to a storage container.
    5. The mercury can be sent to a mercury reclaiming plant. It must 
not be discarded.
    14.0 References for SO2 Method.
    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume I, Principles. EPA-600/9-76-005, U.S. Environmental Protection 
Agency, Research Triangle Park, NC 27711, 1976.
    2. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume II, Ambient Air Specific Methods. EPA-600/4-77-027a, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711, 1977.
    3. Dasqupta, P. K., and K. B. DeCesare. Stability of Sulfur Dioxide 
in Formaldehyde and Its Anomalous Behavior in Tetrachloromercurate (II). 
Submitted for publication in Atmospheric Environment, 1982.
    4. West, P. W., and G. C. Gaeke. Fixation of Sulfur Dioxide as 
Disulfitomercurate (II) and Subsequent Colorimetric Estimation. Anal. 
Chem., 28:1816, 1956.
    5. Ephraim, F. Inorganic Chemistry. P. C. L. Thorne and E. R. 
Roberts, Eds., 5th Edition, Interscience, 1948, p. 562.
    6. Lyles, G. R., F. B. Dowling, and V. J. Blanchard. Quantitative 
Determination of Formaldehyde in the Parts Per Hundred Million 
Concentration Level. J. Air. Poll. Cont. Assoc., Vol. 15(106), 1965.
    7. McKee, H. C., R. E. Childers, and O. Saenz, Jr. Collaborative 
Study of Reference Method for Determination of Sulfur Dioxide in the 
Atmosphere (Pararosaniline Method). EPA-APTD-0903, U.S. Environmental 
Protection Agency, Research Triangle Park, NC 27711, September 1971.
    8. Urone, P., J. B. Evans, and C. M. Noyes. Tracer Techniques in 
Sulfur--Air Pollution Studies Apparatus and Studies of Sulfur Dioxide 
Colorimetric and Conductometric Methods. Anal. Chem., 37: 1104, 1965.

[[Page 24]]

    9. Bostrom, C. E. The Absorption of Sulfur Dioxide at Low 
Concentrations (pphm) Studied by an Isotopic Tracer Method. Intern. J. 
Air Water Poll., 9:333, 1965.
    10. Scaringelli, F. P., B. E. Saltzman, and S. A. Frey. 
Spectrophotometric Determination of Atmospheric Sulfur Dioxide. Anal. 
Chem., 39: 1709, 1967.
    11. Pate, J. B., B. E. Ammons, G. A. Swanson, and J. P. Lodge, Jr. 
Nitrite Interference in Spectrophotometric Determination of Atmospheric 
Sulfur Dioxide. Anal. Chem., 37:942, 1965.
    12. Zurlo, N., and A. M. Griffini. Measurement of the Sulfur Dioxide 
Content of the Air in the Presence of Oxides of Nitrogen and Heavy 
Metals. Medicina Lavoro, 53:330, 1962.
    13. Rehme, K. A., and F. P. Scaringelli. Effect of Ammonia on the 
Spectrophotometric Determination of Atmospheric Concentrations of Sulfur 
Dioxide. Anal. Chem., 47:2474, 1975.
    14. McCoy, R. A., D. E. Camann, and H. C. McKee. Collaborative Study 
of Reference Method for Determination of Sulfur Dioxide in the 
Atmosphere (Pararosaniline Method) (24-Hour Sampling). EPA-650/4-74-027, 
U.S. Environmental Protection Agency, Research Triangle Park, NC 27711, 
December 1973.
    15. Fuerst, R. G. Improved Temperature Stability of Sulfur Dioxide 
Samples Collected by the Federal Reference Method. EPA-600/4-78-018, 
U.S. Environmental Protection Agency, Research Triangle Park, NC 27711, 
April 1978.
    16. Scaringelli, F. P., L. Elfers, D. Norris, and S. Hochheiser. 
Enhanced Stability of Sulfur Dioxide in Solution. Anal. Chem., 42:1818, 
1970.
    17. Martin, B. E. Sulfur Dioxide Bubbler Temperature Study. EPA-600/
4-77-040, U.S. Environmental Protection Agency, Research Triangle Park, 
NC 27711, August 1977.
    18. American Society for Testing and Materials. ASTM Standards, 
Water; Atmospheric Analysis. Part 23. Philadelphia, PA, October 1968, p. 
226.
    19. O'Keeffe, A. E., and G. C. Ortman. Primary Standards for Trace 
Gas Analysis. Anal. Chem., 38:760, 1966.
    20. Scaringelli, F. P., S. A. Frey, and B. E. Saltzman. Evaluation 
of Teflon Permeation Tubes for Use with Sulfur Dioxide. Amer. Ind. 
Hygiene Assoc. J., 28:260, 1967.
    21. Scaringelli, F. P., A. E. O'Keeffe, E. Rosenberg, and J. P. 
Bell, Preparation of Known Concentrations of Gases and Vapors With 
Permeation Devices Calibrated Gravimetrically. Anal. Chem., 42:871, 
1970.
    22. A Procedure for Establishing Traceability of Gas Mixtures to 
Certain National Bureau of Standards Standard Reference Materials. EPA-
600/7-81-010, U.S. Environmental Protection Agency, Environmental 
Monitoring Systems Laboratory (MD-77), Research Triangle Park, NC 27711, 
January 1981.

[47 FR 54899, Dec. 6, 1982; 48 FR 17355, Apr. 22, 1983]

    Appendix B to Part 50--Reference Method for the Determination of 
   Suspended Particulate Matter in the Atmosphere (High-Volume Method)

    1.0 Applicability.
    1.1 This method provides a measurement of the mass concentration of 
total suspended particulate matter (TSP) in ambient air for determining 
compliance with the primary and secondary national ambient air quality 
standards for particulate matter as specified in Sec. 50.6 and Sec. 
50.7 of this chapter. The measurement process is nondestructive, and the 
size of the sample collected is usually adequate for subsequent chemical 
analysis. Quality assurance procedures and guidance are provided in part 
58, appendixes A and B, of this chapter and in References 1 and 2.
    2.0 Principle.
    2.1 An air sampler, properly located at the measurement site, draws 
a measured quantity of ambient air into a covered housing and through a 
filter during a 24-hr (nominal) sampling period. The sampler flow rate 
and the geometry of the shelter favor the collection of particles up to 
25-50 [micro]m (aerodynamic diameter), depending on wind speed and 
direction.(3) The filters used are specified to have a minimum 
collection efficiency of 99 percent for 0.3 [micro]m (DOP) particles 
(see Section 7.1.4).
    2.2 The filter is weighed (after moisture equilibration) before and 
after use to determine the net weight (mass) gain. The total volume of 
air sampled, corrected to EPA standard conditions (25 [deg]C, 760 mm Hg 
[101 kPa]), is determined from the measured flow rate and the sampling 
time. The concentration of total suspended particulate matter in the 
ambient air is computed as the mass of collected particles divided by 
the volume of air sampled, corrected to standard conditions, and is 
expressed in micrograms per standard cubic meter ([micro]g/std m\3\). 
For samples collected at temperatures and pressures significantly 
different than standard conditions, these corrected concentrations may 
differ substantially from actual concentrations (micrograms per actual 
cubic meter), particularly at high elevations. The actual particulate 
matter concentration can be calculated from the corrected concentration 
using the actual temperature and pressure during the sampling period.
    3.0 Range.
    3.1 The approximate concentration range of the method is 2 to 750 
[micro]g/std m\3\. The upper limit is determined by the point at which 
the sampler can no longer maintain the specified

[[Page 25]]

flow rate due to the increased pressure drop of the loaded filter. This 
point is affected by particle size distribution, moisture content of the 
collected particles, and variability from filter to filter, among other 
things. The lower limit is determined by the sensitivity of the balance 
(see Section 7.10) and by inherent sources of error (see Section 6).
    3.2 At wind speeds between 1.3 and 4.5 m/sec (3 and 10 mph), the 
high-volume air sampler has been found to collect particles up to 25 to 
50 [micro]m, depending on wind speed and direction.(3) For the filter 
specified in Section 7.1, there is effectively no lower limit on the 
particle size collected.
    4.0 Precision.
    4.1 Based upon collaborative testing, the relative standard 
deviation (coefficient of variation) for single analyst precision 
(repeatability) of the method is 3.0 percent. The corresponding value 
for interlaboratory precision (reproducibility) is 3.7 percent.(4)
    5.0 Accuracy.
    5.1 The absolute accuracy of the method is undefined because of the 
complex nature of atmospheric particulate matter and the difficulty in 
determining the ``true'' particulate matter concentration. This method 
provides a measure of particulate matter concentration suitable for the 
purpose specified under Section 1.0, Applicability.
    6.0 Inherent Sources of Error.
    6.1 Airflow variation. The weight of material collected on the 
filter represents the (integrated) sum of the product of the 
instantaneous flow rate times the instantaneous particle concentration. 
Therefore, dividing this weight by the average flow rate over the 
sampling period yields the true particulate matter concentration only 
when the flow rate is constant over the period. The error resulting from 
a nonconstant flow rate depends on the magnitude of the instantaneous 
changes in the flow rate and in the particulate matter concentration. 
Normally, such errors are not large, but they can be greatly reduced by 
equipping the sampler with an automatic flow controlling mechanism that 
maintains constant flow during the sampling period. Use of a contant 
flow controller is recommended.*
---------------------------------------------------------------------------

    *At elevated altitudes, the effectiveness of automatic flow 
controllers may be reduced because of a reduction in the maximum sampler 
flow.
---------------------------------------------------------------------------

    6.2 Air volume measurement. If the flow rate changes substantially 
or nonuniformly during the sampling period, appreciable error in the 
estimated air volume may result from using the average of the 
presampling and postsampling flow rates. Greater air volume measurement 
accuracy may be achieved by (1) equipping the sampler with a flow 
controlling mechanism that maintains constant air flow during the 
sampling period,* (2) using a calibrated, continuous flow rate recording 
device to record the actual flow rate during the samping period and 
integrating the flow rate over the period, or (3) any other means that 
will accurately measure the total air volume sampled during the sampling 
period. Use of a continuous flow recorder is recommended, particularly 
if the sampler is not equipped with a constant flow controller.
    6.3 Loss of volatiles. Volatile particles collected on the filter 
may be lost during subsequent sampling or during shipment and/or storage 
of the filter prior to the postsampling weighing.(5) Although such 
losses are largely unavoidable, the filter should be reweighed as soon 
after sampling as practical.
    6.4 Artifact particulate matter. Artifact particulate matter can be 
formed on the surface of alkaline glass fiber filters by oxidation of 
acid gases in the sample air, resulting in a higher than true TSP 
determination.(6 7) This effect usually occurs early in the sample 
period and is a function of the filter pH and the presence of acid 
gases. It is generally believed to account for only a small percentage 
of the filter weight gain, but the effect may become more significant 
where relatively small particulate weights are collected.
    6.5 Humidity. Glass fiber filters are comparatively insensitive to 
changes in relative humidity, but collected particulate matter can be 
hygroscopic.(8) The moisture conditioning procedure minimizes but may 
not completely eliminate error due to moisture.
    6.6 Filter handling. Careful handling of the filter between the 
presampling and postsampling weighings is necessary to avoid errors due 
to loss of fibers or particles from the filter. A filter paper cartridge 
or cassette used to protect the filter can minimize handling errors. 
(See Reference 2, Section 2).
    6.7 Nonsampled particulate matter. Particulate matter may be 
deposited on the filter by wind during periods when the sampler is 
inoperative. (9) It is recommended that errors from this source be 
minimized by an automatic mechanical device that keeps the filter 
covered during nonsampling periods, or by timely installation and 
retrieval of filters to minimize the nonsampling periods prior to and 
following operation.
    6.8 Timing errors. Samplers are normally controlled by clock timers 
set to start and stop the sampler at midnight. Errors in the nominal 
1,440-min sampling period may result from a power interruption during 
the sampling period or from a discrepancy between the start or stop time 
recorded on the filter information record and the actual start or stop 
time of the sampler. Such discrepancies may be caused by (1) poor 
resolution of the timer set-points, (2) timer error due to power 
interruption, (3) missetting of

[[Page 26]]

the timer, or (4) timer malfunction. In general, digital electronic 
timers have much better set-point resolution than mechanical timers, but 
require a battery backup system to maintain continuity of operation 
after a power interruption. A continuous flow recorder or elapsed time 
meter provides an indication of the sampler run-time, as well as 
indication of any power interruption during the sampling period and is 
therefore recommended.
    6.9 Recirculation of sampler exhaust. Under stagnant wind 
conditions, sampler exhaust air can be resampled. This effect does not 
appear to affect the TSP measurement substantially, but may result in 
increased carbon and copper in the collected sample. (10) This problem 
can be reduced by ducting the exhaust air well away, preferably 
downwind, from the sampler.
    7.0 Apparatus.
    (See References 1 and 2 for quality assurance information.)
    Note: Samplers purchased prior to the effective date of this 
amendment are not subject to specifications preceded by ([dagger]).
    7.1 Filter. (Filters supplied by the Environmental Protection Agency 
can be assumed to meet the following criteria. Additional specifications 
are required if the sample is to be analyzed chemically.)
    7.1.1 Size: 20.3  0.2 x 25.4  0.2 cm (nominal 8 x 10 in).
    7.1.2 Nominal exposed area: 406.5 cm\2\ (63 in\2\).
    7.1.3. Material: Glass fiber or other relatively inert, 
nonhygroscopic material. (8)
    7.1.4 Collection efficiency: 99 percent minimum as measured by the 
DOP test (ASTM-2986) for particles of 0.3 [micro]m diameter.
    7.1.5 Recommended pressure drop range: 42-54 mm Hg (5.6-7.2 kPa) at 
a flow rate of 1.5 std m\3\/min through the nominal exposed area.
    7.1.6 pH: 6 to 10. (11)
    7.1.7 Integrity: 2.4 mg maximum weight loss. (11)
    7.1.8 Pinholes: None.
    7.1.9 Tear strength: 500 g minimum for 20 mm wide strip cut from 
filter in weakest dimension. (See ASTM Test D828-60).
    7.1.10 Brittleness: No cracks or material separations after single 
lengthwise crease.
    7.2 Sampler. The air sampler shall provide means for drawing the air 
sample, via reduced pressure, through the filter at a uniform face 
velocity.
    7.2.1 The sampler shall have suitable means to:
    a. Hold and seal the filter to the sampler housing.
    b. Allow the filter to be changed conveniently.
    c. Preclude leaks that would cause error in the measurement of the 
air volume passing through the filter.
    d. ([dagger]) Manually adjust the flow rate to accommodate 
variations in filter pressure drop and site line voltage and altitude. 
The adjustment may be accomplished by an automatic flow controller or by 
a manual flow adjustment device. Any manual adjustment device must be 
designed with positive detents or other means to avoid unintentional 
changes in the setting.
---------------------------------------------------------------------------

    ([dagger]) See note at beginning of Section 7 of this appendix.
---------------------------------------------------------------------------

    7.2.2 Minimum sample flow rate, heavily loaded filter: 1.1 m\3\/min 
(39 ft\3\/min).[Dagger]
---------------------------------------------------------------------------

    [Dagger] These specifications are in actual air volume units; to 
convert to EPA standard air volume units, multiply the specifications by 
(Pb/Pstd)(298/T) where Pb and T are the 
barometric pressure in mm Hg (or kPa) and the temperature in K at the 
sampler, and Pstd is 760 mm Hg (or 101 kPa).
---------------------------------------------------------------------------

    7.2.3 Maximum sample flow rate, clean filter: 1.7 m\3\/min (60 
ft\3\/min).[Dagger]
    7.2.4 Blower Motor: The motor must be capable of continuous 
operation for 24-hr periods.
    7.3 Sampler shelter.
    7.3.1 The sampler shelter shall:
    a. Maintain the filter in a horizontal position at least 1 m above 
the sampler supporting surface so that sample air is drawn downward 
through the filter.
    b. Be rectangular in shape with a gabled roof, similar to the design 
shown in Figure 1.
    c. Cover and protect the filter and sampler from precipitation and 
other weather.
    d. Discharge exhaust air at least 40 cm from the sample air inlet.
    e. Be designed to minimize the collection of dust from the 
supporting surface by incorporating a baffle between the exhaust outlet 
and the supporting surface.
    7.3.2 The sampler cover or roof shall overhang the sampler housing 
somewhat, as shown in Figure 1, and shall be mounted so as to form an 
air inlet gap between the cover and the sampler housing walls. 
[dagger] This sample air inlet should be approximately 
uniform on all sides of the sampler. [dagger] The area of the 
sample air inlet must be sized to provide an effective particle capture 
air velocity of between 20 and 35 cm/sec at the recommended operational 
flow rate. The capture velocity is the sample air flow rate divided by 
the inlet area measured in a horizontal plane at the lower edge of the 
cover. [dagger] Ideally, the inlet area and operational flow 
rate should be selected to obtain a capture air velocity of 25 2 cm/sec.
    7.4 Flow rate measurement devices.
    7.4.1 The sampler shall incorporate a flow rate measurement device 
capable of indicating the total sampler flow rate. Two common types of 
flow indicators covered in the calibration procedure are (1) an 
electronic mass flowmeter and (2) an orifice or orifices

[[Page 27]]

located in the sample air stream together with a suitable pressure 
indicator such as a manometer, or aneroid pressure gauge. A pressure 
recorder may be used with an orifice to provide a continuous record of 
the flow. Other types of flow indicators (including rotameters) having 
comparable precision and accuracy are also acceptable.
    7.4.2 [dagger] The flow rate measurement device must be capable of 
being calibrated and read in units corresponding to a flow rate which is 
readable to the nearest 0.02 std m\3\/min over the range 1.0 to 1.8 std 
m\3\/min.
    7.5 Thermometer, to indicate the approximate air temperature at the 
flow rate measurement orifice, when temperature corrections are used.
    7.5.1 Range: -40[deg] to +50 [deg]C (223-323 K).
    7.5.2 Resolution: 2 [deg]C (2 K).
    7.6 Barometer, to indicate barometric pressure at the flow rate 
measurement orifice, when pressure corrections are used.
    7.6.1 Range: 500 to 800 mm Hg (66-106 kPa).
    7.6.2 Resolution: 5 mm Hg (0.67 kPa).
    7.7 Timing/control device.
    7.7.1 The timing device must be capable of starting and stopping the 
sampler to obtain an elapsed run-time of 24 hr 1 
hr (1,440 60 min).
    7.7.2 Accuracy of time setting: 30 min, or 
better. (See Section 6.8).
    7.8 Flow rate transfer standard, traceable to a primary standard. 
(See Section 9.2.)
    7.8.1 Approximate range: 1.0 to 1.8 m\3\/min.
    7.8.2 Resolution: 0.02 m\3\/min.
    7.8.3 Reproducibility: 2 percent (2 times 
coefficient of variation) over normal ranges of ambient temperature and 
pressure for the stated flow rate range. (See Reference 2, Section 2.)
    7.8.4 Maximum pressure drop at 1.7 std m\3\/min; 50 cm H2 
O (5 kPa).
    7.8.5 The flow rate transfer standard must connect without leaks to 
the inlet of the sampler and measure the flow rate of the total air 
sample.
    7.8.6 The flow rate transfer standard must include a means to vary 
the sampler flow rate over the range of 1.0 to 1.8 m\3\/min (35-64 
ft\3\/min) by introducing various levels of flow resistance between the 
sampler and the transfer standard inlet.
    7.8.7 The conventional type of flow transfer standard consists of: 
An orifice unit with adapter that connects to the inlet of the sampler, 
a manometer or other device to measure orifice pressure drop, a means to 
vary the flow through the sampler unit, a thermometer to measure the 
ambient temperature, and a barometer to measure ambient pressure. Two 
such devices are shown in Figures 2a and 2b. Figure 2a shows multiple 
fixed resistance plates, which necessitate disassembly of the unit each 
time the flow resistance is changed. A preferable design, illustrated in 
Figure 2b, has a variable flow restriction that can be adjusted 
externally without disassembly of the unit. Use of a conventional, 
orifice-type transfer standard is assumed in the calibration procedure 
(Section 9). However, the use of other types of transfer standards 
meeting the above specifications, such as the one shown in Figure 2c, 
may be approved; see the note following Section 9.1.
    7.9 Filter conditioning environment
    7.9.1 Controlled temperature: between 15[deg] and 30 [deg]C with 
less than 3 [deg]C variation during equilibration 
period.
    7.9.2 Controlled humidity: Less than 50 percent relative humidity, 
constant within 5 percent.
    7.10 Analytical balance.
    7.10.1 Sensitivity: 0.1 mg.
    7.10.2 Weighing chamber designed to accept an unfolded 20.3x25.4 cm 
(8x10 in) filter.
    7.11 Area light source, similar to X-ray film viewer, to backlight 
filters for visual inspection.
    7.12 Numbering device, capable of printing identification numbers on 
the filters before they are placed in the filter conditioning 
environment, if not numbered by the supplier.
    8.0 Procedure.
    (See References 1 and 2 for quality assurance information.)
    8.1 Number each filter, if not already numbered, near its edge with 
a unique identification number.
    8.2 Backlight each filter and inspect for pinholes, particles, and 
other imperfections; filters with visible imperfections must not be 
used.
    8.3 Equilibrate each filter in the conditioning environment for at 
least 24-hr.
    8.4 Following equilibration, weigh each filter to the nearest 
milligram and record this tare weight (Wi) with the filter 
identification number.
    8.5 Do not bend or fold the filter before collection of the sample.
    8.6 Open the shelter and install a numbered, preweighed filter in 
the sampler, following the sampler manufacturer's instructions. During 
inclement weather, precautions must be taken while changing filters to 
prevent damage to the clean filter and loss of sample from or damage to 
the exposed filter. Filter cassettes that can be loaded and unloaded in 
the laboratory may be used to minimize this problem (See Section 6.6).
    8.7 Close the shelter and run the sampler for at least 5 min to 
establish run-temperature conditions.
    8.8 Record the flow indicator reading and, if needed, the barometric 
pressure (P\3\3) and the ambient temperature 
(T\3\3) see NOTE following step 8.12). Stop the sampler. 
Determine the sampler flow rate (see Section 10.1); if it is outside the 
acceptable range (1.1 to 1.7 m\3\/min [39-60 ft\3\/min]), use a 
different filter, or adjust the sampler flow rate. Warning: Substantial 
flow adjustments may affect the

[[Page 28]]

calibration of the orifice-type flow indicators and may necessitate 
recalibration.
    8.9 Record the sampler identification information (filter number, 
site location or identification number, sample date, and starting time).
    8.10 Set the timer to start and stop the sampler such that the 
sampler runs 24-hrs, from midnight to midnight (local time).
    8.11 As soon as practical following the sampling period, run the 
sampler for at least 5 min to again establish run-temperature 
conditions.
    8.12 Record the flow indicator reading and, if needed, the 
barometric pressure (P\3\3) and the ambient temperature 
(T\3\3).
    Note: No onsite pressure or temperature measurements are necessary 
if the sampler flow indicator does not require pressure or temperature 
corrections (e.g., a mass flowmeter) or if average barometric pressure 
and seasonal average temperature for the site are incorporated into the 
sampler calibration (see step 9.3.9). For individual pressure and 
temperature corrections, the ambient pressure and temperature can be 
obtained by onsite measurements or from a nearby weather station. 
Barometric pressure readings obtained from airports must be station 
pressure, not corrected to sea level, and may need to be corrected for 
differences in elevation between the sampler site and the airport. For 
samplers having flow recorders but not constant flow controllers, the 
average temperature and pressure at the site during the sampling period 
should be estimated from weather bureau or other available data.
    8.13 Stop the sampler and carefully remove the filter, following the 
sampler manufacturer's instructions. Touch only the outer edges of the 
filter. See the precautions in step 8.6.
    8.14 Fold the filter in half lengthwise so that only surfaces with 
collected particulate matter are in contact and place it in the filter 
holder (glassine envelope or manila folder).
    8.15 Record the ending time or elapsed time on the filter 
information record, either from the stop set-point time, from an elapsed 
time indicator, or from a continuous flow record. The sample period must 
be 1,440 60 min. for a valid sample.
    8.16 Record on the filter information record any other factors, such 
as meteorological conditions, construction activity, fires or dust 
storms, etc., that might be pertinent to the measurement. If the sample 
is known to be defective, void it at this time.
    8.17 Equilibrate the exposed filter in the conditioning environment 
for at least 24-hrs.
    8.18 Immediately after equilibration, reweigh the filter to the 
nearest milligram and record the gross weight with the filter 
identification number. See Section 10 for TSP concentration 
calculations.
    9.0 Calibration.
    9.1 Calibration of the high volume sampler's flow indicating or 
control device is necessary to establish traceability of the field 
measurement to a primary standard via a flow rate transfer standard. 
Figure 3a illustrates the certification of the flow rate transfer 
standard and Figure 3b illustrates its use in calibrating a sampler flow 
indicator. Determination of the corrected flow rate from the sampler 
flow indicator, illustrated in Figure 3c, is addressed in Section 10.1
    Note: The following calibration procedure applies to a conventional 
orifice-type flow transfer standard and an orifice-type flow indicator 
in the sampler (the most common types). For samplers using a pressure 
recorder having a square-root scale, 3 other acceptable calibration 
procedures are provided in Reference 12. Other types of transfer 
standards may be used if the manufacturer or user provides an 
appropriately modified calibration procedure that has been approved by 
EPA under Section 2.8 of appendix C to part 58 of this chapter.
    9.2 Certification of the flow rate transfer standard.
    9.2.1 Equipment required: Positive displacement standard volume 
meter traceable to the National Bureau of Standards (such as a Roots 
meter or equivalent), stop-watch, manometer, thermometer, and barometer.
    9.2.2 Connect the flow rate transfer standard to the inlet of the 
standard volume meter. Connect the manometer to measure the pressure at 
the inlet of the standard volume meter. Connect the orifice manometer to 
the pressure tap on the transfer standard. Connect a high-volume air 
pump (such as a high-volume sampler blower) to the outlet side of the 
standard volume meter. See Figure 3a.
    9.2.3 Check for leaks by temporarily clamping both manometer lines 
(to avoid fluid loss) and blocking the orifice with a large-diameter 
rubber stopper, wide cellophane tape, or other suitable means. Start the 
high-volume air pump and note any change in the standard volume meter 
reading. The reading should remain constant. If the reading changes, 
locate any leaks by listening for a whistling sound and/or retightening 
all connections, making sure that all gaskets are properly installed.
    9.2.4 After satisfactorily completing the leak check as described 
above, unclamp both manometer lines and zero both manometers.
    9.2.5 Achieve the appropriate flow rate through the system, either 
by means of the variable flow resistance in the transfer standard or by 
varying the voltage to the air pump. (Use of resistance plates as shown 
in Figure 1a is discouraged because the above leak check must be 
repeated each time a new resistance plate is installed.) At least five 
different but constant flow rates, evenly distributed, with at least 
three in the specified

[[Page 29]]

flow rate interval (1.1 to 1.7 m\3\/min [39-60 ft\3\/min]), are 
required.
    9.2.6 Measure and record the certification data on a form similar to 
the one illustrated in Figure 4 according to the following steps.
    9.2.7 Observe the barometric pressure and record as P1 
(item 8 in Figure 4).
    9.2.8 Read the ambient temperature in the vicinity of the standard 
volume meter and record it as T1 (item 9 in Figure 4).
    9.2.9 Start the blower motor, adjust the flow, and allow the system 
to run for at least 1 min for a constant motor speed to be attained.
    9.2.10 Observe the standard volume meter reading and simultaneously 
start a stopwatch. Record the initial meter reading (Vi) in 
column 1 of Figure 4.
    9.2.11 Maintain this constant flow rate until at least 3 m\3\ of air 
have passed through the standard volume meter. Record the standard 
volume meter inlet pressure manometer reading as [Delta]P (column 5 in 
Figure 4), and the orifice manometer reading as [Delta]H (column 7 in 
Figure 4). Be sure to indicate the correct units of measurement.
    9.2.12 After at least 3 m\3\ of air have passed through the system, 
observe the standard volume meter reading while simultaneously stopping 
the stopwatch. Record the final meter reading (Vf) in column 
2 and the elapsed time (t) in column 3 of Figure 4.
    9.2.13 Calculate the volume measured by the standard volume meter at 
meter conditions of temperature and pressures as 
Vm=Vf-Vi. Record in column 4 of Figure 
4.
    9.2.14 Correct this volume to standard volume (std m\3\) as follows:
    [GRAPHIC] [TIFF OMITTED] TR31AU93.024
    
where:

Vstd = standard volume, std m\3\;
Vm = actual volume measured by the standard volume meter;
P1 = barometric pressure during calibration, mm Hg or kPa;
[Delta]P = differential pressure at inlet to volume meter, mm Hg or kPa;
Pstd = 760 mm Hg or 101 kPa;
Tstd = 298 K;
T1 = ambient temperature during calibration, K.
Calculate the standard flow rate (std m\3\/min) as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.013

where:

Qstd = standard volumetric flow rate, std m\3\/min
t = elapsed time, minutes.

    Record Qstd to the nearest 0.01 std m\3\/min in column 6 
of Figure 4.
    9.2.15 Repeat steps 9.2.9 through 9.2.14 for at least four 
additional constant flow rates, evenly spaced over the approximate range 
of 1.0 to 1.8 std m\3\/min (35-64 ft\3\/min).
    9.2.16 For each flow, compute

[radic][Delta][Delta]H (P1/Pstd)(298/
T1)

(column 7a of Figure 4) and plot these value against Qstd as 
shown in Figure 3a. Be sure to use consistent units (mm Hg or kPa) for 
barometric pressure. Draw the orifice transfer standard certification 
curve or calculate the linear least squares slope (m) and intercept (b) 
of the certification curve:

[radic][Delta][Delta]H (P1/Pstd)(298/
T1)

=mQstd+b. See Figures 3 and 4. A certification graph should 
be readable to 0.02 std m\3\/min.
    9.2.17 Recalibrate the transfer standard annually or as required by 
applicable quality control procedures. (See Reference 2.)
    9.3 Calibration of sampler flow indicator.

    Note: For samplers equipped with a flow controlling device, the flow 
controller must be disabled to allow flow changes during calibration of 
the sampler's flow indicator, or the alternate calibration of the flow 
controller given in 9.4 may be used. For samplers using an orifice-type 
flow indicator downstream of the motor, do not vary the flow rate by 
adjusting the voltage or power supplied to the sampler.

    9.3.1 A form similar to the one illustrated in Figure 5 should be 
used to record the calibration data.
    9.3.2 Connect the transfer standard to the inlet of the sampler. 
Connect the orifice manometer to the orifice pressure tap, as 
illustrated in Figure 3b. Make sure there are no leaks between the 
orifice unit and the sampler.
    9.3.3 Operate the sampler for at least 5 minutes to establish 
thermal equilibrium prior to the calibration.
    9.3.4 Measure and record the ambient temperature, T2, and 
the barometric pressure, P2, during calibration.
    9.3.5 Adjust the variable resistance or, if applicable, insert the 
appropriate resistance plate (or no plate) to achieve the desired flow 
rate.
    9.3.6 Let the sampler run for at least 2 min to re-establish the 
run-temperature conditions. Read and record the pressure drop across the 
orifice ([Delta]H) and the sampler flow rate indication (I) in the 
appropriate columns of Figure 5.
    9.3.7 Calculate [radic][Delta][Delta]H(P2/
Pstd)(298/T2) and determine the flow rate at 
standard conditions (Qstd) either graphically from the 
certification curve or by calculating Qstd from the least 
square slope and intercept of the transfer standard's transposed 
certification curve: Qstd=1/m [radic][Delta]H(P2/
Pstd)(298/T2)-b. Record the value of 
Qstd on Figure 5.

[[Page 30]]

    9.3.8 Repeat steps 9.3.5, 9.3.6, and 9.3.7 for several additional 
flow rates distributed over a range that includes 1.1 to 1.7 std m\3\/
min.
    9.3.9 Determine the calibration curve by plotting values of the 
appropriate expression involving I, selected from table 1, against 
Qstd. The choice of expression from table 1 depends on the 
flow rate measurement device used (see Section 7.4.1) and also on 
whether the calibration curve is to incorporate geographic average 
barometric pressure (Pa) and seasonal average temperature 
(Ta) for the site to approximate actual pressure and 
temperature. Where Pa and Ta can be determined for 
a site for a seasonal period such that the actual barometric pressure 
and temperature at the site do not vary by more than 60 mm Hg (8 kPa) from Pa or 15 [deg]C from Ta, respectively, then using 
Pa and Ta avoids the need for subsequent pressure 
and temperature calculation when the sampler is used. The geographic 
average barometric pressure (Pa) may be estimated from an 
altitude-pressure table or by making an (approximate) elevation 
correction of -26 mm Hg (-3.46 kPa) for each 305 m (1,000 ft) above sea 
level (760 mm Hg or 101 kPa). The seasonal average temperature 
(Ta) may be estimated from weather station or other records. 
Be sure to use consistent units (mm Hg or kPa) for barometric pressure.
    9.3.10 Draw the sampler calibration curve or calculate the linear 
least squares slope (m), intercept (b), and correlation coefficient of 
the calibration curve: [Expression from table 1]= mQstd+b. 
See Figures 3 and 5. Calibration curves should be readable to 0.02 std 
m\3\/min.
    9.3.11 For a sampler equipped with a flow controller, the flow 
controlling mechanism should be re-enabled and set to a flow near the 
lower flow limit to allow maximum control range. The sample flow rate 
should be verified at this time with a clean filter installed. Then add 
two or more filters to the sampler to see if the flow controller 
maintains a constant flow; this is particularly important at high 
altitudes where the range of the flow controller may be reduced.
    9.4 Alternate calibration of flow-controlled samplers. A flow-
controlled sampler may be calibrated solely at its controlled flow rate, 
provided that previous operating history of the sampler demonstrates 
that the flow rate is stable and reliable. In this case, the flow 
indicator may remain uncalibrated but should be used to indicate any 
relative change between initial and final flows, and the sampler should 
be recalibrated more often to minimize potential loss of samples because 
of controller malfunction.
    9.4.1 Set the flow controller for a flow near the lower limit of the 
flow range to allow maximum control range.
    9.4.2 Install a clean filter in the sampler and carry out steps 
9.3.2, 9.3.3, 9.3.4, 9.3.6, and 9.3.7.
    9.4.3 Following calibration, add one or two additional clean filters 
to the sampler, reconnect the transfer standard, and operate the sampler 
to verify that the controller maintains the same calibrated flow rate; 
this is particularly important at high altitudes where the flow control 
range may be reduced.



[[Page 31]]




    10.0 Calculations of TSP Concentration.
    10.1 Determine the average sampler flow rate during the sampling 
period according to either 10.1.1 or 10.1.2 below.
    10.1.1 For a sampler without a continuous flow recorder, determine 
the appropriate expression to be used from table 2 corresponding to the 
one from table 1 used in step 9.3.9. Using this appropriate expression, 
determine Qstd for the initial flow rate from the sampler 
calibration curve, either graphically or from the transposed regression 
equation:

Qstd =
1/m ([Appropriate expression from table 2]-b)

Similarly, determine Qstd from the final flow reading, and 
calculate the average flow Qstd as one-half the sum of the 
initial and final flow rates.
    10.1.2 For a sampler with a continuous flow recorder, determine the 
average flow rate device reading, I, for the period. Determine the 
appropriate expression from table 2 corresponding to the one from table 
1 used in step 9.3.9. Then using this expression and the average flow 
rate reading, determine Qstd from the sampler calibration 
curve, either graphically or from the transposed regression equation:

Qstd =

1/m ([Appropriate expression from table 2]-b)
    If the trace shows substantial flow change during the sampling 
period, greater accuracy may be achieved by dividing the sampling period 
into intervals and calculating an average reading before determining 
Qstd.
    10.2 Calculate the total air volume sampled as:

V-Qstdx t

where:

V = total air volume sampled, in standard volume units, std m\3\/;
Qstd = average standard flow rate, std m\3\/min;
t = sampling time, min.

    10.3 Calculate and report the particulate matter concentration as:
    [GRAPHIC] [TIFF OMITTED] TR31AU93.025
    
where:

TSP = mass concentration of total suspended particulate matter, 
[micro]g/std m\3\;
Wi = initial weight of clean filter, g;
Wf = final weight of exposed filter, g;
V = air volume sampled, converted to standard conditions, std m\3\,
10\6\ = conversion of g to [micro]g.

    10.4 If desired, the actual particulate matter concentration (see 
Section 2.2) can be calculated as follows:

(TSP)a=TSP (P3/Pstd)(298/T3)

where:

(TSP)a = actual concentration at field conditions, [micro]g/
m\3\;

[[Page 32]]

TSP = concentration at standard conditions, [micro]g/std m\3\;
P3 = average barometric pressure during sampling period, mm 
Hg;
Pstd = 760 mn Hg (or 101 kPa);
T3 = average ambient temperature during sampling period, K.

    11.0 References.
    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume I, Principles. EPA-600/9-76-005, U.S. Environmental Protection 
Agency, Research Triangle Park, NC 27711, 1976.
    2. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume II, Ambient Air Specific Methods. EPA-600/4-77-027a, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711, 1977.
    3. Wedding, J. B., A. R. McFarland, and J. E. Cernak. Large Particle 
Collection Characteristics of Ambient Aerosol Samplers. Environ. Sci. 
Technol. 11:387-390, 1977.
    4. McKee, H. C., et al. Collaborative Testing of Methods to Measure 
Air Pollutants, I. The High-Volume Method for Suspended Particulate 
Matter. J. Air Poll. Cont. Assoc., 22 (342), 1972.
    5. Clement, R. E., and F. W. Karasek. Sample Composition Changes in 
Sampling and Analysis of Organic Compounds in Aerosols. The Intern. J. 
Environ. Anal. Chem., 7:109, 1979.
    6. Lee, R. E., Jr., and J. Wagman. A Sampling Anomaly in the 
Determination of Atmospheric Sulfuric Concentration. Am. Ind. Hygiene 
Assoc. J., 27:266, 1966.
    7. Appel, B. R., et al. Interference Effects in Sampling Particulate 
Nitrate in Ambient Air. Atmospheric Environment, 13:319, 1979.
    8. Tierney, G. P., and W. D. Conner. Hygroscopic Effects on Weight 
Determinations of Particulates Collected on Glass-Fiber Filters. Am. 
Ind. Hygiene Assoc. J., 28:363, 1967.
    9. Chahal, H. S., and D. J. Romano. High-Volume Sampling Effect of 
Windborne Particulate Matter Deposited During Idle Periods. J. Air Poll. 
Cont. Assoc., Vol. 26 (885), 1976.
    10. Patterson, R. K. Aerosol Contamination from High-Volume Sampler 
Exhaust. J. Air Poll. Cont. Assoc., Vol. 30 (169), 1980.
    11. EPA Test Procedures for Determining pH and Integrity of High-
Volume Air Filters. QAD/M-80.01. Available from the Methods 
Standardization Branch, Quality Assurance Division, Environmental 
Monitoring Systems Laboratory (MD-77), U.S. Environmental Protection 
Agency, Research Triangle Park, NC 27711, 1980.
    12. Smith, F., P. S. Wohlschlegel, R. S. C. Rogers, and D. J. 
Mulligan. Investigation of Flow Rate Calibration Procedures Associated 
with the High-Volume Method for Determination of Suspended Particulates. 
EPA-600/4-78-047, U.S. Environmental Protection Agency, Research 
Triangle Park, NC, June 1978.



[[Page 33]]





[[Page 34]]





[[Page 35]]





[[Page 36]]





[47 FR 54912, Dec. 6, 1982; 48 FR 17355, Apr. 22, 1983]

 Appendix C to Part 50--Measurement Principle and Calibration Procedure 
for the Measurement of Carbon Monoxide in the Atmosphere (Non-Dispersive 
                          Infrared Photometry)

                          Measurement Principle

    1. Measurements are based on the absorption of infrared radiation by 
carbon monoxide (CO) in a non-dispersive photometer. Infrared energy 
from a source is passed through a cell containing the gas sample to be 
analyzed, and the quantitative absorption of energy by CO in the sample 
cell is measured by a suitable detector. The photometer is sensitized to 
CO by employing CO gas in either the detector or in a filter cell in the 
optical path, thereby limiting the measured absorption to one or more of 
the characteristic wavelengths at which CO strongly absorbs. Optical 
filters or other means may

[[Page 37]]

also be used to limit sensitivity of the photometer to a narrow band of 
interest. Various schemes may be used to provide a suitable zero 
reference for the photometer. The measured absorption is converted to an 
electrical output signal, which is related to the concentration of CO in 
the measurement cell.
    2. An analyzer based on this principle will be considered a 
reference method only if it has been designated as a reference method in 
accordance with part 53 of this chapter.
    3. Sampling considerations.
    The use of a particle filter on the sample inlet line of an NDIR CO 
analyzer is optional and left to the discretion of the user or the 
manufacturer. Use of filter should depend on the analyzer's 
susceptibility to interference, malfunction, or damage due to particles.

                          Calibration Procedure

    1. Principle. Either of two methods may be used for dynamic 
multipoint calibration of CO analyzers:
    (1) One method uses a single certified standard cylinder of CO, 
diluted as necessary with zero air, to obtain the various calibration 
concentrations needed.
    (2) The other method uses individual certified standard cylinders of 
CO for each concentration needed. Additional information on calibration 
may be found in Section 2.0.9 of Reference 1.
    2. Apparatus. The major components and typical configurations of the 
calibration systems for the two calibration methods are shown in Figures 
1 and 2.
    2.1 Flow controller(s). Device capable of adjusting and regulating 
flow rates. Flow rates for the dilution method (Figure 1) must be 
regulated to 1%.
    2.2 Flow meter(s). Calibrated flow meter capable of measuring and 
monitoring flow rates. Flow rates for the dilution method (Figure 1) 
must be measured with an accuracy of 2% of the 
measured value.
    2.3 Pressure regulator(s) for standard CO cylinder(s). Regulator 
must have nonreactive diaphragm and internal parts and a suitable 
delivery pressure.
    2.4 Mixing chamber. A chamber designed to provide thorough mixing of 
CO and diluent air for the dilution method.
    2.5 Output manifold. The output manifold should be of sufficient 
diameter to insure an insignificant pressure drop at the analyzer 
connection. The system must have a vent designed to insure atmospheric 
pressure at the manifold and to prevent ambient air from entering the 
manifold.
    3. Reagents.
    3.1 CO concentration standard(s). Cylinder(s) of CO in air 
containing appropriate concentrations(s) of CO suitable for the selected 
operating range of the analyzer under calibration; CO standards for the 
dilution method may be contained in a nitrogen matrix if the zero air 
dilution ratio is not less than 100:1. The assay of the cylinder(s) must 
be traceable either to a National Bureau of Standards (NBS) CO in air 
Standard Reference Material (SRM) or to an NBS/EPA-approved commercially 
available Certified Reference Material (CRM). CRM's are described in 
Reference 2, and a list of CRM sources is available from the address 
shown for Reference 2. A recommended protocol for certifying CO gas 
cylinders against either a CO SRM or a CRM is given in Reference 1. CO 
gas cylinders should be recertified on a regular basis as determined by 
the local quality control program.
    3.2 Dilution gas (zero air). Air, free of contaminants which will 
cause a detectable response on the CO analyzer. The zero air should 
contain <0.1 ppm CO. A procedure for generating zero air is given in 
Reference 1.
    4. Procedure Using Dynamic Dilution Method.
    4.1 Assemble a dynamic calibration system such as the one shown in 
Figure 1. All calibration gases including zero air must be introduced 
into the sample inlet of the analyzer system. For specific operating 
instructions refer to the manufacturer's manual.
    4.2 Insure that all flowmeters are properly calibrated, under the 
conditions of use, if appropriate, against an authoritative standard 
such as a soap-bubble meter or wet-test meter. All volumetric flowrates 
should be corrected to 25 [deg]C and 760 mm Hg (101 kPa). A discussion 
on calibration of flowmeters is given in Reference 1.
    4.3 Select the operating range of the CO analyzer to be calibrated.
    4.4 Connect the signal output of the CO analyzer to the input of the 
strip chart recorder or other data collection device. All adjustments to 
the analyzer should be based on the appropriate strip chart or data 
device readings. References to analyzer responses in the procedure given 
below refer to recorder or data device responses.
    4.5 Adjust the calibration system to deliver zero air to the output 
manifold. The total air flow must exceed the total demand of the 
analyzer(s) connected to the output manifold to insure that no ambient 
air is pulled into the manifold vent. Allow the analyzer to sample zero 
air until a stable respose is obtained. After the response has 
stabilized, adjust the analyzer zero control. Offsetting the analyzer 
zero adjustments to +5 percent of scale is recommended to facilitate 
observing negative zero drift. Record the stable zero air response as 
ZCO.
    4.6 Adjust the zero air flow and the CO flow from the standard CO 
cylinder to provide a diluted CO concentration of approximately 80 
percent of the upper range limit (URL) of the operating range of the 
analyzer. The total air flow must exceed the total demand of the 
analyzer(s) connected to the output manifold to insure that no ambient 
air is

[[Page 38]]

pulled into the manifold vent. The exact CO concentration is calculated 
from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.026

where:

[CO]OUT = diluted CO concentration at the output manifold, 
ppm;
[CO]STD = concentration of the undiluted CO standard, ppm;
FCO = flow rate of the CO standard corrected to 25 [deg]C and 
760 mm Hg, (101 kPa), L/min; and
FD = flow rate of the dilution air corrected to 25 [deg]C and 
760 mm Hg, (101 kPa), L/min.

    Sample this CO concentration until a stable response is obtained. 
Adjust the analyzer span control to obtain a recorder response as 
indicated below:

Recorder response (percent scale) =

[GRAPHIC] [TIFF OMITTED] TR31AU93.027

where:

URL = nominal upper range limit of the analyzer's operating range, and
ZCO = analyzer response to zero air, % scale.

    If substantial adjustment of the analyzer span control is required, 
it may be necessary to recheck the zero and span adjustments by 
repeating Steps 4.5 and 4.6. Record the CO concentration and the 
analyzer's response. 4.7 Generate several additional concentrations (at 
least three evenly spaced points across the remaining scale are 
suggested to verify linearity) by decreasing FCO or 
increasing FD. Be sure the total flow exceeds the analyzer's 
total flow demand. For each concentration generated, calculate the exact 
CO concentration using Equation (1). Record the concentration and the 
analyzer's response for each concentration. Plot the analyzer responses 
versus the corresponding CO concentrations and draw or calculate the 
calibration curve.
    5. Procedure Using Multiple Cylinder Method. Use the procedure for 
the dynamic dilution method with the following changes:
    5.1 Use a multi-cylinder system such as the typical one shown in 
Figure 2.
    5.2 The flowmeter need not be accurately calibrated, provided the 
flow in the output manifold exceeds the analyzer's flow demand.
    5.3 The various CO calibration concentrations required in Steps 4.6 
and 4.7 are obtained without dilution by selecting the appropriate 
certified standard cylinder.

                               References

    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume II--Ambient Air Specific Methods, EPA-600/4-77-027a, U.S. 
Environmental Protection Agency, Environmental Monitoring Systems 
Laboratory, Research Triangle Park, NC 27711, 1977.
    2. A procedure for Establishing Traceability of Gas Mixtures to 
Certain National Bureau of Standards Standard Reference Materials. EPA-
600/7-81-010, U.S. Environmental Protection Agency, Environmental 
Monitoring Systems Laboratory (MD-77), Research Triangle Park, NC 27711, 
January 1981.

[[Page 39]]




[[Page 40]]





[47 FR 54922, Dec. 6, 1982; 48 FR 17355, Apr. 22, 1983]

[[Page 41]]

 Appendix D to Part 50--Measurement Principle and Calibration Procedure 
             for the Measurement of Ozone in the Atmosphere

                          Measurement Principle

    1. Ambient air and ethylene are delivered simultaneously to a mixing 
zone where the ozone in the air reacts with the ethylene to emit light, 
which is detected by a photomultiplier tube. The resulting photocurrent 
is amplified and is either read directly or displayed on a recorder.
    2. An analyzer based on this principle will be considered a 
reference method only if it has been designated as a reference method in 
accordance with part 53 of this chapter and calibrated as follows:

                          Calibration Procedure

    1. Principle. The calibration procedure is based on the photometric 
assay of ozone (O3) concentrations in a dynamic flow system. 
The concentration of O3 in an absorption cell is determined 
from a measurement of the amount of 254 nm light absorbed by the sample. 
This determination requires knowledge of (1) the absorption coefficient 
([alpha]) of O3 at 254 nm, (2) the optical path length (l) 
through the sample, (3) the transmittance of the sample at a wavelength 
of 254 nm, and (4) the temperature (T) and pressure (P) of the sample. 
The transmittance is defined as the ratio I/I0, where I is 
the intensity of light which passes through the cell and is sensed by 
the detector when the cell contains an O3 sample, and 
I0 is the intensity of light which passes through the cell 
and is sensed by the detector when the cell contains zero air. It is 
assumed that all conditions of the system, except for the contents of 
the absorption cell, are identical during measurement of I and 
I0. The quantities defined above are related by the Beer-
Lambert absorption law,
[GRAPHIC] [TIFF OMITTED] TR31AU93.028

where:

[alpha] = absorption coefficient of O3 at 254 nm=308 4 atm-1 cm-1 at 0 [deg]C and 760 
torr.\3\(1, 2, 3, 4, 5, 6, 7)
c = O3 concentration in atmospheres
l = optical path length in cm

    In practice, a stable O3 generator is used to produce 
O3 concentrations over the required range. Each O3 
concentration is determined from the measurement of the transmittance 
(I/I0) of the sample at 254 nm with a photometer of path 
length l and calculated from the equation,
[GRAPHIC] [TIFF OMITTED] TR31AU93.029

The calculated O3 concentrations must be corrected for 
O3 losses which may occur in the photometer and for the 
temperature and pressure of the sample.
    2. Applicability. This procedure is applicable to the calibration of 
ambient air O3 analyzers, either directly or by means of a 
transfer standard certified by this procedure. Transfer standards must 
meet the requirements and specifications set forth in Reference 8.
    3. Apparatus. A complete UV calibration system consists of an ozone 
generator, an output port or manifold, a photometer, an appropriate 
source of zero air, and other components as necessary. The configuration 
must provide a stable ozone concentration at the system output and allow 
the photometer to accurately assay the output concentration to the 
precision specified for the photometer (3.1). Figure 1 shows a commonly 
used configuration and serves to illustrate the calibration procedure 
which follows. Other configurations may require appropriate variations 
in the procedural steps. All connections between components in the 
calibration system downstream of the O3 generator should be 
of glass, Teflon, or other relatively inert materials. Additional 
information regarding the assembly of a UV photometric calibration 
apparatus is given in Reference 9. For certification of transfer 
standards which provide their own source of O3, the transfer 
standard may replace the O3 generator and possibly other 
components shown in Figure 1; see Reference 8 for guidance.
    3.1 UV photometer. The photometer consists of a low-pressure mercury 
discharge lamp, (optional) collimation optics, an absorption cell, a 
detector, and signal-processing electronics, as illustrated in Figure 1. 
It must be capable of measuring the transmittance, I/I0, at a 
wavelength of 254 nm with sufficient precision such that the standard 
deviation of the concentration measurements does not exceed the greater 
of 0.005 ppm or 3% of the concentration. Because the low-pressure 
mercury lamp radiates at several wavelengths, the photometer must 
incorporate suitable means to assure that no O3 is generated 
in the cell by the lamp, and that at least 99.5% of the radiation sensed 
by the detector is 254 nm radiation. (This can be readily achieved by 
prudent selection of optical filter and detector response 
characteristics.) The length of the light path through the absorption 
cell must be known with an accuracy of at least 99.5%. In addition, the 
cell and associated plumbing must be designed to

[[Page 42]]

minimize loss of O3 from contact with cell walls and gas 
handling components. See Reference 9 for additional information.
    3.2 Air flow controllers. Devices capable of regulating air flows as 
necessary to meet the output stability and photometer precision 
requirements.
    3.3 Ozone generator. Device capable of generating stable levels of 
O3 over the required concentration range.
    3.4 Output manifold. The output manifold should be constructed of 
glass, Teflon, or other relatively inert material, and should be of 
sufficient diameter to insure a negligible pressure drop at the 
photometer connection and other output ports. The system must have a 
vent designed to insure atmospheric pressure in the manifold and to 
prevent ambient air from entering the manifold.
    3.5 Two-way valve. Manual or automatic valve, or other means to 
switch the photometer flow between zero air and the O3 
concentration.
    3.6 Temperature indicator. Accurate to 1 
[deg]C.
    3.7 Barometer or pressure indicator. Accurate to 2 torr.
    4. Reagents.
    4.1 Zero air. The zero air must be free of contaminants which would 
cause a detectable response from the O3 analyzer, and it 
should be free of NO, C2 H4, and other species 
which react with O3. A procedure for generating suitable zero 
air is given in Reference 9. As shown in Figure 1, the zero air supplied 
to the photometer cell for the I0 reference measurement must 
be derived from the same source as the zero air used for generation of 
the ozone concentration to be assayed (I measurement). When using the 
photometer to certify a transfer standard having its own source of 
ozone, see Reference 8 for guidance on meeting this requirement.
    5. Procedure.
    5.1 General operation. The calibration photometer must be dedicated 
exclusively to use as a calibration standard. It should always be used 
with clean, filtered calibration gases, and never used for ambient air 
sampling. Consideration should be given to locating the calibration 
photometer in a clean laboratory where it can be stationary, protected 
from physical shock, operated by a responsible analyst, and used as a 
common standard for all field calibrations via transfer standards.
    5.2 Preparation. Proper operation of the photometer is of critical 
importance to the accuracy of this procedure. The following steps will 
help to verify proper operation. The steps are not necessarily required 
prior to each use of the photometer. Upon initial operation of the 
photometer, these steps should be carried out frequently, with all 
quantitative results or indications recorded in a chronological record 
either in tabular form or plotted on a graphical chart. As the 
performance and stability record of the photometer is established, the 
frequency of these steps may be reduced consistent with the documented 
stability of the photometer.
    5.2.1 Instruction manual: Carry out all set up and adjustment 
procedures or checks as described in the operation or instruction manual 
associated with the photometer.
    5.2.2 System check: Check the photometer system for integrity, 
leaks, cleanliness, proper flowrates, etc. Service or replace filters 
and zero air scrubbers or other consumable materials, as necessary.
    5.2.3 Linearity: Verify that the photometer manufacturer has 
adequately established that the linearity error of the photometer is 
less than 3%, or test the linearity by dilution as follows: Generate and 
assay an O3 concentration near the upper range limit of the 
system (0.5 or 1.0 ppm), then accurately dilute that concentration with 
zero air and reassay it. Repeat at several different dilution ratios. 
Compare the assay of the original concentration with the assay of the 
diluted concentration divided by the dilution ratio, as follows
[GRAPHIC] [TIFF OMITTED] TR31AU93.030

where:

E = linearity error, percent
A1 = assay of the original concentration
A2 = assay of the diluted concentration
R = dilution ratio = flow of original concentration divided by the total 
flow

    The linearity error must be less than 5%. Since the accuracy of the 
measured flow-rates will affect the linearity error as measured this 
way, the test is not necessarily conclusive. Additional information on 
verifying linearity is contained in Reference 9.
    5.2.4 Intercomparison: When possible, the photometer should be 
occasionally intercompared, either directly or via transfer standards, 
with calibration photometers used by other agencies or laboratories.
    5.2.5 Ozone losses: Some portion of the O3 may be lost 
upon contact with the photometer cell walls and gas handling components. 
The magnitude of this loss must be determined and used to correct the 
calculated O3 concentration. This loss must not exceed 5%. 
Some guidelines for quantitatively determining this loss are discussed 
in Reference 9.
    5.3 Assay of O3 concentrations.
    5.3.1 Allow the photometer system to warm up and stabilizer.
    5.3.2 Verify that the flowrate through the photometer absorption 
cell, F allows the cell to be flushed in a reasonably short period of 
time (2 liter/min is a typical flow). The precision of the measurements 
is inversely related to the time required for flushing, since the 
photometer drift error increases with time.

[[Page 43]]

    5.3.3 Insure that the flowrate into the output manifold is at least 
1 liter/min greater than the total flowrate required by the photometer 
and any other flow demand connected to the manifold.
    5.3.4 Insure that the flowrate of zero air, Fz, is at 
least 1 liter/min greater than the flowrate required by the photometer.
    5.3.5 With zero air flowing in the output manifold, actuate the two-
way valve to allow the photometer to sample first the manifold zero air, 
then Fz. The two photometer readings must be equal 
(I=Io).
    Note: In some commercially available photometers, the operation of 
the two-way valve and various other operations in section 5.3 may be 
carried out automatically by the photometer.
    5.3.6 Adjust the O3 generator to produce an O3 
concentration as needed.
    5.3.7 Actuate the two-way valve to allow the photometer to sample 
zero air until the absorption cell is thoroughly flushed and record the 
stable measured value of Io.
    5.3.8 Actuate the two-way valve to allow the photometer to sample 
the ozone concentration until the absorption cell is thoroughly flushed 
and record the stable measured value of I.
    5.3.9 Record the temperature and pressure of the sample in the 
photometer absorption cell. (See Reference 9 for guidance.)
    5.3.10 Calculate the O3 concentration from equation 4. An 
average of several determinations will provide better precision.
[GRAPHIC] [TIFF OMITTED] TR31AU93.032

where:

[O3]OUT = O3 concentration, ppm
[alpha] = absorption coefficient of O3 at 254 nm=308 
atm-1 cm-1 at 0 [deg]C and 760 torr
l = optical path length, cm
T = sample temperature, K
P = sample pressure, torr
L = correction factor for O3 losses from 5.2.5=(1-fraction 
O3 lost).

    Note: Some commercial photometers may automatically evaluate all or 
part of equation 4. It is the operator's responsibility to verify that 
all of the information required for equation 4 is obtained, either 
automatically by the photometer or manually. For ``automatic'' 
photometers which evaluate the first term of equation 4 based on a 
linear approximation, a manual correction may be required, particularly 
at higher O3 levels. See the photometer instruction manual 
and Reference 9 for guidance.
    5.3.11 Obtain additional O3 concentration standards as 
necessary by repeating steps 5.3.6 to 5.3.10 or by Option 1.
    5.4 Certification of transfer standards. A transfer standard is 
certified by relating the output of the transfer standard to one or more 
ozone standards as determined according to section 5.3. The exact 
procedure varies depending on the nature and design of the transfer 
standard. Consult Reference 8 for guidance.
    5.5 Calibration of ozone analyzers. Ozone analyzers are calibrated 
as follows, using ozone standards obtained directly according to section 
5.3 or by means of a certified transfer standard.
    5.5.1 Allow sufficient time for the O3 analyzer and the 
photometer or transfer standard to warmup and stabilize.
    5.5.2 Allow the O3 analyzer to sample zero air until a 
stable response is obtained and adjust the O3 analyzer's zero 
control. Offsetting the analyzer's zero adjustment to +5% of scale is 
recommended to facilitate observing negative zero drift. Record the 
stable zero air response as ``Z''.
    5.5.3 Generate an O3 concentration standard of 
approximately 80% of the desired upper range limit (URL) of the 
O3 analyzer. Allow the O3 analyzer to sample this 
O3 concentration standard until a stable response is 
obtained.
    5.5.4 Adjust the O3 analyzer's span control to obtain a 
convenient recorder response as indicated below:
    recorder response (%scale) =
    [GRAPHIC] [TIFF OMITTED] TR31AU93.033
    
where:

URL = upper range limit of the O3 analyzer, ppm
Z = recorder response with zero air, % scale

    Record the O3 concentration and the corresponding 
analyzer response. If substantial adjustment of the span control is 
necessary, recheck the zero and span adjustments by repeating steps 
5.5.2 to 5.5.4.
    5.5.5 Generate several other O3 concentration standards 
(at least 5 others are recommended) over the scale range of the 
O3 analyzer by adjusting the O3 source or by 
Option 1. For each O3 concentration standard, record the 
O3 and the corresponding analyzer response.
    5.5.6 Plot the O3 analyzer responses versus the 
corresponding O3 concentrations and draw the O3 
analyzer's calibration curve or calculate the appropriate response 
factor.
    5.5.7 Option 1: The various O3 concentrations required in 
steps 5.3.11 and 5.5.5 may be obtained by dilution of the O3 
concentration generated in steps 5.3.6 and 5.5.3. With this option, 
accurate flow measurements are required. The dynamic calibration system 
may be modified as shown in Figure 2 to allow for dilution air to be 
metered in downstream of the O3 generator. A mixing chamber 
between the O3 generator and the output manifold is also 
required. The flowrate through the O3 generator 
(Fo) and the dilution air flowrate

[[Page 44]]

(FD) are measured with a reliable flow or volume standard 
traceable to NBS. Each O3 concentration generated by dilution 
is calculated from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.031

where:

[O3]'OUT = diluted O3 concentration, 
ppm
F0 = flowrate through the O3 generator, liter/min
FD = diluent air flowrate, liter/min

                               References

    1. E.C.Y. Inn and Y. Tanaka, ``Absorption coefficient of Ozone in 
the Ultraviolet and Visible Regions'', J. Opt. Soc. Am., 43, 870 (1953).
    2. A. G. Hearn, ``Absorption of Ozone in the Ultraviolet and Visible 
Regions of the Spectrum'', Proc. Phys. Soc. (London), 78, 932 (1961).
    3. W. B. DeMore and O. Raper, ``Hartley Band Extinction Coefficients 
of Ozone in the Gas Phase and in Liquid Nitrogen, Carbon Monoxide, and 
Argon'', J. Phys. Chem., 68, 412 (1964).
    4. M. Griggs, ``Absorption Coefficients of Ozone in the Ultraviolet 
and Visible Regions'', J. Chem. Phys., 49, 857 (1968).
    5. K. H. Becker, U. Schurath, and H. Seitz, ``Ozone Olefin Reactions 
in the Gas Phase. 1. Rate Constants and Activation Energies'', Int'l 
Jour. of Chem. Kinetics, VI, 725 (1974).
    6. M. A. A. Clyne and J. A. Coxom, ``Kinetic Studies of Oxy-halogen 
Radical Systems'', Proc. Roy. Soc., A303, 207 (1968).
    7. J. W. Simons, R. J. Paur, H. A. Webster, and E. J. Bair, ``Ozone 
Ultraviolet Photolysis. VI. The Ultraviolet Spectrum'', J. Chem. Phys., 
59, 1203 (1973).
    8. Transfer Standards for Calibration of Ambient Air Monitoring 
Analyzers for Ozone, EPA publication number EPA-600/4-79-056, EPA, 
National Exposure Research Laboratory, Department E, (MD-77B), Research 
Triangle Park, NC 27711.
    9. Technical Assistance Document for the Calibration of Ambient 
Ozone Monitors, EPA publication number EPA-600/4-79-057, EPA, National 
Exposure Research Laboratory, Department E, (MD-77B), Research Triangle 
Park, NC 27711.

[[Page 45]]




[44 FR 8224, Feb. 8, 1979, as amended at 62 FR 38895, July 18, 1997]

[[Page 46]]

                    Appendix E to Part 50 [Reserved]

 Appendix F to Part 50--Measurement Principle and Calibration Procedure 
  for the Measurement of Nitrogen Dioxide in the Atmosphere (Gas Phase 
                           Chemiluminescence)

                       Principle and Applicability

    1. Atmospheric concentrations of nitrogen dioxide (NO2) 
are measured indirectly by photometrically measuring the light 
intensity, at wavelengths greater than 600 nanometers, resulting from 
the chemiluminescent reaction of nitric oxide (NO) with ozone 
(O3). (1,2,3) NO2 is first quantitatively reduced 
to NO(4,5,6) by means of a converter. NO, which commonly exists in 
ambient air together with NO2, passes through the converter 
unchanged causing a resultant total NOX concentration equal 
to NO+NO2. A sample of the input air is also measured without 
having passed through the converted. This latter NO measurement is 
subtracted from the former measurement (NO+NO2) to yield the 
final NO2 measurement. The NO and NO+NO2 
measurements may be made concurrently with dual systems, or cyclically 
with the same system provided the cycle time does not exceed 1 minute.
    2. Sampling considerations.
    2.1 Chemiluminescence NO/NOX/NO2 analyzers 
will respond to other nitrogen containing compounds, such as 
peroxyacetyl nitrate (PAN), which might be reduced to NO in the thermal 
converter. (7) Atmospheric concentrations of these potential 
interferences are generally low relative to NO2 and valid 
NO2 measurements may be obtained. In certain geographical 
areas, where the concentration of these potential interferences is known 
or suspected to be high relative to NO2, the use of an 
equivalent method for the measurement of NO2 is recommended.
    2.2 The use of integrating flasks on the sample inlet line of 
chemiluminescence NO/NOX/NO2 analyzers is optional 
and left to couraged. The sample residence time between the sampling 
point and the analyzer should be kept to a minimum to avoid erroneous 
NO2 measurements resulting from the reaction of ambient 
levels of NO and O3 in the sampling system.
    2.3 The use of particulate filters on the sample inlet line of 
chemiluminescence NO/NOX/NO2 analyzers is optional 
and left to the discretion of the user or the manufacturer.
Use of the filter should depend on the analyzer's susceptibility to 
interference, malfunction, or damage due to particulates. Users are 
cautioned that particulate matter concentrated on a filter may cause 
erroneous NO2 measurements and therefore filters should be 
changed frequently.
    3. An analyzer based on this principle will be considered a 
reference method only if it has been designated as a reference method in 
accordance with part 53 of this chapter.

                               Calibration

    1. Alternative A--Gas phase titration (GPT) of an NO standard with 
O3.
    Major equipment required: Stable O3 generator. 
Chemiluminescence NO/NOX/NO2 analyzer with strip 
chart recorder(s). NO concentration standard.
    1.1 Principle. This calibration technique is based upon the rapid 
gas phase reaction between NO and O3 to produce 
stoichiometric quantities of NO2 in accordance with the 
following equation: (8)
[GRAPHIC] [TIFF OMITTED] TC08NO91.075

The quantitative nature of this reaction is such that when the NO 
concentration is known, the concentration of NO2 can be 
determined. Ozone is added to excess NO in a dynamic calibration system, 
and the NO channel of the chemiluminescence NO/NOX/
NO2 analyzer is used as an indicator of changes in NO 
concentration. Upon the addition of O3, the decrease in NO 
concentration observed on the calibrated NO channel is equivalent to the 
concentration of NO2 produced. The amount of NO2 
generated may be varied by adding variable amounts of O3 from 
a stable uncalibrated O3 generator. (9)
    1.2 Apparatus. Figure 1, a schematic of a typical GPT apparatus, 
shows the suggested configuration of the components listed below. All 
connections between components in the calibration system downstream from 
the O3 generator should be of glass, Teflon[reg], 
or other non-reactive material.
    1.2.1 Air flow controllers. Devices capable of maintaining constant 
air flows within 2% of the required flowrate.
    1.2.2 NO flow controller. A device capable of maintaining constant 
NO flows within 2% of the required flowrate. 
Component parts in contact with the NO should be of a non-reactive 
material.
    1.2.3 Air flowmeters. Calibrated flowmeters capable of measuring and 
monitoring air flowrates with an accuracy of 2% of 
the measured flowrate.
    1.2.4 NO flowmeter. A calibrated flowmeter capable of measuring and 
monitoring NO flowrates with an accuracy of 2% of 
the measured flowrate. (Rotameters have been reported to operate 
unreliably when measuring low NO flows and are not recommended.)
    1.2.5 Pressure regulator for standard NO cylinder. This regulator 
must have a nonreactive diaphragm and internal parts and a suitable 
delivery pressure.
    1.2.6 Ozone generator. The generator must be capable of generating 
sufficient and stable levels of O3 for reaction with NO to 
generate

[[Page 47]]

NO2 concentrations in the range required. Ozone generators of 
the electric discharge type may produce NO and NO2 and are 
not recommended.
    1.2.7 Valve. A valve may be used as shown in Figure 1 to divert the 
NO flow when zero air is required at the manifold. The valve should be 
constructed of glass, Teflon[reg], or other nonreactive 
material.
    1.2.8 Reaction chamber. A chamber, constructed of glass, 
Teflon[reg], or other nonreactive material, for the 
quantitative reaction of O3 with excess NO. The chamber 
should be of sufficient volume (VRC) such that the residence time 
(tR) meets the requirements specified in 1.4. For practical 
reasons, tR should be less than 2 minutes.
    1.2.9 Mixing chamber. A chamber constructed of glass, 
Teflon[reg], or other nonreactive material and designed to 
provide thorough mixing of reaction products and diluent air. The 
residence time is not critical when the dynamic parameter specification 
given in 1.4 is met.
    1.2.10 Output manifold. The output manifold should be constructed of 
glass, Teflon[reg], or other non-reactive material and should 
be of sufficient diameter to insure an insignificant pressure drop at 
the analyzer connection. The system must have a vent designed to insure 
atmospheric pressure at the manifold and to prevent ambient air from 
entering the manifold.
    1.3 Reagents.
    1.3.1 NO concentration standard. Gas cylinder standard containing 50 
to 100 ppm NO in N2 with less than 1 ppm NO2. This 
standard must be traceable to a National Bureau of Standards (NBS) NO in 
N2 Standard Reference Material (SRM 1683 or SRM 1684), an NBS 
NO2 Standard Reference Material (SRM 1629), or an NBS/EPA-
approved commercially available Certified Reference Material (CRM). 
CRM's are described in Reference 14, and a list of CRM sources is 
available from the address shown for Reference 14. A recommended 
protocol for certifying NO gas cylinders against either an NO SRM or CRM 
is given in section 2.0.7 of Reference 15. Reference 13 gives procedures 
for certifying an NO gas cylinder against an NBS NO2 SRM and 
for determining the amount of NO2 impurity in an NO cylinder.
    1.3.2 Zero air. Air, free of contaminants which will cause a 
detectable response on the NO/NOX/NO2 analyzer or 
which might react with either NO, O3, or NO2 in 
the gas phase titration. A procedure for generating zero air is given in 
reference 13.
    1.4 Dynamic parameter specification.
    1.4.1 The O3 generator air flowrate (F0) and 
NO flowrate (FNO) (see Figure 1) must be adjusted such that 
the following relationship holds:
[GRAPHIC] [TIFF OMITTED] TC08NO91.076

[GRAPHIC] [TIFF OMITTED] TC08NO91.077

[GRAPHIC] [TIFF OMITTED] TC08NO91.078

where:

PR = dynamic parameter specification, determined empirically, to insure 
complete reaction of the available O3, ppm-minute
[NO]RC = NO concentration in the reaction chamber, ppm
R = residence time of the reactant gases in the reaction chamber, minute
[NO]STD = concentration of the undiluted NO standard, ppm
FNO = NO flowrate, scm\3\/min
FO = O3 generator air flowrate, scm\3\/min
VRC = volume of the reaction chamber, scm\3\

    1.4.2 The flow conditions to be used in the GPT system are 
determined by the following procedure:
    (a) Determine FT, the total flow required at the output manifold 
(FT=analyzer demand plus 10 to 50% excess).
    (b) Establish [NO]OUT as the highest NO concentration 
(ppm) which will be required at the output manifold. [NO]OUT 
should be approximately equivalent to 90% of the upper range limit (URL) 
of the NO2 concentration range to be covered.
    (c) Determine FNO as
    [GRAPHIC] [TIFF OMITTED] TC08NO91.079
    
    (d) Select a convenient or available reaction chamber volume. 
Initially, a trial VRC may be selected to be in the range of 
approximately 200 to 500 scm\3\.
    (e) Compute FO as
    
    
    (f) Compute tR as
    [GRAPHIC] [TIFF OMITTED] TC08NO91.080
    
Verify that tR < 2 minutes. If not, select a reaction chamber with a 
smaller VRC.
    (g) Compute the diluent air flowrate as
    [GRAPHIC] [TIFF OMITTED] TC08NO91.081
    
where:

FD = diluent air flowrate, scm\3\/min

    (h) If FO turns out to be impractical for the desired system, select 
a reaction chamber

[[Page 48]]

having a different VRC and recompute FO and FD.
    Note: A dynamic parameter lower than 2.75 ppm-minutes may be used if 
it can be determined empirically that quantitative reaction of 
O3 with NO occurs. A procedure for making this determination 
as well as a more detailed discussion of the above requirements and 
other related considerations is given in reference 13.
    1.5 Procedure.
    1.5.1 Assemble a dynamic calibration system such as the one shown in 
Figure 1.
    1.5.2 Insure that all flowmeters are calibrated under the conditions 
of use against a reliable standard such as a soap-bubble meter or wet-
test meter. All volumetric flowrates should be corrected to 25 [deg]C 
and 760 mm Hg. A discussion on the calibration of flowmeters is given in 
reference 13.
    1.5.3 Precautions must be taken to remove O2 and other 
contaminants from the NO pressure regulator and delivery system prior to 
the start of calibration to avoid any conversion of the standard NO to 
NO2. Failure to do so can cause significant errors in 
calibration. This problem may be minimized by (1) carefully evacuating 
the regulator, when possible, after the regulator has been connected to 
the cylinder and before opening the cylinder valve; (2) thoroughly 
flushing the regulator and delivery system with NO after opening the 
cylinder valve; (3) not removing the regulator from the cylinder between 
calibrations unless absolutely necessary. Further discussion of these 
procedures is given in reference 13.
    1.5.4 Select the operating range of the NO/NOX/
NO2 analyzer to be calibrated. In order to obtain maximum 
precision and accuracy for NO2 calibration, all three 
channels of the analyzer should be set to the same range. If operation 
of the NO and NOX channels on higher ranges is desired, 
subsequent recalibration of the NO and NOX channels on the 
higher ranges is recommended.
    Note: Some analyzer designs may require identical ranges for NO, 
NOX, and NO2 during operation of the analyzer.
    1.5.5 Connect the recorder output cable(s) of the NO/NOX/
NO2 analyzer to the input terminals of the strip chart 
recorder(s). All adjustments to the analyzer should be performed based 
on the appropriate strip chart readings. References to analyzer 
responses in the procedures given below refer to recorder responses.
    1.5.6 Determine the GPT flow conditions required to meet the dynamic 
parameter specification as indicated in 1.4.
    1.5.7 Adjust the diluent air and O3 generator air flows 
to obtain the flows determined in section 1.4.2. The total air flow must 
exceed the total demand of the analyzer(s) connected to the output 
manifold to insure that no ambient air is pulled into the manifold vent. 
Allow the analyzer to sample zero air until stable NO, NOX, 
and NO2 responses are obtained. After the responses have 
stabilized, adjust the analyzer zero control(s).
    Note: Some analyzers may have separate zero controls for NO, 
NOX, and NO2. Other analyzers may have separate 
zero controls only for NO and NOX, while still others may 
have only one zero control common to all three channels.
    Offsetting the analyzer zero adjustments to +5 percent of scale is 
recommended to facilitate observing negative zero drift. Record the 
stable zero air responses as ZNO, Znox, and Zno2.
    1.5.8 Preparation of NO and NOX calibration curves.
    1.5.8.1 Adjustment of NO span control. Adjust the NO flow from the 
standard NO cylinder to generate an NO concentration of approximately 80 
percent of the upper range limit (URL) of the NO range. This exact NO 
concentration is calculated from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.044

where:

[NO]OUT = diluted NO concentration at the output manifold, ppm

Sample this NO concentration until the NO and NOX responses 
have stabilized. Adjust the NO span control to obtain a recorder 
response as indicated below:

recorder response (percent scale) =
[GRAPHIC] [TIFF OMITTED] TR31AU93.045

where:

URL = nominal upper range limit of the NO channel, ppm
    Note: Some analyzers may have separate span controls for NO, 
NOX, and NO2. Other analyzers may have separate 
span controls only for NO and NOX, while still others may 
have only one span control common to all three channels. When only one 
span control is available, the span adjustment is made on the NO channel 
of the analyzer.
If substantial adjustment of the NO span control is necessary, it may be 
necessary to recheck the zero and span adjustments by repeating steps 
1.5.7 and 1.5.8.1. Record the NO concentration and the analyzer's NO 
response.
    1.5.8.2 Adjustment of NOX span control. When adjusting 
the analyzer's NOX span control, the presence of any 
NO2 impurity in the standard NO cylinder must be taken into 
account. Procedures for determining the amount of NO2 
impurity in the standard NO cylinder are given in reference 13. The 
exact NOX concentration is calculated from:

[[Page 49]]

[GRAPHIC] [TIFF OMITTED] TR31AU93.046

where:

[NOX]OUT = diluted NOX concentration at 
the output manifold, ppm
[NO2]IMP = concentration of NO2 
impurity in the standard NO cylinder, ppm

Adjust the NOX span control to obtain a recorder response as 
indicated below:

recorder response (% scale) =
[GRAPHIC] [TIFF OMITTED] TR31AU93.047

    Note: If the analyzer has only one span control, the span adjustment 
is made on the NO channel and no further adjustment is made here for 
NOX.

If substantial adjustment of the NOX span control is 
necessary, it may be necessary to recheck the zero and span adjustments 
by repeating steps 1.5.7 and 1.5.8.2. Record the NOX 
concentration and the analyzer's NOX response.
    1.5.8.3 Generate several additional concentrations (at least five 
evenly spaced points across the remaining scale are suggested to verify 
linearity) by decreasing FNO or increasing FD. For 
each concentration generated, calculate the exact NO and NOX 
concentrations using equations (9) and (11) respectively. Record the 
analyzer's NO and NOX responses for each concentration. Plot 
the analyzer responses versus the respective calculated NO and 
NOX concentrations and draw or calculate the NO and 
NOX calibration curves. For subsequent calibrations where 
linearity can be assumed, these curves may be checked with a two-point 
calibration consisting of a zero air point and NO and NOX 
concentrations of approximately 80% of the URL.
    1.5.9 Preparation of NO2 calibration curve.
    1.5.9.1 Assuming the NO2 zero has been properly adjusted 
while sampling zero air in step 1.5.7, adjust FO and 
FD as determined in section 1.4.2. Adjust FNO to 
generate an NO concentration near 90% of the URL of the NO range. Sample 
this NO concentration until the NO and NOX responses have 
stabilized. Using the NO calibration curve obtained in section 1.5.8, 
measure and record the NO concentration as [NO]orig. Using 
the NOX calibration curve obtained in section 1.5.8, measure 
and record the NOX concentration as 
[NOX]orig.
    1.5.9.2 Adjust the O3 generator to generate sufficient 
O3 to produce a decrease in the NO concentration equivalent 
to approximately 80% of the URL of the NO2 range. The 
decrease must not exceed 90% of the NO concentration determined in step 
1.5.9.1. After the analyzer responses have stabilized, record the 
resultant NO and NOX concentrations as [NO]rem and 
[NOX]rem.
    1.5.9.3 Calculate the resulting NO2 concentration from:
    [GRAPHIC] [TIFF OMITTED] TC08NO91.082
    
where:

[NO2]OUT = diluted NO2 concentration at 
the output manifold, ppm
[NO]orig = original NO concentration, prior to addition of 
O3, ppm
[NO]rem = NO concentration remaining after addition of 
O3, ppm

Adjust the NO2 span control to obtain a recorder response as 
indicated below:

recorder response (% scale) =
[GRAPHIC] [TIFF OMITTED] TR31AU93.048

    Note: If the analyzer has only one or two span controls, the span 
adjustments are made on the NO channel or NO and NOX channels 
and no further adjustment is made here for NO2.
If substantial adjustment of the NO2 span control is 
necessary, it may be necessary to recheck the zero and span adjustments 
by repeating steps 1.5.7 and 1.5.9.3. Record the NO2 
concentration and the corresponding analyzer NO2 and 
NOX responses.
    1.5.9.4 Maintaining the same FNO, FO, and 
FD as in section 1.5.9.1, adjust the ozone generator to 
obtain several other concentrations of NO2 over the 
NO2 range (at least five evenly spaced points across the 
remaining scale are suggested). Calculate each NO2 
concentration using equation (13) and record the corresponding analyzer 
NO2 and NOX responses. Plot the analyzer's 
NO2 responses versus the corresponding calculated 
NO2 concentrations and draw or calculate the NO2 
calibration curve.
    1.5.10 Determination of converter efficiency.
    1.5.10.1 For each NO2 concentration generated during the 
preparation of the NO2 calibration curve (see section 1.5.9) 
calculate the concentration of NO2 converted from:

[[Page 50]]

[GRAPHIC] [TIFF OMITTED] TC08NO91.083

where:

[NO2]CONV = concentration of NO2 
converted, ppm
[NOX]orig = original NOX concentration 
prior to addition of O3, ppm
[NOX]rem = NOX concentration remaining 
after addition of O3, ppm

    Note: Supplemental information on calibration and other procedures 
in this method are given in reference 13.
Plot [NO2]CONV (y-axis) versus 
[NO2]OUT (x-axis) and draw or calculate the 
converter efficiency curve. The slope of the curve times 100 is the 
average converter efficiency, EC The average converter 
efficiency must be greater than 96%; if it is less than 96%, replace or 
service the converter.
    2. Alternative B--NO2 permeation device.
    Major equipment required:
    Stable O3 generator.
    Chemiluminescence NO/NOX/NO2 analyzer with strip chart 
recorder(s).
    NO concentration standard.
    NO2 concentration standard.
    2.1 Principle. Atmospheres containing accurately known 
concentrations of nitrogen dioxide are generated by means of a 
permeation device. (10) The permeation device emits NO2 at a 
known constant rate provided the temperature of the device is held 
constant (0.1 [deg]C) and the device has been 
accurately calibrated at the temperature of use. The NO2 
emitted from the device is diluted with zero air to produce 
NO2 concentrations suitable for calibration of the 
NO2 channel of the NO/NOX/NO2 analyzer. An NO 
concentration standard is used for calibration of the NO and NOX 
channels of the analyzer.
    2.2 Apparatus. A typical system suitable for generating the required 
NO and NO2 concentrations is shown in Figure 2. All 
connections between components downstream from the permeation device 
should be of glass, Teflon[reg], or other non-reactive 
material.
    2.2.1 Air flow controllers. Devices capable of maintaining constant 
air flows within 2% of the required flowrate.
    2.2.2 NO flow controller. A device capable of maintaining constant 
NO flows within 2% of the required flowrate. 
Component parts in contact with the NO must be of a non-reactive 
material.
    2.2.3 Air flowmeters. Calibrated flowmeters capable of measuring and 
monitoring air flowrates with an accuracy of 2% of 
the measured flowrate.
    2.2.4 NO flowmeter. A calibrated flowmeter capable of measuring and 
monitoring NO flowrates with an accuracy of 2% of 
the measured flowrate. (Rotameters have been reported to operate 
unreliably when measuring low NO flows and are not recommended.)
    2.2.5 Pressure regulator for standard NO cylinder. This regulator 
must have a non-reactive diaphragm and internal parts and a suitable 
delivery pressure.
    2.2.6 Drier. Scrubber to remove moisture from the permeation device 
air system. The use of the drier is optional with NO2 
permeation devices not sensitive to moisture. (Refer to the supplier's 
instructions for use of the permeation device.)
    2.2.7 Constant temperature chamber. Chamber capable of housing the 
NO2 permeation device and maintaining its temperature to 
within 0.1 [deg]C.
    2.2.8 Temperature measuring device. Device capable of measuring and 
monitoring the temperature of the NO2 permeation device with 
an accuracy of 0.05 [deg]C.
    2.2.9 Valves. A valve may be used as shown in Figure 2 to divert the 
NO2 from the permeation device when zero air or NO is 
required at the manifold. A second valve may be used to divert the NO 
flow when zero air or NO2 is required at the manifold.
    The valves should be constructed of glass, Teflon[reg], 
or other nonreactive material.
    2.2.10 Mixing chamber. A chamber constructed of glass, 
Teflon[reg], or other nonreactive material and designed to 
provide thorough mixing of pollutant gas streams and diluent air.
    2.2.11 Output manifold. The output manifold should be constructed of 
glass, Teflon[reg], or other non-reactive material and should 
be of sufficient diameter to insure an insignificant pressure drop at 
the analyzer connection. The system must have a vent designed to insure 
atmospheric pressure at the manifold and to prevent ambient air from 
entering the manifold.
    2.3 Reagents.
    2.3.1 Calibration standards. Calibration standards are required for 
both NO and NO2. The reference standard for the calibration 
may be either an NO or NO2 standard, and must be traceable to 
a National Bureau of Standards (NBS) NO in N2 Standard 
Reference Material (SRM 1683 or SRM 1684), and NBS NO2 
Standard Reference Material (SRM 1629), or an NBS/EPA-approved 
commercially available Certified Reference Material (CRM). CRM's are 
described in Reference 14, and a list of CRM sources is available from 
the address shown for Reference 14. Reference 15 gives recommended 
procedures for certifying an NO gas cylinder against an NO

[[Page 51]]

SRM or CRM and for certifying an NO2 permeation device 
against an NO2 SRM. Reference 13 contains procedures for 
certifying an NO gas cylinder against an NO2 SRM and for 
certifying an NO2 permeation device against an NO SRM or CRM. 
A procedure for determining the amount of NO2 impurity in an 
NO cylinder is also contained in Reference 13. The NO or NO2 
standard selected as the reference standard must be used to certify the 
other standard to ensure consistency between the two standards.
    2.3.1.1 NO2 Concentration standard. A permeation device 
suitable for generating NO2 concentrations at the required 
flow-rates over the required concentration range. If the permeation 
device is used as the reference standard, it must be traceable to an SRM 
or CRM as specified in 2.3.1. If an NO cylinder is used as the reference 
standard, the NO2 permeation device must be certified against 
the NO standard according to the procedure given in Reference 13. The 
use of the permeation device should be in strict accordance with the 
instructions supplied with the device. Additional information regarding 
the use of permeation devices is given by Scaringelli et al. (11) and 
Rook et al. (12).
    2.3.1.2 NO Concentration standard. Gas cylinder containing 50 to 100 
ppm NO in N2 with less than 1 ppm NO2. If this 
cylinder is used as the reference standard, the cylinder must be 
traceable to an SRM or CRM as specified in 2.3.1. If an NO2 
permeation device is used as the reference standard, the NO cylinder 
must be certified against the NO2 standard according to the 
procedure given in Reference 13. The cylinder should be recertified on a 
regular basis as determined by the local quality control program.
    2.3.3 Zero air. Air, free of contaminants which might react with NO 
or NO2 or cause a detectable response on the NO/NOX/
NO2 analyzer. When using permeation devices that are 
sensitive to moisture, the zero air passing across the permeation device 
must be dry to avoid surface reactions on the device. (Refer to the 
supplier's instructions for use of the permeation device.) A procedure 
for generating zero air is given in reference 13.
    2.4 Procedure.
    2.4.1 Assemble the calibration apparatus such as the typical one 
shown in Figure 2.
    2.4.2 Insure that all flowmeters are calibrated under the conditions 
of use against a reliable standard such as a soap bubble meter or wet-
test meter. All volumetric flowrates should be corrected to 25 [deg]C 
and 760 mm Hg. A discussion on the calibration of flowmeters is given in 
reference 13.
    2.4.3 Install the permeation device in the constant temperature 
chamber. Provide a small fixed air flow (200-400 scm\3\/min) across the 
device. The permeation device should always have a continuous air flow 
across it to prevent large buildup of NO2 in the system and a 
consequent restabilization period. Record the flowrate as FP. Allow the 
device to stabilize at the calibration temperature for at least 24 
hours. The temperature must be adjusted and controlled to within 0.1 [deg]C or less of the calibration temperature as 
monitored with the temperature measuring device.
    2.4.4 Precautions must be taken to remove O2 and other 
contaminants from the NO pressure regulator and delivery system prior to 
the start of calibration to avoid any conversion of the standard NO to 
NO2. Failure to do so can cause significant errors in 
calibration. This problem may be minimized by
    (1) Carefully evacuating the regulator, when possible, after the 
regulator has been connected to the cylinder and before opening the 
cylinder valve;
    (2) Thoroughly flushing the regulator and delivery system with NO 
after opening the cylinder valve;
    (3) Not removing the regulator from the cylinder between 
calibrations unless absolutely necessary. Further discussion of these 
procedures is given in reference 13.
    2.4.5 Select the operating range of the NO/NOX NO2 
analyzer to be calibrated. In order to obtain maximum precision and 
accuracy for NO2 calibration, all three channels of the 
analyzer should be set to the same range. If operation of the NO and NOX 
channels on higher ranges is desired, subsequent recalibration of the NO 
and NOX channels on the higher ranges is recommended.
    Note: Some analyzer designs may require identical ranges for NO, 
NOX, and NO2 during operation of the analyzer.
    2.4.6 Connect the recorder output cable(s) of the NO/NOX/
NO2 analyzer to the input terminals of the strip chart 
recorder(s). All adjustments to the analyzer should be performed based 
on the appropriate strip chart readings. References to analyzer 
responses in the procedures given below refer to recorder responses.
    2.4.7 Switch the valve to vent the flow from the permeation device 
and adjust the diluent air flowrate, FD, to provide zero air at the 
output manifold. The total air flow must exceed the total demand of the 
analyzer(s) connected to the output manifold to insure that no ambient 
air is pulled into the manifold vent. Allow the analyzer to sample zero 
air until stable NO, NOX, and NO2 responses are obtained. 
After the responses have stabilized, adjust the analyzer zero 
control(s).
    Note: Some analyzers may have separate zero controls for NO, NOX, 
and NO2. Other analyzers may have separate zero controls only 
for NO and NOX, while still others may have only one zero common control 
to all three channels.
Offsetting the analyzer zero adjustments to +5% of scale is recommended 
to facilitate observing negative zero drift. Record the stable zero air 
responses as ZNO, ZNOX, and 
ZNO2.

[[Page 52]]

    2.4.8 Preparation of NO and NOX calibration curves.
    2.4.8.1 Adjustment of NO span control. Adjust the NO flow from the 
standard NO cylinder to generate an NO concentration of approximately 
80% of the upper range limit (URL) of the NO range. The exact NO 
concentration is calculated from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.049

where:

[NO]OUT = diluted NO concentration at the output manifold, 
ppm
FNO = NO flowrate, scm\3\/min
[NO]STD=concentration of the undiluted NO standard, ppm
FD = diluent air flowrate, scm\3\/min

Sample this NO concentration until the NO and NOX responses have 
stabilized. Adjust the NO span control to obtain a recorder response as 
indicated below:

recorder response (% scale) =
[GRAPHIC] [TIFF OMITTED] TR31AU93.050

[GRAPHIC] [TIFF OMITTED] TR31AU93.051

where:

URL = nominal upper range limit of the NO channel, ppm

    Note: Some analyzers may have separate span controls for NO, NOX, 
and NO2. Other analyzers may have separate span controls only 
for NO and NOX, while still others may have only one span control common 
to all three channels. When only one span control is available, the span 
adjustment is made on the NO channel of the analyzer.

If substantial adjustment of the NO span control is necessary, it may be 
necessary to recheck the zero and span adjustments by repeating steps 
2.4.7 and 2.4.8.1. Record the NO concentration and the analyzer's NO 
response.
    2.4.8.2 Adjustment of NOX span control. When adjusting the 
analyzer's NOX span control, the presence of any NO2 impurity 
in the standard NO cylinder must be taken into account. Procedures for 
determining the amount of NO2 impurity in the standard NO 
cylinder are given in reference 13. The exact NOX concentration is 
calculated from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.052

where:

[NOX]OUT = diluted NOX cencentration at 
the output manifold, ppm
[NO2]IMP = concentration of NO2 
impurity in the standard NO cylinder, ppm

Adjust the NOX span control to obtain a convenient recorder response as 
indicated below:

recorder response (% scale)
[GRAPHIC] [TIFF OMITTED] TR31AU93.053

    Note: If the analyzer has only one span control, the span adjustment 
is made on the NO channel and no further adjustment is made here for 
NOX.
If substantial adjustment of the NOX span control is 
necessary, it may be necessary to recheck the zero and span adjustments 
by repeating steps 2.4.7 and 2.4.8.2. Record the NOX 
concentration and the analyzer's NOX response.
    2.4.8.3 Generate several additional concentrations (at least five 
evenly spaced points across the remaining scale are suggested to verify 
linearity) by decreasing FNO or increasing FD. For each 
concentration generated, calculate the exact NO and NOX 
concentrations using equations (16) and (18) respectively. Record the 
analyzer's NO and NOX responses for each concentration. Plot 
the analyzer responses versus the respective calculated NO and 
NOX concentrations and draw or calculate the NO and 
NOX calibration curves. For subsequent calibrations where 
linearity can be assumed, these curves may be checked with a two-point 
calibration consisting of a zero point and NO and NOX 
concentrations of approximately 80 percent of the URL.
    2.4.9 Preparation of NO2 calibration curve.
    2.4.9.1 Remove the NO flow. Assuming the NO2 zero has 
been properly adjusted while sampling zero air in step 2.4.7, switch the 
valve to provide NO2 at the output manifold.
    2.4.9.2 Adjust FD to generate an NO2 concentration of 
approximately 80 percent of the URL of the NO2 range. The 
total air flow must exceed the demand of the analyzer(s) under 
calibration. The actual concentration of NO2 is calculated 
from:
[GRAPHIC] [TIFF OMITTED] TR31AU93.054

where:

[NO2]OUT = diluted NO2 concentration at 
the output manifold, ppm
R = permeation rate, [micro]g/min
K = 0.532 [micro]l NO2/[micro]g NO2 (at 25 [deg]C 
and 760 mm Hg)
Fp = air flowrate across permeation device, scm\3\/min
FD = diluent air flowrate, scm\3\/min


[[Page 53]]


Sample this NO2 concentration until the NOX and 
NO2 responses have stabilized. Adjust the NO2 span 
control to obtain a recorder response as indicated below:

recorder response (% scale)
[GRAPHIC] [TIFF OMITTED] TR31AU93.055

    Note: If the analyzer has only one or two span controls, the span 
adjustments are made on the NO channel or NO and NOX channels 
and no further adjustment is made here for NO2.

If substantial adjustment of the NO2 span control is 
necessary it may be necessary to recheck the zero and span adjustments 
by repeating steps 2.4.7 and 2.4.9.2. Record the NO2 
concentration and the analyzer's NO2 response. Using the 
NOX calibration curve obtained in step 2.4.8, measure and 
record the NOX concentration as [NOX]M.
    2.4.9.3 Adjust FD to obtain several other concentrations of 
NO2 over the NO2 range (at least five evenly 
spaced points across the remaining scale are suggested). Calculate each 
NO2 concentration using equation (20) and record the 
corresponding analyzer NO2 and NOX responses. Plot 
the analyzer's NO2 responses versus the corresponding 
calculated NO2 concentrations and draw or calculate the 
NO2 calibration curve.
    2.4.10 Determination of converter efficiency.
    2.4.10.1 Plot [NOX]M (y-axis) versus 
[NO2]OUT (x-axis) and draw or calculate the 
converter efficiency curve. The slope of the curve times 100 is the 
average converter efficiency, EC. The average converter efficiency must 
be greater than 96 percent; if it is less than 96 percent, replace or 
service the converter.
    Note: Supplemental information on calibration and other procedures 
in this method are given in reference 13.
    3. Frequency of calibration. The frequency of calibration, as well 
as the number of points necessary to establish the calibration curve and 
the frequency of other performance checks, will vary from one analyzer 
to another. The user's quality control program should provide guidelines 
for initial establishment of these variables and for subsequent 
alteration as operational experience is accumulated. Manufacturers of 
analyzers should include in their instruction/operation manuals 
information and guidance as to these variables and on other matters of 
operation, calibration, and quality control.

                               References

    1. A. Fontijn, A. J. Sabadell, and R. J. Ronco, ``Homogeneous 
Chemiluminescent Measurement of Nitric Oxide with Ozone,'' Anal. Chem., 
42, 575 (1970).
    2. D. H. Stedman, E. E. Daby, F. Stuhl, and H. Niki, ``Analysis of 
Ozone and Nitric Oxide by a Chemiluminiscent Method in Laboratory and 
Atmospheric Studies of Photochemical Smog,'' J. Air Poll. Control 
Assoc., 22, 260 (1972).
    3. B. E. Martin, J. A. Hodgeson, and R. K. Stevens, ``Detection of 
Nitric Oxide Chemiluminescence at Atmospheric Pressure,'' Presented at 
164th National ACS Meeting, New York City, August 1972.
    4. J. A. Hodgeson, K. A. Rehme, B. E. Martin, and R. K. Stevens, 
``Measurements for Atmospheric Oxides of Nitrogen and Ammonia by 
Chemiluminescence,'' Presented at 1972 APCA Meeting, Miami, FL, June 
1972.
    5. R. K. Stevens and J. A. Hodgeson, ``Applications of 
Chemiluminescence Reactions to the Measurement of Air Pollutants,'' 
Anal. Chem., 45, 443A (1973).
    6. L. P. Breitenbach and M. Shelef, ``Development of a Method for 
the Analysis of NO2 and NH3 by NO-Measuring 
Instruments,'' J. Air Poll. Control Assoc., 23, 128 (1973).
    7. A. M. Winer, J. W. Peters, J. P. Smith, and J. N. Pitts, Jr., 
``Response of Commercial Chemiluminescent NO-NO2 Analyzers to 
Other Nitrogen-Containing Compounds,'' Environ. Sci. Technol., 8, 1118 
(1974).
    8. K. A. Rehme, B. E. Martin, and J. A. Hodgeson, Tentative Method 
for the Calibration of Nitric Oxide, Nitrogen Dioxide, and Ozone 
Analyzers by Gas Phase Titration,'' EPA-R2-73-246, March 1974.
    9. J. A. Hodgeson, R. K. Stevens, and B. E. Martin, ``A Stable Ozone 
Source Applicable as a Secondary Standard for Calibration of Atmospheric 
Monitors,'' ISA Transactions, 11, 161 (1972).
    10. A. E. O'Keeffe and G. C. Ortman, ``Primary Standards for Trace 
Gas Analysis,'' Anal. Chem., 38, 760 (1966).
    11. F. P. Scaringelli, A. E. O'Keeffe, E. Rosenberg, and J. P. Bell, 
``Preparation of Known Concentrations of Gases and Vapors with 
Permeation Devices Calibrated Gravimetrically,'' Anal. Chem., 42, 871 
(1970).
    12. H. L. Rook, E. E. Hughes, R. S. Fuerst, and J. H. Margeson, 
``Operation Characteristics of NO2 Permeation Devices,'' 
Presented at 167th National ACS Meeting, Los Angeles, CA, April 1974.
    13. E. C. Ellis, ``Technical Assistance Document for the 
Chemiluminescence Measurement of Nitrogen Dioxide,'' EPA-E600/4-75-003 
(Available in draft form from the United States Environmental Protection 
Agency, Department E (MD-76), Environmental Monitoring and Support 
Laboratory, Research Triangle Park, NC 27711).
    14. A Procedure for Establishing Traceability of Gas Mixtures to 
Certain National Bureau of Standards Standard Reference Materials. EPA-
600/7-81-010, Joint publication by NBS and EPA. Available from the U.S. 
Environmental Protection Agency, Environmental Monitoring Systems 
Laboratory (MD-77), Research Triangle Park, NC 27711, May 1981.

[[Page 54]]

    15. Quality Assurance Handbook for Air Pollution Measurement 
Systems, Volume II, Ambient Air Specific Methods. The U.S. Environmental 
Protection Agency, Environmental Monitoring Systems Laboratory, Research 
Triangle Park, NC 27711. Publication No. EAP-600/4-77-027a.



[[Page 55]]





[41 FR 52688, Dec. 1, 1976, as amended at 48 FR 2529, Jan 20, 1983]

Appendix G to Part 50--Reference Method for the Determination of Lead in 
         Suspended Particulate Matter Collected From Ambient Air

    1. Principle and applicability.
    1.1 Ambient air suspended particulate matter is collected on a 
glass-fiber filter for 24 hours using a high volume air sampler. The 
analysis of the 24-hour samples may be performed for either individual 
samples or composites of the samples collected over a calendar month or 
quarter, provided that the compositing procedure has been approved in 
accordance with section 2.8 of appendix C to part 58 of this chapter--
Modifications of methods by users. (Guidance or assistance in requesting 
approval under Section 2.8 can be obtained from the address given in 
section 2.7 of appendix C to part 58 of this chapter.)
    1.2 Lead in the particulate matter is solubilized by extraction with 
nitric acid (HNO3), facilitated by heat or by a mixture of 
HNO3 and hydrochloric acid (HCl) facilitated by 
ultrasonication.
    1.3 The lead content of the sample is analyzed by atomic absorption 
spectrometry using an air-acetylene flame, the 283.3 or 217.0 nm lead 
absorption line, and the optimum instrumental conditions recommended by 
the manufacturer.
    1.4 The ultrasonication extraction with HNO3/HCl will 
extract metals other than lead from ambient particulate matter.
    2. Range, sensitivity, and lower detectable limit. The values given 
below are typical of the methods capabilities. Absolute values will vary 
for individual situations depending on the type of instrument used, the 
lead line, and operating conditions.
    2.1 Range. The typical range of the method is 0.07 to 7.5 [micro]g 
Pb/m\3\ assuming an upper linear range of analysis of 15 [micro]g/ml and 
an air volume of 2,400 m\3\.
    2.2 Sensitivity. Typical sensitivities for a 1 percent change in 
absorption (0.0044 absorbance units) are 0.2 and 0.5 [micro]g Pb/ml for 
the 217.0 and 283.3 nm lines, respectively.
    2.3 Lower detectable limit (LDL). A typical LDL is 0.07 [micro]g Pb/
m\3\. The above value was calculated by doubling the between-laboratory 
standard deviation obtained for the lowest measurable lead concentration 
in a collaborative test of the method.(15) An air volume of 2,400 m\3\ 
was assumed.
    3. Interferences. Two types of interferences are possible: chemical 
and light scattering.
    3.1 Chemical. Reports on the absence (1, 2, 3, 4, 5) of chemical 
interferences far outweigh those reporting their presence, (6) 
therefore, no correction for chemical interferences is given here. If 
the analyst suspects that the sample matrix is causing a chemical 
interference, the interference can be verified and corrected for by 
carrying out the analysis

[[Page 56]]

with and without the method of standard additions.(7)
    3.2 Light scattering. Nonatomic absorption or light scattering, 
produced by high concentrations of dissolved solids in the sample, can 
produce a significant interference, especially at low lead 
concentrations. (2) The interference is greater at the 217.0 nm line 
than at the 283.3 nm line. No interference was observed using the 283.3 
nm line with a similar method.(1)
    Light scattering interferences can, however, be corrected for 
instrumentally. Since the dissolved solids can vary depending on the 
origin of the sample, the correction may be necessary, especially when 
using the 217.0 nm line. Dual beam instruments with a continuum source 
give the most accurate correction. A less accurate correction can be 
obtained by using a nonabsorbing lead line that is near the lead 
analytical line. Information on use of these correction techniques can 
be obtained from instrument manufacturers' manuals.
    If instrumental correction is not feasible, the interference can be 
eliminated by use of the ammonium pyrrolidinecarbodithioate-
methylisobutyl ketone, chelation-solvent extraction technique of sample 
preparation.(8)
    4. Precision and bias.
    4.1 The high-volume sampling procedure used to collect ambient air 
particulate matter has a between-laboratory relative standard deviation 
of 3.7 percent over the range 80 to 125 [micro]g/m\3\.(9) The combined 
extraction-analysis procedure has an average within-laboratory relative 
standard deviation of 5 to 6 percent over the range 1.5 to 15 [micro]g 
Pb/ml, and an average between laboratory relative standard deviation of 
7 to 9 percent over the same range. These values include use of either 
extraction procedure.
    4.2 Single laboratory experiments and collaborative testing indicate 
that there is no significant difference in lead recovery between the hot 
and ultrasonic extraction procedures.(15)
    5. Apparatus.
    5.1 Sampling.
    5.1.1 High-Volume Sampler. Use and calibrate the sampler as 
described in appendix B to this part.
    5.2 Analysis.
    5.2.1 Atomic absorption spectrophotometer. Equipped with lead hollow 
cathode or electrodeless discharge lamp.
    5.2.1.1 Acetylene. The grade recommended by the instrument 
manufacturer should be used. Change cylinder when pressure drops below 
50-100 psig.
    5.2.1.2 Air. Filtered to remove particulate, oil, and water.
    5.2.2 Glassware. Class A borosilicate glassware should be used 
throughout the analysis.
    5.2.2.1 Beakers. 30 and 150 ml. graduated, Pyrex.
    5.2.2.2 Volumetric flasks. 100-ml.
    5.2.2.3 Pipettes. To deliver 50, 30, 15, 8, 4, 2, 1 ml.
    5.2.2.4 Cleaning. All glassware should be scrupulously cleaned. The 
following procedure is suggested. Wash with laboratory detergent, rinse, 
soak for 4 hours in 20 percent (w/w) HNO3, rinse 3 times with 
distilled-deionized water, and dry in a dust free manner.
    5.2.3 Hot plate.
    5.2.4. Ultrasonication water bath, unheated. Commercially available 
laboratory ultrasonic cleaning baths of 450 watts or higher ``cleaning 
power,'' i.e., actual ultrasonic power output to the bath have been 
found satisfactory.
    5.2.5 Template. To aid in sectioning the glass-fiber filter. See 
figure 1 for dimensions.
    5.2.6 Pizza cutter. Thin wheel. Thickness 1mm.
    5.2.7 Watch glass.
    5.2.8 Polyethylene bottles. For storage of samples. Linear 
polyethylene gives better storage stability than other polyethylenes and 
is preferred.
    5.2.9 Parafilm ``M''.\1\ American Can Co., Marathon Products, 
Neenah, Wis., or equivalent.
---------------------------------------------------------------------------

    \1\ Mention of commercial products does not imply endorsement by the 
U.S. Environmental Protection Agency.
---------------------------------------------------------------------------

    6. Reagents.
    6.1 Sampling.
    6.1.1 Glass fiber filters. The specifications given below are 
intended to aid the user in obtaining high quality filters with 
reproducible properties. These specifications have been met by EPA 
contractors.
    6.1.1.1 Lead content. The absolute lead content of filters is not 
critical, but low values are, of course, desirable. EPA typically 
obtains filters with a lead content of 75 [micro]g/filter.
    It is important that the variation in lead content from filter to 
filter, within a given batch, be small.
    6.1.1.2 Testing.
    6.1.1.2.1 For large batches of filters (500 filters) 
select at random 20 to 30 filters from a given batch. For small batches 
(500 filters) a lesser number of filters may be taken. Cut 
one \3/4\x8 strip from each filter anywhere in the 
filter. Analyze all strips, separately, according to the directions in 
sections 7 and 8.
    6.1.1.2.2 Calculate the total lead in each filter as
    [GRAPHIC] [TIFF OMITTED] TC08NO91.084
    
where:

Fb = Amount of lead per 72 square inches of filter, [micro]g.

    6.1.1.2.3 Calculate the mean, Fb, of the values and the 
relative standard deviation

[[Page 57]]

(standard deviation/mean x 100). If the relative standard deviation is 
high enough so that, in the analysts opinion, subtraction of 
Fb, (section 10.3) may result in a significant error in the 
[micro]g Pb/m\3\, the batch should be rejected.
    6.1.1.2.4 For acceptable batches, use the value of Fb to 
correct all lead analyses (section 10.3) of particulate matter collected 
using that batch of filters. If the analyses are below the LDL (section 
2.3) no correction is necessary.
    6.2 Analysis.
    6.2.1 Concentrated (15.6 M) HNO3. ACS reagent grade 
HNO3 and commercially available redistilled HNO3 
has found to have sufficiently low lead concentrations.
    6.2.2 Concentrated (11.7 M) HCl. ACS reagent grade.
    6.2.3 Distilled-deionized water. (D.I. water).
    6.2.4 3 M HNO3. This solution is used in the hot 
extraction procedure. To prepare, add 192 ml of concentrated 
HNO3 to D.I. water in a 1 l volumetric flask. Shake well, 
cool, and dilute to volume with D.I. water. Caution: Nitric acid fumes 
are toxic. Prepare in a well ventilated fume hood.
    6.2.5 0.45 M HNO3. This solution is used as the matrix 
for calibration standards when using the hot extraction procedure. To 
prepare, add 29 ml of concentrated HNO3 to D.I. water in a 1 
l volumetric flask. Shake well, cool, and dilute to volume with D.I. 
water.
    6.2.6 2.6 M HNO3+0 to 0.9 M HCl. This solution is used in 
the ultrasonic extraction procedure. The concentration of HCl can be 
varied from 0 to 0.9 M. Directions are given for preparation of a 2.6 M 
HNO3+0.9 M HCl solution. Place 167 ml of concentrated 
HNO3 into a 1 l volumetric flask and add 77 ml of 
concentrated HCl. Stir 4 to 6 hours, dilute to nearly 1 l with D.I. 
water, cool to room temperature, and dilute to 1 l.
    6.2.7 0.40 M HNO3 + X M HCl. This solution is used as the 
matrix for calibration standards when using the ultrasonic extraction 
procedure. To prepare, add 26 ml of concentrated HNO3, plus 
the ml of HCl required, to a 1 l volumetric flask. Dilute to nearly 1 l 
with D.I. water, cool to room temperature, and dilute to 1 l. The amount 
of HCl required can be determined from the following equation:
[GRAPHIC] [TIFF OMITTED] TC08NO91.085

where:

y = ml of concentrated HCl required.
x = molarity of HCl in 6.2.6.
0.15 = dilution factor in 7.2.2.

    6.2.8 Lead nitrate, Pb(NO3)2. ACS reagent 
grade, purity 99.0 percent. Heat for 4 hours at 120 [deg]C and cool in a 
desiccator.
    6.3 Calibration standards.
    6.3.1 Master standard, 1000 [micro]g Pb/ml in HNO3. 
Dissolve 1.598 g of Pb(NO3)2 in 0.45 M 
HNO3 contained in a 1 l volumetric flask and dilute to volume 
with 0.45 M HNO3.
    6.3.2 Master standard, 1000 [micro]g Pb/ml in HNO3/HCl. 
Prepare as in section 6.3.1 except use the HNO3/HCl solution 
in section 6.2.7.
    Store standards in a polyethylene bottle. Commercially available 
certified lead standard solutions may also be used.
    7. Procedure.
    7.1 Sampling. Collect samples for 24 hours using the procedure 
described in reference 10 with glass-fiber filters meeting the 
specifications in section 6.1.1. Transport collected samples to the 
laboratory taking care to minimize contamination and loss of sample. 
(16).
    7.2 Sample preparation.
    7.2.1 Hot extraction procedure.
    7.2.1.1 Cut a \3/4\x8 strip from the exposed 
filter using a template and a pizza cutter as described in Figures 1 and 
2. Other cutting procedures may be used.
    Lead in ambient particulate matter collected on glass fiber filters 
has been shown to be uniformly distributed across the filter. \1,3,11\ 
Another study \12\ has shown that when sampling near a roadway, strip 
position contributes significantly to the overall variability associated 
with lead analyses. Therefore, when sampling near a roadway, additional 
strips should be analyzed to minimize this variability.
    7.2.1.2 Fold the strip in half twice and place in a 150-ml beaker. 
Add 15 ml of 3 M HNO3 to cover the sample. The acid should 
completely cover the sample. Cover the beaker with a watch glass.
    7.2.1.3 Place beaker on the hot-plate, contained in a fume hood, and 
boil gently for 30 min. Do not let the sample evaporate to dryness. 
Caution: Nitric acid fumes are toxic.
    7.2.1.4 Remove beaker from hot plate and cool to near room 
temperature.
    7.2.1.5 Quantitatively transfer the sample as follows:
    7.2.1.5.1 Rinse watch glass and sides of beaker with D.I. water.
    7.2.1.5.2 Decant extract and rinsings into a 100-ml volumetric 
flask.
    7.2.1.5.3 Add D.I. water to 40 ml mark on beaker, cover with watch 
glass, and set aside for a minimum of 30 minutes. This is a critical 
step and cannot be omitted since it allows the HNO3 trapped 
in the filter to diffuse into the rinse water.
    7.2.1.5.4 Decant the water from the filter into the volumetric 
flask.
    7.2.1.5.5 Rinse filter and beaker twice with D.I. water and add 
rinsings to volumetric flask until total volume is 80 to 85 ml.
    7.2.1.5.6 Stopper flask and shake vigorously. Set aside for 
approximately 5 minutes or until foam has dissipated.
    7.2.1.5.7 Bring solution to volume with D.I. water. Mix thoroughly.

[[Page 58]]

    7.2.1.5.8 Allow solution to settle for one hour before proceeding 
with analysis.
    7.2.1.5.9 If sample is to be stored for subsequent analysis, 
transfer to a linear polyethylene bottle.
    7.2.2 Ultrasonic extraction procedure.
    7.2.2.1 Cut a \3/4\x8 strip from the exposed 
filter as described in section 7.2.1.1.
    7.2.2.2 Fold the strip in half twice and place in a 30 ml beaker. 
Add 15 ml of the HNO3/HCl solution in section 6.2.6. The acid 
should completely cover the sample. Cover the beaker with parafilm.
    The parafilm should be placed over the beaker such that none of the 
parafilm is in contact with water in the ultrasonic bath. Otherwise, 
rinsing of the parafilm (section 7.2.2.4.1) may contaminate the sample.
    7.2.2.3 Place the beaker in the ultrasonication bath and operate for 
30 minutes.
    7.2.2.4 Quantitatively transfer the sample as follows:
    7.2.2.4.1 Rinse parafilm and sides of beaker with D.I. water.
    7.2.2.4.2 Decant extract and rinsings into a 100 ml volumetric 
flask.
    7.2.2.4.3 Add 20 ml D.I. water to cover the filter strip, cover with 
parafilm, and set aside for a minimum of 30 minutes. This is a critical 
step and cannot be omitted. The sample is then processed as in sections 
7.2.1.5.4 through 7.2.1.5.9.
    Note: Samples prepared by the hot extraction procedure are now in 
0.45 M HNO3. Samples prepared by the ultrasonication 
procedure are in 0.40 M HNO3 + X M HCl.
    8. Analysis.
    8.1 Set the wavelength of the monochromator at 283.3 or 217.0 nm. 
Set or align other instrumental operating conditions as recommended by 
the manufacturer.
    8.2 The sample can be analyzed directly from the volumetric flask, 
or an appropriate amount of sample decanted into a sample analysis tube. 
In either case, care should be taken not to disturb the settled solids.
    8.3 Aspirate samples, calibration standards and blanks (section 9.2) 
into the flame and record the equilibrium absorbance.
    8.4 Determine the lead concentration in [micro]g Pb/ml, from the 
calibration curve, section 9.3.
    8.5 Samples that exceed the linear calibration range should be 
diluted with acid of the same concentration as the calibration standards 
and reanalyzed.
    9. Calibration.
    9.1 Working standard, 20 [micro]g Pb/ml. Prepared by diluting 2.0 ml 
of the master standard (section 6.3.1 if the hot acid extraction was 
used or section 6.3.2 if the ultrasonic extraction procedure was used) 
to 100 ml with acid of the same concentration as used in preparing the 
master standard.
    9.2 Calibration standards. Prepare daily by diluting the working 
standard, with the same acid matrix, as indicated below. Other lead 
concentrations may be used.

------------------------------------------------------------------------
                                                           Concentration
Volume of 20 [micro]g/ml working standard, ml     Final     [micro]g Pb/
                                               volume, ml        ml
------------------------------------------------------------------------
0............................................         100             0
1.0..........................................         200           0.1
2.0..........................................         200           0.2
2.0..........................................         100           0.4
4.0..........................................         100           0.8
8.0..........................................         100           1.6
15.0.........................................         100           3.0
30.0.........................................         100           6.0
50.0.........................................         100          10.0
100.0........................................         100          20.0
------------------------------------------------------------------------

    9.3 Preparation of calibration curve. Since the working range of 
analysis will vary depending on which lead line is used and the type of 
instrument, no one set of instructions for preparation of a calibration 
curve can be given. Select standards (plus the reagent blank), in the 
same acid concentration as the samples, to cover the linear absorption 
range indicated by the instrument manufacturer. Measure the absorbance 
of the blank and standards as in section 8.0. Repeat until good 
agreement is obtained between replicates. Plot absorbance (y-axis) 
versus concentration in [micro]g Pb/ml (x-axis). Draw (or compute) a 
straight line through the linear portion of the curve. Do not force the 
calibration curve through zero. Other calibration procedures may be 
used.
    To determine stability of the calibration curve, remeasure--
alternately--one of the following calibration standards for every 10th 
sample analyzed: Concentration <=1 [micro]g Pb/ml; concentration <=10 
[micro]g Pb/ml. If either standard deviates by more than 5 percent from 
the value predicted by the calibration curve, recalibrate and repeat the 
previous 10 analyses.
    10. Calculation.
    10.1 Measured air volume. Calculate the measured air volume at 
Standard Temperature and Pressure as described in Reference 10.
    10.2 Lead concentration. Calculate lead concentration in the air 
sample.

[[Page 59]]



where:

C = Concentration, [micro]g Pb/sm\3\.
[micro]g Pb/ml = Lead concentration determined from section 8.
100 ml/strip = Total sample volume.
12 strips = Total useable filter area, 8x9. 
Exposed area of one strip, \3/4\x7.
Filter = Total area of one strip, \3/4\x8.
Fb = Lead concentration of blank filter, [micro]g, from 
section 6.1.1.2.3.
VSTP = Air volume from section 10.2.

    11. Quality control.
    \3/4\x8 glass fiber filter strips containing 
80 to 2000 [micro]g Pb/strip (as lead salts) and blank strips with zero 
Pb content should be used to determine if the method--as being used--has 
any bias. Quality control charts should be established to monitor 
differences between measured and true values. The frequency of such 
checks will depend on the local quality control program.
    To minimize the possibility of generating unreliable data, the user 
should follow practices established for assuring the quality of air 
pollution data, (13) and take part in EPA's semiannual audit program for 
lead analyses.
    12. Trouble shooting.
    1. During extraction of lead by the hot extraction procedure, it is 
important to keep the sample covered so that corrosion products--formed 
on fume hood surfaces which may contain lead--are not deposited in the 
extract.
    2. The sample acid concentration should minimize corrosion of the 
nebulizer. However, different nebulizers may require lower acid 
concentrations. Lower concentrations can be used provided samples and 
standards have the same acid concentration.
    3. Ashing of particulate samples has been found, by EPA and 
contractor laboratories, to be unnecessary in lead analyses by atomic 
absorption. Therefore, this step was omitted from the method.
    4. Filtration of extracted samples, to remove particulate matter, 
was specifically excluded from sample preparation, because some analysts 
have observed losses of lead due to filtration.
    5. If suspended solids should clog the nebulizer during analysis of 
samples, centrifuge the sample to remove the solids.
    13. Authority.
    (Secs. 109 and 301(a), Clean Air Act, as amended (42 U.S.C. 7409, 
7601(a)))
    14. References.
    1. Scott, D. R. et al. ``Atomic Absorption and Optical Emission 
Analysis of NASN Atmospheric Particulate Samples for Lead.'' Envir. Sci. 
and Tech., 10, 877-880 (1976).
    2. Skogerboe, R. K. et al. ``Monitoring for Lead in the 
Environment.'' pp. 57-66, Department of Chemistry, Colorado State 
University, Fort Collins, CO 80523. Submitted to National Science 
Foundation for publications, 1976.
    3. Zdrojewski, A. et al. ``The Accurate Measurement of Lead in 
Airborne Particulates.'' Inter. J. Environ. Anal. Chem., 2, 63-77 
(1972).
    4. Slavin, W., ``Atomic Absorption Spectroscopy.'' Published by 
Interscience Company, New York, NY (1968).
    5. Kirkbright, G. F., and Sargent, M., ``Atomic Absorption and 
Fluorescence Spectroscopy.'' Published by Academic Press, New York, NY 
1974.
    6. Burnham, C. D. et al., ``Determination of Lead in Airborne 
Particulates in Chicago and Cook County, IL, by Atomic Absorption 
Spectroscopy.'' Envir. Sci. and Tech., 3, 472-475 (1969).
    7. ``Proposed Recommended Practices for Atomic Absorption 
Spectrometry.'' ASTM Book of Standards, part 30, pp. 1596-1608 (July 
1973).
    8. Koirttyohann, S. R. and Wen, J. W., ``Critical Study of the APCD-
MIBK Extraction System for Atomic Absorption.'' Anal. Chem., 45, 1986-
1989 (1973).
    9. Collaborative Study of Reference Method for the Determination of 
Suspended Particulates in the Atmosphere (High Volume Method). 
Obtainable from National Technical Information Service, Department of 
Commerce, Port Royal Road, Springfield, VA 22151, as PB-205-891.
    10. [Reserved]
    11. Dubois, L., et al., ``The Metal Content of Urban Air.'' JAPCA, 
16, 77-78 (1966).
    12. EPA Report No. 600/4-77-034, June 1977, ``Los Angeles Catalyst 
Study Symposium.'' Page 223.
    13. Quality Assurance Handbook for Air Pollution Measurement System. 
Volume 1--Principles. EPA-600/9-76-005, March 1976.
    14. Thompson, R. J. et al., ``Analysis of Selected Elements in 
Atmospheric Particulate Matter by Atomic Absorption.'' Atomic Absorption 
Newsletter, 9, No. 3, May-June 1970.
    15. To be published. EPA, QAB, EMSL, RTP, N.C. 27711

[[Page 60]]

    16. Quality Assurance Handbook for Air Pollution Measurement 
Systems. Volume II--Ambient Air Specific Methods. EPA-600/4-77/027a, May 
1977.



[[Page 61]]





(Secs. 109, 301(a) of the Clean Air Act, as amended (42 U.S.C. 7409, 
7601(a)); secs. 110, 301(a) and 319 of the Clean Air Act (42 U.S.C. 
7410, 7601(a), 7619))

[43 FR 46258, Oct. 5, 1978; 44 FR 37915, June 29, 1979, as amended at 46 
FR 44163, Sept. 3, 1981; 52 FR 24664, July 1, 1987]

    Appendix H to Part 50--Interpretation of the 1-Hour Primary and 
       Secondary National Ambient Air Quality Standards for Ozone

                               1. General

    This appendix explains how to determine when the expected number of 
days per calendar year with maximum hourly average concentrations above 
0.12 ppm (235 [micro]g/m\3\) is equal to or less than 1. An expanded 
discussion of these procedures and associated examples are contained in 
the ``Guideline for Interpretation of Ozone Air Quality Standards.'' For 
purposes of clarity in the following discussion, it is convenient to use 
the term ``exceedance'' to describe a daily maximum hourly average ozone 
measurement that is greater than the level of the standard. Therefore, 
the phrase ``expected number of days with maximum hourly average ozone 
concentrations above the level of the standard'' may be simply stated as 
the ``expected number of exceedances.''

[[Page 62]]

    The basic principle in making this determination is relatively 
straightforward. Most of the complications that arise in determining the 
expected number of annual exceedances relate to accounting for 
incomplete sampling. In general, the average number of exceedances per 
calendar year must be less than or equal to 1. In its simplest form, the 
number of exceedances at a monitoring site would be recorded for each 
calendar year and then averaged over the past 3 calendar years to 
determine if this average is less than or equal to 1.

                2. Interpretation of Expected Exceedances

    The ozone standard states that the expected number of exceedances 
per year must be less than or equal to 1. The statistical term 
``expected number'' is basically an arithmetic average. The following 
example explains what it would mean for an area to be in compliance with 
this type of standard. Suppose a monitoring station records a valid 
daily maximum hourly average ozone value for every day of the year 
during the past 3 years. At the end of each year, the number of days 
with maximum hourly concentrations above 0.12 ppm is determined and this 
number is averaged with the results of previous years. As long as this 
average remains ``less than or equal to 1,'' the area is in compliance.

           3. Estimating the Number of Exceedances for a Year

    In general, a valid daily maximum hourly average value may not be 
available for each day of the year, and it will be necessary to account 
for these missing values when estimating the number of exceedances for a 
particular calendar year. The purpose of these computations is to 
determine if the expected number of exceedances per year is less than or 
equal to 1. Thus, if a site has two or more observed exceedances each 
year, the standard is not met and it is not necessary to use the 
procedures of this section to account for incomplete sampling.
    The term ``missing value'' is used here in the general sense to 
describe all days that do not have an associated ozone measurement. In 
some cases, a measurement might actually have been missed but in other 
cases no measurement may have been scheduled for that day. A daily 
maximum ozone value is defined to be the highest hourly ozone value 
recorded for the day. This daily maximum value is considered to be valid 
if 75 percent of the hours from 9:01 a.m. to 9:00 p.m. (LST) were 
measured or if the highest hour is greater than the level of the 
standard.
    In some areas, the seasonal pattern of ozone is so pronounced that 
entire months need not be sampled because it is extremely unlikely that 
the standard would be exceeded. Any such waiver of the ozone monitoring 
requirement would be handled under provisions of 40 CFR, part 58. Some 
allowance should also be made for days for which valid daily maximum 
hourly values were not obtained but which would quite likely have been 
below the standard. Such an allowance introduces a complication in that 
it becomes necessary to define under what conditions a missing value may 
be assumed to have been less than the level of the standard. The 
following criterion may be used for ozone:
    A missing daily maximum ozone value may be assumed to be less than 
the level of the standard if the valid daily maxima on both the 
preceding day and the following day do not exceed 75 percent of the 
level of the standard.
    Let z denote the number of missing daily maximum values that may be 
assumed to be less than the standard. Then the following formula shall 
be used to estimate the expected number of exceedances for the year:
[GRAPHIC] [TIFF OMITTED] TC08NO91.086

    (*Indicates multiplication.)

where:

e = the estimated number of exceedances for the year,
N = the number of required monitoring days in the year,
n = the number of valid daily maxima,
v = the number of daily values above the level of the standard, and
z = the number of days assumed to be less than the standard level.

    This estimated number of exceedances shall be rounded to one decimal 
place (fractional parts equal to 0.05 round up).
    It should be noted that N will be the total number of days in the 
year unless the appropriate Regional Administrator has granted a waiver 
under the provisions of 40 CFR part 58.
    The above equation may be interpreted intuitively in the following 
manner. The estimated number of exceedances is equal to the observed 
number of exceedances (v) plus an increment that accounts for incomplete 
sampling. There were (N-n) missing values for the year but a certain 
number of these, namely z, were assumed to be less than the standard. 
Therefore, (N-n-z) missing values are considered to include possible 
exceedances. The fraction of measured values that are above the level of 
the standard is v/n. It is assumed that this same fraction applies to 
the (N-n-z) missing values and that (v/n)*(N-n-z) of these values would 
also have exceeded the level of the standard.

[44 FR 8220, Feb. 8, 1979, as amended at 62 FR 38895, July 18, 1997]

[[Page 63]]

    Appendix I to Part 50--Interpretation of the 8-Hour Primary and 
       Secondary National Ambient Air Quality Standards for Ozone

    1. General.
    This appendix explains the data handling conventions and 
computations necessary for determining whether the national 8-hour 
primary and secondary ambient air quality standards for ozone specified 
in Sec. 50.10 are met at an ambient ozone air quality monitoring site. 
Ozone is measured in the ambient air by a reference method based on 
appendix D of this part. Data reporting, data handling, and computation 
procedures to be used in making comparisons between reported ozone 
concentrations and the level of the ozone standard are specified in the 
following sections. Whether to exclude, retain, or make adjustments to 
the data affected by stratospheric ozone intrusion or other natural 
events is subject to the approval of the appropriate Regional 
Administrator.
    2. Primary and Secondary Ambient Air Quality Standards for Ozone.
    2.1 Data Reporting and Handling Conventions.
    2.1.1 Computing 8-hour averages. Hourly average concentrations shall 
be reported in parts per million (ppm) to the third decimal place, with 
additional digits to the right being truncated. Running 8-hour averages 
shall be computed from the hourly ozone concentration data for each hour 
of the year and the result shall be stored in the first, or start, hour 
of the 8-hour period. An 8-hour average shall be considered valid if at 
least 75% of the hourly averages for the 8-hour period are available. In 
the event that only 6 (or 7) hourly averages are available, the 8-hour 
average shall be computed on the basis of the hours available using 6 
(or 7) as the divisor. (8-hour periods with three or more missing hours 
shall not be ignored if, after substituting one-half the minimum 
detectable limit for the missing hourly concentrations, the 8-hour 
average concentration is greater than the level of the standard.) The 
computed 8-hour average ozone concentrations shall be reported to three 
decimal places (the insignificant digits to the right of the third 
decimal place are truncated, consistent with the data handling 
procedures for the reported data.)
    2.1.2 Daily maximum 8-hour average concentrations. (a) There are 24 
possible running 8-hour average ozone concentrations for each calendar 
day during the ozone monitoring season. (Ozone monitoring seasons vary 
by geographic location as designated in part 58, appendix D to this 
chapter.) The daily maximum 8-hour concentration for a given calendar 
day is the highest of the 24 possible 8-hour average concentrations 
computed for that day. This process is repeated, yielding a daily 
maximum 8-hour average ozone concentration for each calendar day with 
ambient ozone monitoring data. Because the 8-hour averages are recorded 
in the start hour, the daily maximum 8-hour concentrations from two 
consecutive days may have some hourly concentrations in common. 
Generally, overlapping daily maximum 8-hour averages are not likely, 
except in those non-urban monitoring locations with less pronounced 
diurnal variation in hourly concentrations.
    (b) An ozone monitoring day shall be counted as a valid day if valid 
8-hour averages are available for at least 75% of possible hours in the 
day (i.e., at least 18 of the 24 averages). In the event that less than 
75% of the 8-hour averages are available, a day shall also be counted as 
a valid day if the daily maximum 8-hour average concentration for that 
day is greater than the level of the ambient standard.
    2.2 Primary and Secondary Standard-related Summary Statistic. The 
standard-related summary statistic is the annual fourth-highest daily 
maximum 8-hour ozone concentration, expressed in parts per million, 
averaged over three years. The 3-year average shall be computed using 
the three most recent, consecutive calendar years of monitoring data 
meeting the data completeness requirements described in this appendix. 
The computed 3-year average of the annual fourth-highest daily maximum 
8-hour average ozone concentrations shall be expressed to three decimal 
places (the remaining digits to the right are truncated.)
    2.3 Comparisons with the Primary and Secondary Ozone Standards. (a) 
The primary and secondary ozone ambient air quality standards are met at 
an ambient air quality monitoring site when the 3-year average of the 
annual fourth-highest daily maximum 8-hour average ozone concentration 
is less than or equal to 0.08 ppm. The number of significant figures in 
the level of the standard dictates the rounding convention for comparing 
the computed 3-year average annual fourth-highest daily maximum 8-hour 
average ozone concentration with the level of the standard. The third 
decimal place of the computed value is rounded, with values equal to or 
greater than 5 rounding up. Thus, a computed 3-year average ozone 
concentration of 0.085 ppm is the smallest value that is greater than 
0.08 ppm.
    (b) This comparison shall be based on three consecutive, complete 
calendar years of air quality monitoring data. This requirement is met 
for the three year period at a monitoring site if daily maximum 8-hour 
average concentrations are available for at least 90%, on average, of 
the days during the designated ozone monitoring season, with a minimum 
data completeness in any one year of at least 75% of the designated 
sampling days. When

[[Page 64]]

computing whether the minimum data completeness requirements have been 
met, meteorological or ambient data may be sufficient to demonstrate 
that meteorological conditions on missing days were not conducive to 
concentrations above the level of the standard. Missing days assumed 
less than the level of the standard are counted for the purpose of 
meeting the data completeness requirement, subject to the approval of 
the appropriate Regional Administrator.
    (c) Years with concentrations greater than the level of the standard 
shall not be ignored on the ground that they have less than complete 
data. Thus, in computing the 3-year average fourth maximum 
concentration, calendar years with less than 75% data completeness shall 
be included in the computation if the average annual fourth maximum 8-
hour concentration is greater than the level of the standard.
    (d) Comparisons with the primary and secondary ozone standards are 
demonstrated by examples 1 and 2 in paragraphs (d)(1) and (d) (2) 
respectively as follows:
    (1) As shown in example 1, the primary and secondary standards are 
met at this monitoring site because the 3-year average of the annual 
fourth-highest daily maximum 8-hour average ozone concentrations (i.e., 
0.084 ppm) is less than or equal to 0.08 ppm. The data completeness 
requirement is also met because the average percent of days with valid 
ambient monitoring data is greater than 90%, and no single year has less 
than 75% data completeness.

             Example 1. Ambient monitoring site attaining the primary and secondary ozone standards
----------------------------------------------------------------------------------------------------------------
                                                 1st Highest  2nd Highest  3rd Highest  4th Highest  5th Highest
                                      Percent    Daily Max 8- Daily Max 8- Daily Max 8- Daily Max 8- Daily Max 8-
               Year                  Valid Days   hour Conc.   hour Conc.   hour Conc.   hour Conc.   hour Conc.
                                                    (ppm)        (ppm)        (ppm)        (ppm)        (ppm)
----------------------------------------------------------------------------------------------------------------
1993..............................         100%        0.092        0.091        0.090        0.088        0.085
----------------------------------------------------------------------------------------------------------------
1994..............................          96%        0.090        0.089        0.086        0.084        0.080
----------------------------------------------------------------------------------------------------------------
1995..............................          98%        0.087        0.085        0.083        0.080        0.075
================================================================================================================
    Average.......................          98%
----------------------------------------------------------------------------------------------------------------

    (2) As shown in example 2, the primary and secondary standards are 
not met at this monitoring site because the 3-year average of the 
fourth-highest daily maximum 8-hour average ozone concentrations (i.e., 
0.093 ppm) is greater than 0.08 ppm. Note that the ozone concentration 
data for 1994 is used in these computations, even though the data 
capture is less than 75%, because the average fourth-highest daily 
maximum 8-hour average concentration is greater than 0.08 ppm.

          Example 2. Ambient Monitoring Site Failing to Meet the Primary and Secondary Ozone Standards
----------------------------------------------------------------------------------------------------------------
                                                 1st Highest  2nd Highest  3rd Highest  4th Highest  5th Highest
                                      Percent    Daily Max 8- Daily Max 8- Daily Max 8- Daily Max 8- Daily Max 8-
               Year                  Valid Days   hour Conc.   hour Conc.   hour Conc.   hour Conc.   hour Conc.
                                                    (ppm)        (ppm)        (ppm)        (ppm)        (ppm)
----------------------------------------------------------------------------------------------------------------
1993..............................          96%        0.105        0.103        0.103        0.102        0.102
----------------------------------------------------------------------------------------------------------------
1994..............................          74%        0.090        0.085        0.082        0.080        0.078
----------------------------------------------------------------------------------------------------------------
1995..............................          98%        0.103        0.101        0.101        0.097        0.095
================================================================================================================
    Average.......................          89%
----------------------------------------------------------------------------------------------------------------

    3. Design Values for Primary and Secondary Ambient Air Quality 
Standards for Ozone. The air quality design value at a monitoring site 
is defined as that concentration that when reduced to the level of the 
standard ensures that the site meets the standard. For a concentration-
based standard, the air quality design value is simply the standard-
related test statistic. Thus, for the primary and secondary ozone 
standards, the 3-year average annual fourth-highest daily maximum 8-hour 
average ozone concentration is also the air quality design value for the 
site.

[62 FR 38895, July 18, 1997]

    Appendix J to Part 50--Reference Method for the Determination of 
         Particulate Matter as PM10 in the Atmosphere

    1.0 Applicability.

[[Page 65]]

    1.1 This method provides for the measurement of the mass 
concentration of particulate matter with an aerodynamic diameter less 
than or equal to a nominal 10 micrometers (PM1O) in ambient 
air over a 24-hour period for purposes of determining attainment and 
maintenance of the primary and secondary national ambient air quality 
standards for particulate matter specified in Sec. 50.6 of this 
chapter. The measurement process is nondestructive, and the 
PM10 sample can be subjected to subsequent physical or 
chemical analyses. Quality assurance procedures and guidance are 
provided in part 58, appendices A and B, of this chapter and in 
References 1 and 2.
    2.0 Principle.
    2.1 An air sampler draws ambient air at a constant flow rate into a 
specially shaped inlet where the suspended particulate matter is 
inertially separated into one or more size fractions within the 
PM10 size range. Each size fraction in the PM1O 
size range is then collected on a separate filter over the specified 
sampling period. The particle size discrimination characteristics 
(sampling effectiveness and 50 percent cutpoint) of the sampler inlet 
are prescribed as performance specifications in part 53 of this chapter.
    2.2 Each filter is weighed (after moisture equilibration) before and 
after use to determine the net weight (mass) gain due to collected 
PM10. The total volume of air sampled, corrected to EPA 
reference conditions (25 C, 101.3 kPa), is determined from the measured 
flow rate and the sampling time. The mass concentration of 
PM10 in the ambient air is computed as the total mass of 
collected particles in the PM10 size range divided by the 
volume of air sampled, and is expressed in micrograms per standard cubic 
meter ([micro]g/std m\3\). For PM10 samples collected at 
temperatures and pressures significantly different from EPA reference 
conditions, these corrected concentrations sometimes differ 
substantially from actual concentrations (in micrograms per actual cubic 
meter), particularly at high elevations. Although not required, the 
actual PM10 concentration can be calculated from the 
corrected concentration, using the average ambient temperature and 
barometric pressure during the sampling period.
    2.3 A method based on this principle will be considered a reference 
method only if (a) the associated sampler meets the requirements 
specified in this appendix and the requirements in part 53 of this 
chapter, and (b) the method has been designated as a reference method in 
accordance with part 53 of this chapter.
    3.0 Range.
    3.1 The lower limit of the mass concentration range is determined by 
the repeatability of filter tare weights, assuming the nominal air 
sample volume for the sampler. For samplers having an automatic filter-
changing mechanism, there may be no upper limit. For samplers that do 
not have an automatic filter-changing mechanism, the upper limit is 
determined by the filter mass loading beyond which the sampler no longer 
maintains the operating flow rate within specified limits due to 
increased pressure drop across the loaded filter. This upper limit 
cannot be specified precisely because it is a complex function of the 
ambient particle size distribution and type, humidity, filter type, and 
perhaps other factors. Nevertheless, all samplers should be capable of 
measuring 24-hour PM10 mass concentrations of at least 300 
[micro]g/std m\3\ while maintaining the operating flow rate within the 
specified limits.
    4.0 Precision.
    4.1 The precision of PM10 samplers must be 5 [micro]g/
m\3\ for PM10 concentrations below 80 [micro]g/m\3\ and 7 
percent for PM10 concentrations above 80 [micro]g/m\3\, as 
required by part 53 of this chapter, which prescribes a test procedure 
that determines the variation in the PM10 concentration 
measurements of identical samplers under typical sampling conditions. 
Continual assessment of precision via collocated samplers is required by 
part 58 of this chapter for PM10 samplers used in certain 
monitoring networks.
    5.0 Accuracy.
    5.1 Because the size of the particles making up ambient particulate 
matter varies over a wide range and the concentration of particles 
varies with particle size, it is difficult to define the absolute 
accuracy of PM10 samplers. Part 53 of this chapter provides a 
specification for the sampling effectiveness of PM10 
samplers. This specification requires that the expected mass 
concentration calculated for a candidate PM10 sampler, when 
sampling a specified particle size distribution, be within 10 percent of that calculated for an ideal sampler whose 
sampling effectiveness is explicitly specified. Also, the particle size 
for 50 percent sampling effectivensss is required to be 10 0.5 micrometers. Other specifications related to 
accuracy apply to flow measurement and calibration, filter media, 
analytical (weighing) procedures, and artifact. The flow rate accuracy 
of PM10 samplers used in certain monitoring networks is 
required by part 58 of this chapter to be assessed periodically via flow 
rate audits.
    6.0 Potential Sources of Error.
    6.1 Volatile Particles. Volatile particles collected on filters are 
often lost during shipment and/or storage of the filters prior to the 
post-sampling weighing \3\. Although shipment or storage of loaded 
filters is sometimes unavoidable, filters should be reweighed as soon as 
practical to minimize these losses.
    6.2 Artifacts. Positive errors in PM10 concentration 
measurements may result from retention of gaseous species on filters. 
\4,5\ Such errors include the retention of sulfur

[[Page 66]]

dioxide and nitric acid. Retention of sulfur dioxide on filters, 
followed by oxidation to sulfate, is referred to as artifact sulfate 
formation, a phenomenon which increases with increasing filter 
alkalinity. \6\ Little or no artifact sulfate formation should occur 
using filters that meet the alkalinity specification in section 7.2.4. 
Artifact nitrate formation, resulting primarily from retention of nitric 
acid, occurs to varying degrees on many filter types, including glass 
fiber, cellulose ester, and many quartz fiber filters. \5,7,8,9,10\ Loss 
of true atmospheric particulate nitrate during or following sampling may 
also occur due to dissociation or chemical reaction. This phenomenon has 
been observed on Teflon[reg] filters \8\ and inferred for 
quartz fiber filters. \11,12\ The magnitude of nitrate artifact errors 
in PM10 mass concentration measurements will vary with 
location and ambient temperature; however, for most sampling locations, 
these errors are expected to be small.
    6.3 Humidity. The effects of ambient humidity on the sample are 
unavoidable. The filter equilibration procedure in section 9.0 is 
designed to minimize the effects of moisture on the filter medium.
    6.4 Filter Handling. Careful handling of filters between presampling 
and postsampling weighings is necessary to avoid errors due to damaged 
filters or loss of collected particles from the filters. Use of a filter 
cartridge or cassette may reduce the magnitude of these errors. Filters 
must also meet the integrity specification in section 7.2.3.
    6.5 Flow Rate Variation. Variations in the sampler's operating flow 
rate may alter the particle size discrimination characteristics of the 
sampler inlet. The magnitude of this error will depend on the 
sensitivity of the inlet to variations in flow rate and on the particle 
distribution in the atmosphere during the sampling period. The use of a 
flow control device (section 7.1.3) is required to minimize this error.
    6.6 Air Volume Determination. Errors in the air volume determination 
may result from errors in the flow rate and/or sampling time 
measurements. The flow control device serves to minimize errors in the 
flow rate determination, and an elapsed time meter (section 7.1.5) is 
required to minimize the error in the sampling time measurement.
    7.0 Apparatus.
    7.1 PM10 Sampler.
    7.1.1 The sampler shall be designed to:
    a. Draw the air sample into the sampler inlet and through the 
particle collection filter at a uniform face velocity.
    b. Hold and seal the filter in a horizontal position so that sample 
air is drawn downward through the filter.
    c. Allow the filter to be installed and removed conveniently.
    d. Protect the filter and sampler from precipitation and prevent 
insects and other debris from being sampled.
    e. Minimize air leaks that would cause error in the measurement of 
the air volume passing through the filter.
    f. Discharge exhaust air at a sufficient distance from the sampler 
inlet to minimize the sampling of exhaust air.
    g. Minimize the collection of dust from the supporting surface.
    7.1.2 The sampler shall have a sample air inlet system that, when 
operated within a specified flow rate range, provides particle size 
discrimination characteristics meeting all of the applicable performance 
specifications prescribed in part 53 of this chapter. The sampler inlet 
shall show no significant wind direction dependence. The latter 
requirement can generally be satisfied by an inlet shape that is 
circularly symmetrical about a vertical axis.
    7.1.3 The sampler shall have a flow control device capable of 
maintaining the sampler's operating flow rate within the flow rate 
limits specified for the sampler inlet over normal variations in line 
voltage and filter pressure drop.
    7.1.4 The sampler shall provide a means to measure the total flow 
rate during the sampling period. A continuous flow recorder is 
recommended but not required. The flow measurement device shall be 
accurate to 2 percent.
    7.1.5 A timing/control device capable of starting and stopping the 
sampler shall be used to obtain a sample collection period of 24 1 hr (1,440 60 min). An elapsed 
time meter, accurate to within 15 minutes, shall 
be used to measure sampling time. This meter is optional for samplers 
with continuous flow recorders if the sampling time measurement obtained 
by means of the recorder meets the 15 minute 
accuracy specification.
    7.1.6 The sampler shall have an associated operation or instruction 
manual as required by part 53 of this chapter which includes detailed 
instructions on the calibration, operation, and maintenance of the 
sampler.
    7.2 Filters.
    7.2.1 Filter Medium. No commercially available filter medium is 
ideal in all respects for all samplers. The user's goals in sampling 
determine the relative importance of various filter characteristics 
(e.g., cost, ease of handling, physical and chemical characteristics, 
etc.) and, consequently, determine the choice among acceptable filters. 
Furthermore, certain types of filters may not be suitable for use with 
some samplers, particularly under heavy loading conditions (high mass 
concentrations), because of high or rapid increase in the filter flow 
resistance that would exceed the capability of the sampler's flow 
control device. However, samplers equipped with automatic filter-
changing

[[Page 67]]

mechanisms may allow use of these types of filters. The specifications 
given below are minimum requirements to ensure acceptability of the 
filter medium for measurement of PM10 mass concentrations. 
Other filter evaluation criteria should be considered to meet individual 
sampling and analysis objectives.
    7.2.2 Collection Efficiency. =99 percent, as measured by 
the DOP test (ASTM-2986) with 0.3 [micro]m particles at the sampler's 
operating face velocity.
    7.2.3 Integrity. 5 [micro]g/m\3\ (assuming 
sampler's nominal 24-hour air sample volume). Integrity is measured as 
the PM10 concentration equivalent corresponding to the 
average difference between the initial and the final weights of a random 
sample of test filters that are weighed and handled under actual or 
simulated sampling conditions, but have no air sample passed through 
them (i.e., filter blanks). As a minimum, the test procedure must 
include initial equilibration and weighing, installation on an 
inoperative sampler, removal from the sampler, and final equilibration 
and weighing.
    7.2.4 Alkalinity. <25 microequivalents/gram of filter, as measured 
by the procedure given in Reference 13 following at least two months 
storage in a clean environment (free from contamination by acidic gases) 
at room temperature and humidity.
    7.3 Flow Rate Transfer Standard. The flow rate transfer standard 
must be suitable for the sampler's operating flow rate and must be 
calibrated against a primary flow or volume standard that is traceable 
to the National Bureau of Standards (NBS). The flow rate transfer 
standard must be capable of measuring the sampler's operating flow rate 
with an accuracy of 2 percent.
    7.4 Filter Conditioning Environment.
    7.4.1 Temperature range: 15 to 30 C.
    7.4.2 Temperature control: 3 C.
    7.4.3 Humidity range: 20% to 45% RH.
    7.4.4 Humidity control: 5% RH.
    7.5 Analytical Balance. The analytical balance must be suitable for 
weighing the type and size of filters required by the sampler. The range 
and sensitivity required will depend on the filter tare weights and mass 
loadings. Typically, an analytical balance with a sensitivity of 0.1 mg 
is required for high volume samplers (flow rates 0.5 m\3\/
min). Lower volume samplers (flow rates <0.5 m\3\/min) will require a 
more sensitive balance.
    8.0 Calibration.
    8.1 General Requirements.
    8.1.1 Calibration of the sampler's flow measurement device is 
required to establish traceability of subsequent flow measurements to a 
primary standard. A flow rate transfer standard calibrated against a 
primary flow or volume standard shall be used to calibrate or verify the 
accuracy of the sampler's flow measurement device.
    8.1.2 Particle size discrimination by inertial separation requires 
that specific air velocities be maintained in the sampler's air inlet 
system. Therefore, the flow rate through the sampler's inlet must be 
maintained throughout the sampling period within the design flow rate 
range specified by the manufacturer. Design flow rates are specified as 
actual volumetric flow rates, measured at existing conditions of 
temperature and pressure (Qa). In contrast, mass 
concentrations of PM10 are computed using flow rates 
corrected to EPA reference conditions of temperature and pressure 
(Qstd).
    8.2 Flow Rate Calibration Procedure.
    8.2.1 PM10 samplers employ various types of flow control 
and flow measurement devices. The specific procedure used for flow rate 
calibration or verification will vary depending on the type of flow 
controller and flow indicator employed. Calibration in terms of actual 
volumetric flow rates (Qa) is generally recommended, but 
other measures of flow rate (e.g., Qstd) may be used provided 
the requirements of section 8.1 are met. The general procedure given 
here is based on actual volumetric flow units (Qa) and serves 
to illustrate the steps involved in the calibration of a PM10 
sampler. Consult the sampler manufacturer's instruction manual and 
Reference 2 for specific guidance on calibration. Reference 14 provides 
additional information on the use of the commonly used measures of flow 
rate and their interrelationships.
    8.2.2 Calibrate the flow rate transfer standard against a primary 
flow or volume standard traceable to NBS. Establish a calibration 
relationship (e.g., an equation or family of curves) such that 
traceability to the primary standard is accurate to within 2 percent 
over the expected range of ambient conditions (i.e., temperatures and 
pressures) under which the transfer standard will be used. Recalibrate 
the transfer standard periodically.
    8.2.3 Following the sampler manufacturer's instruction manual, 
remove the sampler inlet and connect the flow rate transfer standard to 
the sampler such that the transfer standard accurately measures the 
sampler's flow rate. Make sure there are no leaks between the transfer 
standard and the sampler.
    8.2.4 Choose a minimum of three flow rates (actual m\3\/min), spaced 
over the acceptable flow rate range specified for the inlet (see 7.1.2) 
that can be obtained by suitable adjustment of the sampler flow rate. In 
accordance with the sampler manufacturer's instruction manual, obtain or 
verify the calibration relationship between the flow rate (actual m\3\/
min) as indicated by the transfer standard and the sampler's flow 
indicator response. Record the ambient temperature and barometric 
pressure. Temperature and pressure corrections to subsequent flow 
indicator readings may be required for certain types of

[[Page 68]]

flow measurement devices. When such corrections are necessary, 
correction on an individual or daily basis is preferable. However, 
seasonal average temperature and average barometric pressure for the 
sampling site may be incorporated into the sampler calibration to avoid 
daily corrections. Consult the sampler manufacturer's instruction manual 
and Reference 2 for additional guidance.
    8.2.5 Following calibration, verify that the sampler is operating at 
its design flow rate (actual m\3\/min) with a clean filter in place.
    8.2.6 Replace the sampler inlet.
    9.0 Procedure.
    9.1 The sampler shall be operated in accordance with the specific 
guidance provided in the sampler manufacturer's instruction manual and 
in Reference 2. The general procedure given here assumes that the 
sampler's flow rate calibration is based on flow rates at ambient 
conditions (Qa) and serves to illustrate the steps involved 
in the operation of a PM10 sampler.
    9.2 Inspect each filter for pinholes, particles, and other 
imperfections. Establish a filter information record and assign an 
identification number to each filter.
    9.3 Equilibrate each filter in the conditioning environment (see 
7.4) for at least 24 hours.
    9.4 Following equilibration, weigh each filter and record the 
presampling weight with the filter identification number.
    9.5 Install a preweighed filter in the sampler following the 
instructions provided in the sampler manufacturer's instruction manual.
    9.6 Turn on the sampler and allow it to establish run-temperature 
conditions. Record the flow indicator reading and, if needed, the 
ambient temperature and barometric pressure. Determine the sampler flow 
rate (actual m\3\/min) in accordance with the instructions provided in 
the sampler manufacturer's instruction manual. NOTE.--No onsite 
temperature or pressure measurements are necessary if the sampler's flow 
indicator does not require temperature or pressure corrections or if 
seasonal average temperature and average barometric pressure for the 
sampling site are incorporated into the sampler calibration (see step 
8.2.4). If individual or daily temperature and pressure corrections are 
required, ambient temperature and barometric pressure can be obtained by 
on-site measurements or from a nearby weather station. Barometric 
pressure readings obtained from airports must be station pressure, not 
corrected to sea level, and may need to be corrected for differences in 
elevation between the sampling site and the airport.
    9.7 If the flow rate is outside the acceptable range specified by 
the manufacturer, check for leaks, and if necessary, adjust the flow 
rate to the specified setpoint. Stop the sampler.
    9.8 Set the timer to start and stop the sampler at appropriate 
times. Set the elapsed time meter to zero or record the initial meter 
reading.
    9.9 Record the sample information (site location or identification 
number, sample date, filter identification number, and sampler model and 
serial number).
    9.10 Sample for 24 1 hours.
    9.11 Determine and record the average flow rate (Qa) in 
actual m\3\/min for the sampling period in accordance with the 
instructions provided in the sampler manufacturer's instruction manual. 
Record the elapsed time meter final reading and, if needed, the average 
ambient temperature and barometric pressure for the sampling period (see 
note following step 9.6).
    9.12 Carefully remove the filter from the sampler, following the 
sampler manufacturer's instruction manual. Touch only the outer edges of 
the filter.
    9.13 Place the filter in a protective holder or container (e.g., 
petri dish, glassine envelope, or manila folder).
    9.14 Record any factors such as meteorological conditions, 
construction activity, fires or dust storms, etc., that might be 
pertinent to the measurement on the filter information record.
    9.15 Transport the exposed sample filter to the filter conditioning 
environment as soon as possible for equilibration and subsequent 
weighing.
    9.16 Equilibrate the exposed filter in the conditioning environment 
for at least 24 hours under the same temperature and humidity conditions 
used for presampling filter equilibration (see 9.3).
    9.17 Immediately after equilibration, reweigh the filter and record 
the postsampling weight with the filter identification number.
    10.0 Sampler Maintenance.
    10.1 The PM10 sampler shall be maintained in strict 
accordance with the maintenance procedures specified in the sampler 
manufacturer's instruction manual.
    11.0 Calculations.
    11.1 Calculate the average flow rate over the sampling period 
corrected to EPA reference conditions as Qstd. When the 
sampler's flow indicator is calibrated in actual volumetric units 
(Qa), Qstd is calculated as:

Qstd=Qax(Pav/
Tav)(Tstd/Pstd)

where

Qstd = average flow rate at EPA reference conditions, std 
m\3\/min;
Qa = average flow rate at ambient conditions, m\3\/min;
Pav = average barometric pressure during the sampling period 
or average barometric pressure for the sampling site, kPa (or mm Hg);
Tav = average ambient temperature during the sampling period 
or seasonal average

[[Page 69]]

ambient temperature for the sampling site, K;
Tstd = standard temperature, defined as 298 K;
Pstd = standard pressure, defined as 101.3 kPa (or 760 mm 
Hg).

    11.2 Calculate the total volume of air sampled as:

Vstd = Qstdxt

where

Vstd = total air sampled in standard volume units, std m\3\;
t = sampling time, min.

    11.3 Calculate the PM10 concentration as:

PM10 = (Wf-Wi)x10\6\/Vstd

where

PM10 = mass concentration of PM10, [micro]g/std 
m\3\;
Wf, Wi = final and initial weights of filter 
collecting PM1O particles, g;
10\6\ = conversion of g to [micro]g.

    Note: If more than one size fraction in the PM10 size 
range is collected by the sampler, the sum of the net weight gain by 
each collection filter [[Sigma](Wf-Wi)] is used to 
calculate the PM10 mass concentration.
    12.0 References.
    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume I, Principles. EPA-600/9-76-005, March 1976. Available from CERI, 
ORD Publications, U.S. Environmental Protection Agency, 26 West St. 
Clair Street, Cincinnati, OH 45268.
    2. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume II, Ambient Air Specific Methods. EPA-600/4-77-027a, May 1977. 
Available from CERI, ORD Publications, U.S. Environmental Protection 
Agency, 26 West St. Clair Street, Cincinnati, OH 45268.
    3. Clement, R.E., and F.W. Karasek. Sample Composition Changes in 
Sampling and Analysis of Organic Compounds in Aerosols. Int. J. Environ. 
Analyt. Chem., 7:109, 1979.
    4. Lee, R.E., Jr., and J. Wagman. A Sampling Anomaly in the 
Determination of Atmospheric Sulfate Concentration. Amer. Ind. Hyg. 
Assoc. J., 27:266, 1966.
    5. Appel, B.R., S.M. Wall, Y. Tokiwa, and M. Haik. Interference 
Effects in Sampling Particulate Nitrate in Ambient Air. Atmos. Environ., 
13:319, 1979.
    6. Coutant, R.W. Effect of Environmental Variables on Collection of 
Atmospheric Sulfate. Environ. Sci. Technol., 11:873, 1977.
    7. Spicer, C.W., and P. Schumacher. Interference in Sampling 
Atmospheric Particulate Nitrate. Atmos. Environ., 11:873, 1977.
    8. Appel, B.R., Y. Tokiwa, and M. Haik. Sampling of Nitrates in 
Ambient Air. Atmos. Environ., 15:283, 1981.
    9. Spicer, C.W., and P.M. Schumacher. Particulate Nitrate: 
Laboratory and Field Studies of Major Sampling Interferences. Atmos. 
Environ., 13:543, 1979.
    10. Appel, B.R. Letter to Larry Purdue, U.S. EPA, Environmental 
Monitoring and Support Laboratory. March 18, 1982, Docket No. A-82-37, 
II-I-1.
    11. Pierson, W.R., W.W. Brachaczek, T.J. Korniski, T.J. Truex, and 
J.W. Butler. Artifact Formation of Sulfate, Nitrate, and Hydrogen Ion on 
Backup Filters: Allegheny Mountain Experiment. J. Air Pollut. Control 
Assoc., 30:30, 1980.
    12. Dunwoody, C.L. Rapid Nitrate Loss From PM10 Filters. 
J. Air Pollut. Control Assoc., 36:817, 1986.
    13. Harrell, R.M. Measuring the Alkalinity of Hi-Vol Air Filters. 
EMSL/RTP-SOP-QAD-534, October 1985. Available from the U.S. 
Environmental Protection Agency, EMSL/QAD, Research Triangle Park, NC 
27711.
    14. Smith, F., P.S. Wohlschlegel, R.S.C. Rogers, and D.J. Mulligan. 
Investigation of Flow Rate Calibration Procedures Associated With the 
High Volume Method for Determination of Suspended Particulates. EPA-600/
4-78-047, U.S. Environmental Protection Agency, Research Triangle Park, 
NC 27711, 1978.

[52 FR 24664, July 1, 1987; 52 FR 29467, Aug. 7, 1987]

   Appendix K to Part 50--Interpretation of the National Ambient Air 
                  Quality Standards for PM10

    1.0 General.
    (a) This appendix explains the computations necessary for analyzing 
particulate matter data to determine attainment of the 24-hour and 
annual standards specified in 40 CFR 50.6. For the primary and secondary 
standards, particulate matter is measured in the ambient air as 
PM10 (particles with an aerodynamic diameter less than or 
equal to a nominal 10 micrometers) by a reference method based on 
appendix J of this part and designated in accordance with part 53 of 
this chapter, or by an equivalent method designated in accordance with 
part 53 of this chapter. The required frequency of measurements is 
specified in part 58 of this chapter.
    (b) The terms used in this appendix are defined as follows:
    Average refers to an arithmetic mean. All particulate matter 
standards are expressed in terms of expected annual values: Expected 
number of exceedances per year for the 24-hour standards and expected 
annual arithmetic mean for the annual standards.
    Daily value for PM10 refers to the 24-hour average 
concentration of PM10 calculated or measured from midnight to 
midnight (local time).
    Exceedance means a daily value that is above the level of the 24-
hour standard after

[[Page 70]]

rounding to the nearest 10 [micro]g/m\3\ (i.e., values ending in 5 or 
greater are to be rounded up).
    Expected annual value is the number approached when the annual 
values from an increasing number of years are averaged, in the absence 
of long-term trends in emissions or meteorological conditions.
    Year refers to a calendar year.
    (c) Although the discussion in this appendix focuses on monitored 
data, the same principles apply to modeling data, subject to EPA 
modeling guidelines.
    2.0 Attainment Determinations.
    2.1 24-Hour Primary and Secondary Standards.
    (a) Under 40 CFR 50.6(a) the 24-hour primary and secondary standards 
are attained when the expected number of exceedances per year at each 
monitoring site is less than or equal to one. In the simplest case, the 
number of expected exceedances at a site is determined by recording the 
number of exceedances in each calendar year and then averaging them over 
the past 3 calendar years. Situations in which 3 years of data are not 
available and possible adjustments for unusual events or trends are 
discussed in sections 2.3 and 2.4 of this appendix. Further, when data 
for a year are incomplete, it is necessary to compute an estimated 
number of exceedances for that year by adjusting the observed number of 
exceedances. This procedure, performed by calendar quarter, is described 
in section 3.0 of this appendix. The expected number of exceedances is 
then estimated by averaging the individual annual estimates for the past 
3 years.
    (b) The comparison with the allowable expected exceedance rate of 
one per year is made in terms of a number rounded to the nearest tenth 
(fractional values equal to or greater than 0.05 are to be rounded up; 
e.g., an exceedance rate of 1.05 would be rounded to 1.1, which is the 
lowest rate for nonattainment).
    2.2 Annual Primary and Secondary Standards. Under 40 CFR 50.6(b), 
the annual primary and secondary standards are attained when the 
expected annual arithmetic mean PM10 concentration is less 
than or equal to the level of the standard. In the simplest case, the 
expected annual arithmetic mean is determined by averaging the annual 
arithmetic mean PM10 concentrations for the past 3 calendar 
years. Because of the potential for incomplete data and the possible 
seasonality in PM10 concentrations, the annual mean shall be 
calculated by averaging the four quarterly means of PM10 
concentrations within the calendar year. The equations for calculating 
the annual arithmetic mean are given in section 4.0 of this appendix. 
Situations in which 3 years of data are not available and possible 
adjustments for unusual events or trends are discussed in sections 2.3 
and 2.4 of this appendix. The expected annual arithmetic mean is rounded 
to the nearest 1 [micro]g/m\3\ before comparison with the annual 
standards (fractional values equal to or greater than 0.5 are to be 
rounded up).
    2.3 Data Requirements.
    (a) 40 CFR 58.13 specifies the required minimum frequency of 
sampling for PM10. For the purposes of making comparisons 
with the particulate matter standards, all data produced by National Air 
Monitoring Stations (NAMS), State and Local Air Monitoring Stations 
(SLAMS) and other sites submitted to EPA in accordance with the part 58 
requirements must be used, and a minimum of 75 percent of the scheduled 
PM10 samples per quarter are required.
    (b) To demonstrate attainment of either the annual or 24-hour 
standards at a monitoring site, the monitor must provide sufficient data 
to perform the required calculations of sections 3.0 and 4.0 of this 
appendix. The amount of data required varies with the sampling 
frequency, data capture rate and the number of years of record. In all 
cases, 3 years of representative monitoring data that meet the 75 
percent criterion of the previous paragraph should be utilized, if 
available, and would suffice. More than 3 years may be considered, if 
all additional representative years of data meeting the 75 percent 
criterion are utilized. Data not meeting these criteria may also suffice 
to show attainment; however, such exceptions will have to be approved by 
the appropriate Regional Administrator in accordance with EPA guidance.
    (c) There are less stringent data requirements for showing that a 
monitor has failed an attainment test and thus has recorded a violation 
of the particulate matter standards. Although it is generally necessary 
to meet the minimum 75 percent data capture requirement per quarter to 
use the computational equations described in sections 3.0 and 4.0 of 
this appendix, this criterion does not apply when less data is 
sufficient to unambiguously establish nonattainment. The following 
examples illustrate how nonattainment can be demonstrated when a site 
fails to meet the completeness criteria. Nonattainment of the 24-hour 
primary standards can be established by the observed annual number of 
exceedances (e.g., four observed exceedances in a single year), or by 
the estimated number of exceedances derived from the observed number of 
exceedances and the required number of scheduled samples (e.g., two 
observed exceedances with every other day sampling). Nonattainment of 
the annual standards can be demonstrated on the basis of quarterly mean 
concentrations developed from observed data combined with one-half the 
minimum detectable concentration substituted for missing values. In both 
cases, expected annual values must exceed the levels allowed by the 
standards.
    2.4 Adjustment for Exceptional Events and Trends.

[[Page 71]]

    (a) An exceptional event is an uncontrollable event caused by 
natural sources of particulate matter or an event that is not expected 
to recur at a given location. Inclusion of such a value in the 
computation of exceedances or averages could result in inappropriate 
estimates of their respective expected annual values. To reduce the 
effect of unusual events, more than 3 years of representative data may 
be used. Alternatively, other techniques, such as the use of statistical 
models or the use of historical data could be considered so that the 
event may be discounted or weighted according to the likelihood that it 
will recur. The use of such techniques is subject to the approval of the 
appropriate Regional Administrator in accordance with EPA guidance.
    (b) In cases where long-term trends in emissions and air quality are 
evident, mathematical techniques should be applied to account for the 
trends to ensure that the expected annual values are not inappropriately 
biased by unrepresentative data. In the simplest case, if 3 years of 
data are available under stable emission conditions, this data should be 
used. In the event of a trend or shift in emission patterns, either the 
most recent representative year(s) could be used or statistical 
techniques or models could be used in conjunction with previous years of 
data to adjust for trends. The use of less than 3 years of data, and any 
adjustments are subject to the approval of the appropriate Regional 
Administrator in accordance with EPA guidance.
    3.0 Computational Equations for the 24-hour Standards.
    3.1 Estimating Exceedances for a Year.
    (a) If PM10 sampling is scheduled less frequently than 
every day, or if some scheduled samples are missed, a PM10 
value will not be available for each day of the year. To account for the 
possible effect of incomplete data, an adjustment must be made to the 
data collected at each monitoring location to estimate the number of 
exceedances in a calendar year. In this adjustment, the assumption is 
made that the fraction of missing values that would have exceeded the 
standard level is identical to the fraction of measured values above 
this level. This computation is to be made for all sites that are 
scheduled to monitor throughout the entire year and meet the minimum 
data requirements of section 2.3 of this appendix. Because of possible 
seasonal imbalance, this adjustment shall be applied on a quarterly 
basis. The estimate of the expected number of exceedances for the 
quarter is equal to the observed number of exceedances plus an increment 
associated with the missing data. The following equation must be used 
for these computations:

                               Equation 1
[GRAPHIC] [TIFF OMITTED] TR18JY97.180

where:

eq = the estimated number of exceedances for calendar quarter 
q;
vq = the observed number of exceedances for calendar quarter 
q;
Nq = the number of days in calendar quarter q;
nq = the number of days in calendar quarter q with 
PM10 data; and
q = the index for calendar quarter, q=1, 2, 3 or 4.

    (b) The estimated number of exceedances for a calendar quarter must 
be rounded to the nearest hundredth (fractional values equal to or 
greater than 0.005 must be rounded up).
    (c) The estimated number of exceedances for the year, e, is the sum 
of the estimates for each calendar quarter.

                               Equation 2
[GRAPHIC] [TIFF OMITTED] TR18JY97.181

    (d) The estimated number of exceedances for a single year must be 
rounded to one decimal place (fractional values equal to or greater than 
0.05 are to be rounded up). The expected number of exceedances is then 
estimated by averaging the individual annual estimates for the most 
recent 3 or more representative years of data. The expected number of 
exceedances must be rounded to one decimal place (fractional values 
equal to or greater than 0.05 are to be rounded up).
    (e) The adjustment for incomplete data will not be necessary for 
monitoring or modeling data which constitutes a complete record, i.e., 
365 days per year.
    (f) To reduce the potential for overestimating the number of 
expected exceedances, the correction for missing data will not be 
required for a calendar quarter in which the first observed exceedance 
has occurred if:
    (1) There was only one exceedance in the calendar quarter;
    (2) Everyday sampling is subsequently initiated and maintained for 4 
calendar quarters in accordance with 40 CFR 58.13; and
    (3) Data capture of 75 percent is achieved during the required 
period of everyday sampling. In addition, if the first exceedance is 
observed in a calendar quarter in which the monitor is already sampling 
every day, no adjustment for missing data will be made to the first 
exceedance if a 75 percent data capture rate was achieved in the quarter 
in which it was observed.

[[Page 72]]

                                Example 1

    a. During a particular calendar quarter, 39 out of a possible 92 
samples were recorded, with one observed exceedance of the 24-hour 
standard. Using Equation 1, the estimated number of exceedances for the 
quarter is:

eq=1x92/39=2.359 or 2.36.

    b. If the estimated exceedances for the other 3 calendar quarters in 
the year were 2.30, 0.0 and 0.0, then, using Equation 2, the estimated 
number of exceedances for the year is 2.36=2.30=0.0=0.0 which equals 
4.66 or 4.7. If no exceedances were observed for the 2 previous years, 
then the expected number of exceedances is estimated by: (1/
3)x(4.7=0=0)=1.57 or 1.6. Since 1.6 exceeds the allowable number of 
expected exceedances, this monitoring site would fail the attainment 
test.

                                Example 2

    In this example, everyday sampling was initiated following the first 
observed exceedance as required by 40 CFR 58.13. Accordingly, the first 
observed exceedance would not be adjusted for incomplete sampling. 
During the next three quarters, 1.2 exceedances were estimated. In this 
case, the estimated exceedances for the year would be 1.0=1.2=0.0=0.0 
which equals 2.2. If, as before, no exceedances were observed for the 
two previous years, then the estimated exceedances for the 3-year period 
would then be (1/3)x(2.2=0.0=0.0)=0.7, and the monitoring site would not 
fail the attainment test.
    3.2 Adjustments for Non-Scheduled Sampling Days.
    (a) If a systematic sampling schedule is used and sampling is 
performed on days in addition to the days specified by the systematic 
sampling schedule, e.g., during episodes of high pollution, then an 
adjustment must be made in the eqution for the estimation of 
exceedances. Such an adjustment is needed to eliminate the bias in the 
estimate of the quarterly and annual number of exceedances that would 
occur if the chance of an exceedance is different for scheduled than for 
non-scheduled days, as would be the case with episode sampling.
    (b) The required adjustment treats the systematic sampling schedule 
as a stratified sampling plan. If the period from one scheduled sample 
until the day preceding the next scheduled sample is defined as a 
sampling stratum, then there is one stratum for each scheduled sampling 
day. An average number of observed exceedances is computed for each of 
these sampling strata. With nonscheduled sampling days, the estimated 
number of exceedances is defined as:

                               Equation 3
[GRAPHIC] [TIFF OMITTED] TR18JY97.182

where:

eq = the estimated number of exceedances for the quarter;
Nq = the number of days in the quarter;
mq = the number of strata with samples during the quarter;
vj = the number of observed exceedances in stratum j; and
kj = the number of actual samples in stratum j.

    (c) Note that if only one sample value is recorded in each stratum, 
then Equation 3 reduces to Equation 1.

                                Example 3

    A monitoring site samples according to a systematic sampling 
schedule of one sample every 6 days, for a total of 15 scheduled samples 
in a quarter out of a total of 92 possible samples. During one 6-day 
period, potential episode levels of PM10 were suspected, so 5 
additional samples were taken. One of the regular scheduled samples was 
missed, so a total of 19 samples in 14 sampling strata were measured. 
The one 6-day sampling stratum with 6 samples recorded 2 exceedances. 
The remainder of the quarter with one sample per stratum recorded zero 
exceedances. Using Equation 3, the estimated number of exceedances for 
the quarter is:

eq=(92/14)x(2/6=0=. . .=0)=2.19.

    4.0 Computational Equations for Annual Standards.
    4.1 Calculation of the Annual Arithmetic Mean. (a) An annual 
arithmetic mean value for PM10 is determined by averaging the 
quarterly means for the 4 calendar quarters of the year. The following 
equation is to be used for calculation of the mean for a calendar 
quarter:

                               Equation 4
[GRAPHIC] [TIFF OMITTED] TR18JY97.183

where:

xq = the quarterly mean concentration for quarter q, q=1, 2, 
3, or 4,
nq = the number of samples in the quarter, and
xi = the ith concentration value recorded in the quarter.

    (b) The quarterly mean, expressed in [micro]g/m\3\, must be rounded 
to the nearest tenth (fractional values of 0.05 should be rounded up).

[[Page 73]]

    (c) The annual mean is calculated by using the following equation:

                               Equation 5
[GRAPHIC] [TIFF OMITTED] TR18JY97.184

where:

x = the annual mean; and
xq = the mean for calendar quarter q.

    (d) The average of quarterly means must be rounded to the nearest 
tenth (fractional values of 0.05 should be rounded up).
    (e) The use of quarterly averages to compute the annual average will 
not be necessary for monitoring or modeling data which results in a 
complete record, i.e., 365 days per year.
    (f) The expected annual mean is estimated as the average of three or 
more annual means. This multi-year estimate, expressed in [micro]g/m\3\, 
shall be rounded to the nearest integer for comparison with the annual 
standard (fractional values of 0.5 should be rounded up).

                                Example 4

    Using Equation 4, the quarterly means are calculated for each 
calendar quarter. If the quarterly means are 52.4, 75.3, 82.1, and 63.2 
[micro]g/m\3\, then the annual mean is:

x = (1/4)x(52.4=75.3=82.1=63.2) = 68.25 or 68.3.

    4.2 Adjustments for Non-scheduled Sampling Days. (a) An adjustment 
in the calculation of the annual mean is needed if sampling is performed 
on days in addition to the days specified by the systematic sampling 
schedule. For the same reasons given in the discussion of estimated 
exceedances, under section 3.2 of this appendix, the quarterly averages 
would be calculated by using the following equation:

                               Equation 6
[GRAPHIC] [TIFF OMITTED] TR18JY97.185

where:

xq = the quarterly mean concentration for quarter q, q=1, 2, 
3, or 4;
xij = the ith concentration value recorded in stratum j;
kj = the number of actual samples in stratum j; and
mq = the number of strata with data in the quarter.

    (b) If one sample value is recorded in each stratum, Equation 6 
reduces to a simple arithmetic average of the observed values as 
described by Equation 4.

                                Example 5

    a. During one calendar quarter, 9 observations were recorded. These 
samples were distributed among 7 sampling strata, with 3 observations in 
one stratum. The concentrations of the 3 observations in the single 
stratum were 202, 242, and 180 [micro]g/m\3\. The remaining 6 observed 
concentrations were 55, 68, 73, 92, 120, and 155 [micro]g/m\3\. Applying 
the weighting factors specified in Equation 6, the quarterly mean is:

xq = (1/7) x [(1/3) x (202 = 242 = 180) = 155 = 68 = 73 = 92 
= 120 = 155] = 110.1

    b. Although 24-hour measurements are rounded to the nearest 10 
[micro]g/m\3\ for determinations of exceedances of the 24-hour standard, 
note that these values are rounded to the nearest 1 [micro]g/m\3\ for 
the calculation of means.

[62 FR 38712, July 18, 1997]

 Appendix L to Part 50--Reference Method for the Determination of Fine 
        Particulate Matter as PM2.5 in the Atmosphere

    1.0 Applicability.
    1.1 This method provides for the measurement of the mass 
concentration of fine particulate matter having an aerodynamic diameter 
less than or equal to a nominal 2.5 micrometers (PM2.5) in 
ambient air over a 24-hour period for purposes of determining whether 
the primary and secondary national ambient air quality standards for 
fine particulate matter specified in Sec. 50.7 of this part are met. 
The measurement process is considered to be nondestructive, and the 
PM2.5 sample obtained can be subjected to subsequent physical 
or chemical analyses. Quality assessment procedures are provided in part 
58, appendix A of this chapter, and quality assurance guidance are 
provided in references 1, 2, and 3 in section 13.0 of this appendix.
    1.2 This method will be considered a reference method for purposes 
of part 58 of this chapter only if:
    (a) The associated sampler meets the requirements specified in this 
appendix and the applicable requirements in part 53 of this chapter, and
    (b) The method and associated sampler have been designated as a 
reference method in accordance with part 53 of this chapter.
    1.3 PM2.5 samplers that meet nearly all specifications 
set forth in this method but have minor deviations and/or modifications 
of the reference method sampler will be designated as ``Class I'' 
equivalent methods for PM2.5 in accordance with part 53 of 
this chapter.
    2.0 Principle.
    2.1 An electrically powered air sampler draws ambient air at a 
constant volumetric flow rate into a specially shaped inlet and

[[Page 74]]

through an inertial particle size separator (impactor) where the 
suspended particulate matter in the PM2.5 size range is 
separated for collection on a polytetrafluoroethylene (PTFE) filter over 
the specified sampling period. The air sampler and other aspects of this 
reference method are specified either explicitly in this appendix or 
generally with reference to other applicable regulations or quality 
assurance guidance.
    2.2 Each filter is weighed (after moisture and temperature 
conditioning) before and after sample collection to determine the net 
gain due to collected PM2.5. The total volume of air sampled 
is determined by the sampler from the measured flow rate at actual 
ambient temperature and pressure and the sampling time. The mass 
concentration of PM2.5 in the ambient air is computed as the 
total mass of collected particles in the PM2.5 size range 
divided by the actual volume of air sampled, and is expressed in 
micrograms per cubic meter of air ([micro]g/m\3\).
    3.0 PM2.5 Measurement Range.
    3.1 Lower concentration limit. The lower detection limit of the mass 
concentration measurement range is estimated to be approximately 2 
[micro]g/m\3\, based on noted mass changes in field blanks in 
conjunction with the 24 m\3\ nominal total air sample volume specified 
for the 24-hour sample.
    3.2 Upper concentration limit. The upper limit of the mass 
concentration range is determined by the filter mass loading beyond 
which the sampler can no longer maintain the operating flow rate within 
specified limits due to increased pressure drop across the loaded 
filter. This upper limit cannot be specified precisely because it is a 
complex function of the ambient particle size distribution and type, 
humidity, the individual filter used, the capacity of the sampler flow 
rate control system, and perhaps other factors. Nevertheless, all 
samplers are estimated to be capable of measuring 24-hour 
PM2.5 mass concentrations of at least 200 [micro]g/m\3\ while 
maintaining the operating flow rate within the specified limits.
    3.3 Sample period. The required sample period for PM2.5 
concentration measurements by this method shall be 1,380 to 1500 minutes 
(23 to 25 hours). However, when a sample period is less than 1,380 
minutes, the measured concentration (as determined by the collected 
PM2.5 mass divided by the actual sampled air volume), 
multiplied by the actual number of minutes in the sample period and 
divided by 1,440, may be used as if it were a valid concentration 
measurement for the specific purpose of determining a violation of the 
NAAQS. This value assumes that the PM2.5 concentration is 
zero for the remaining portion of the sample period and therefore 
represents the minimum concentration that could have been measured for 
the full 24-hour sample period. Accordingly, if the value thus 
calculated is high enough to be an exceedance, such an exceedance would 
be a valid exceedance for the sample period. When reported to AIRS, this 
data value should receive a special code to identify it as not to be 
commingled with normal concentration measurements or used for other 
purposes.
    4.0 Accuracy.
    4.1 Because the size and volatility of the particles making up 
ambient particulate matter vary over a wide range and the mass 
concentration of particles varies with particle size, it is difficult to 
define the accuracy of PM2.5 measurements in an absolute 
sense. The accuracy of PM2.5 measurements is therefore 
defined in a relative sense, referenced to measurements provided by this 
reference method. Accordingly, accuracy shall be defined as the degree 
of agreement between a subject field PM2.5 sampler and a 
collocated PM2.5 reference method audit sampler operating 
simultaneously at the monitoring site location of the subject sampler 
and includes both random (precision) and systematic (bias) errors. The 
requirements for this field sampler audit procedure are set forth in 
part 58, appendix A of this chapter.
    4.2 Measurement system bias. Results of collocated measurements 
where the duplicate sampler is a reference method sampler are used to 
assess a portion of the measurement system bias according to the 
schedule and procedure specified in part 58, appendix A of this chapter.
    4.3 Audits with reference method samplers to determine system 
accuracy and bias. According to the schedule and procedure specified in 
part 58, appendix A of this chapter, a reference method sampler is 
required to be located at each of selected PM2.5 SLAMS sites 
as a duplicate sampler. The results from the primary sampler and the 
duplicate reference method sampler are used to calculate accuracy of the 
primary sampler on a quarterly basis, bias of the primary sampler on an 
annual basis, and bias of a single reporting organization on an annual 
basis. Reference 2 in section 13.0 of this appendix provides additional 
information and guidance on these reference method audits.
    4.4 Flow rate accuracy and bias. Part 58, appendix A of this chapter 
requires that the flow rate accuracy and bias of individual 
PM2.5 samplers used in SLAMS monitoring networks be assessed 
periodically via audits of each sampler's operational flow rate. In 
addition, part 58, appendix A of this chapter requires that flow rate 
bias for each reference and equivalent method operated by each reporting 
organization be assessed quarterly and annually. Reference 2 in section 
13.0 of this appendix provides additional information and guidance on 
flow rate accuracy audits and calculations for accuracy and bias.
    5.0 Precision. A data quality objective of 10 percent coefficient of 
variation or better has

[[Page 75]]

been established for the operational precision of PM2.5 
monitoring data.
    5.1 Tests to establish initial operational precision for each 
reference method sampler are specified as a part of the requirements for 
designation as a reference method under Sec. 53.58 of this chapter.
    5.2 Measurement System Precision. Collocated sampler results, where 
the duplicate sampler is not a reference method sampler but is a sampler 
of the same designated method as the primary sampler, are used to assess 
measurement system precision according to the schedule and procedure 
specified in part 58, appendix A of this chapter. Part 58, appendix A of 
this chapter requires that these collocated sampler measurements be used 
to calculate quarterly and annual precision estimates for each primary 
sampler and for each designated method employed by each reporting 
organization. Reference 2 in section 13.0 of this appendix provides 
additional information and guidance on this requirement.
    6.0 Filter for PM2.5 Sample Collection. Any filter 
manufacturer or vendor who sells or offers to sell filters specifically 
identified for use with this PM2.5 reference method shall 
certify that the required number of filters from each lot of filters 
offered for sale as such have been tested as specified in this section 
6.0 and meet all of the following design and performance specifications.
    6.1 Size. Circular, 46.2 mm diameter 0.25 mm.
    6.2 Medium. Polytetrafluoroethylene (PTFE Teflon), with integral 
support ring.
    6.3 Support ring. Polymethylpentene (PMP) or equivalent inert 
material, 0.38 0.04 mm thick, outer diameter 46.2 
mm 0.25 mm, and width of 3.68 mm ( 0.00, -0.51 mm).
    6.4 Pore size. 2 [micro]m as measured by ASTM F 316-94.
    6.5 Filter thickness. 30 to 50 [micro]m.
    6.6 Maximum pressure drop (clean filter). 30 cm H2O 
column @ 16.67 L/min clean air flow.
    6.7 Maximum moisture pickup. Not more than 10 [micro]g weight 
increase after 24-hour exposure to air of 40 percent relative humidity, 
relative to weight after 24-hour exposure to air of 35 percent relative 
humidity.
    6.8 Collection efficiency. Greater than 99.7 percent, as measured by 
the DOP test (ASTM D 2986-91) with 0.3 [micro]m particles at the 
sampler's operating face velocity.
    6.9 Filter weight stability. Filter weight loss shall be less than 
20 [micro]g, as measured in each of the following two tests specified in 
sections 6.9.1 and 6.9.2 of this appendix. The following conditions 
apply to both of these tests: Filter weight loss shall be the average 
difference between the initial and the final filter weights of a random 
sample of test filters selected from each lot prior to sale. The number 
of filters tested shall be not less than 0.1 percent of the filters of 
each manufacturing lot, or 10 filters, whichever is greater. The filters 
shall be weighed under laboratory conditions and shall have had no air 
sample passed through them, i.e., filter blanks. Each test procedure 
must include initial conditioning and weighing, the test, and final 
conditioning and weighing. Conditioning and weighing shall be in 
accordance with sections 8.0 through 8.2 of this appendix and general 
guidance provided in reference 2 of section 13.0 of this appendix.
    6.9.1 Test for loose, surface particle contamination. After the 
initial weighing, install each test filter, in turn, in a filter 
cassette (Figures L-27, L-28, and L-29 of this appendix) and drop the 
cassette from a height of 25 cm to a flat hard surface, such as a 
particle-free wood bench. Repeat two times, for a total of three drop 
tests for each test filter. Remove the test filter from the cassette and 
weigh the filter. The average change in weight must be less than 20 
[micro]g.
    6.9.2 Test for temperature stability. After weighing each filter, 
place the test filters in a drying oven set at 40 [deg]C 2 [deg]C for not less than 48 hours. Remove, condition, 
and reweigh each test filter. The average change in weight must be less 
than 20 [micro]g.
    6.10 Alkalinity. Less than 25 microequivalents/gram of filter, as 
measured by the guidance given in reference 2 in section 13.0 of this 
appendix.
    6.11 Supplemental requirements. Although not required for 
determination of PM2.5 mass concentration under this 
reference method, additional specifications for the filter must be 
developed by users who intend to subject PM2.5 filter samples 
to subsequent chemical analysis. These supplemental specifications 
include background chemical contamination of the filter and any other 
filter parameters that may be required by the method of chemical 
analysis. All such supplemental filter specifications must be compatible 
with and secondary to the primary filter specifications given in this 
section 6.0 of this appendix.
    7.0 PM2.5 Sampler.
    7.1 Configuration. The sampler shall consist of a sample air inlet, 
downtube, particle size separator (impactor), filter holder assembly, 
air pump and flow rate control system, flow rate measurement device, 
ambient and filter temperature monitoring system, barometric pressure 
measurement system, timer, outdoor environmental enclosure, and suitable 
mechanical, electrical, or electronic control capability to meet or 
exceed the design and functional performance as specified in this 
section 7.0 of this appendix. The performance specifications require 
that the sampler:
    (a) Provide automatic control of sample volumetric flow rate and 
other operational parameters.
    (b) Monitor these operational parameters as well as ambient 
temperature and pressure.
    (c) Provide this information to the sampler operator at the end of 
each sample period in

[[Page 76]]

digital form, as specified in table L-1 of section 7.4.19 of this 
appendix.
    7.2 Nature of specifications. The PM2.5 sampler is 
specified by a combination of design and performance requirements. The 
sample inlet, downtube, particle size discriminator, filter cassette, 
and the internal configuration of the filter holder assembly are 
specified explicitly by design figures and associated mechanical 
dimensions, tolerances, materials, surface finishes, assembly 
instructions, and other necessary specifications. All other aspects of 
the sampler are specified by required operational function and 
performance, and the design of these other aspects (including the design 
of the lower portion of the filter holder assembly) is optional, subject 
to acceptable operational performance. Test procedures to demonstrate 
compliance with both the design and performance requirements are set 
forth in subpart E of part 53 of this chapter.
    7.3 Design specifications. Except as indicated in this section 7.3 
of this appendix, these components must be manufactured or reproduced 
exactly as specified, in an ISO 9001-registered facility, with 
registration initially approved and subsequently maintained during the 
period of manufacture. See Sec. 53.1(t) of this chapter for the 
definition of an ISO-registered facility. Minor modifications or 
variances to one or more components that clearly would not affect the 
aerodynamic performance of the inlet, downtube, impactor, or filter 
cassette will be considered for specific approval. Any such proposed 
modifications shall be described and submitted to the EPA for specific 
individual acceptability either as part of a reference or equivalent 
method application under part 53 of this chapter or in writing in 
advance of such an intended application under part 53 of this chapter.
    7.3.1 Sample inlet assembly. The sample inlet assembly, consisting 
of the inlet, downtube, and impactor shall be configured and assembled 
as indicated in Figure L-1 of this appendix and shall meet all 
associated requirements. A portion of this assembly shall also be 
subject to the maximum overall sampler leak rate specification under 
section 7.4.6 of this appendix.
    7.3.2 Inlet. The sample inlet shall be fabricated as indicated in 
Figures L-2 through L-18 of this appendix and shall meet all associated 
requirements.
    7.3.3 Downtube. The downtube shall be fabricated as indicated in 
Figure L-19 of this appendix and shall meet all associated requirements.
    7.3.4 Impactor.
    7.3.4.1 The impactor (particle size separator) shall be fabricated 
as indicated in Figures L-20 through L-24 of this appendix and shall 
meet all associated requirements. Following the manufacture and 
finishing of each upper impactor housing (Figure L-21 of this appendix), 
the dimension of the impaction jet must be verified by the manufacturer 
using Class ZZ go/no-go plug gauges that are traceable to NIST.
    7.3.4.2 Impactor filter specifications:
    (a) Size. Circular, 35 to 37 mm diameter.
    (b) Medium. Borosilicate glass fiber, without binder.
    (c) Pore size. 1 to 1.5 micrometer, as measured by ASTM F 316-80.
    (d) Thickness. 300 to 500 micrometers.
    7.3.4.3 Impactor oil specifications:
    (a) Composition. Tetramethyltetraphenyltrisiloxane, single-compound 
diffusion oil.
    (b) Vapor pressure. Maximum 2x10-8 mm Hg at 25 [deg]C.
    (c) Viscosity. 36 to 40 centistokes at 25 [deg]C.
    (d) Density. 1.06 to 1.07 g/cm\3\ at 25 [deg]C.
    (e) Quantity. 1 mL 0.1 mL.
    7.3.5 Filter holder assembly. The sampler shall have a sample filter 
holder assembly to adapt and seal to the down tube and to hold and seal 
the specified filter, under section 6.0 of this appendix, in the sample 
air stream in a horizontal position below the downtube such that the 
sample air passes downward through the filter at a uniform face 
velocity. The upper portion of this assembly shall be fabricated as 
indicated in Figures L-25 and L-26 of this appendix and shall accept and 
seal with the filter cassette, which shall be fabricated as indicated in 
Figures L-27 through L-29 of this appendix.
    (a) The lower portion of the filter holder assembly shall be of a 
design and construction that:
    (1) Mates with the upper portion of the assembly to complete the 
filter holder assembly,
    (2) Completes both the external air seal and the internal filter 
cassette seal such that all seals are reliable over repeated filter 
changings, and
    (3) Facilitates repeated changing of the filter cassette by the 
sampler operator.
    (b) Leak-test performance requirements for the filter holder 
assembly are included in section 7.4.6 of this appendix.
    (c) If additional or multiple filters are stored in the sampler as 
part of an automatic sequential sample capability, all such filters, 
unless they are currently and directly installed in a sampling channel 
or sampling configuration (either active or inactive), shall be covered 
or (preferably) sealed in such a way as to:
    (1) Preclude significant exposure of the filter to possible 
contamination or accumulation of dust, insects, or other material that 
may be present in the ambient air, sampler, or sampler ventilation air 
during storage periods either before or after sampling; and
    (2) To minimize loss of volatile or semi-volatile PM sample 
components during storage of the filter following the sample period.

[[Page 77]]

    7.3.6 Flow rate measurement adapter. A flow rate measurement adapter 
as specified in Figure L-30 of this appendix shall be furnished with 
each sampler.
    7.3.7 Surface finish. All internal surfaces exposed to sample air 
prior to the filter shall be treated electrolytically in a sulfuric acid 
bath to produce a clear, uniform anodized surface finish of not less 
than 1000 mg/ft\2\ (1.08 mg/cm\2\) in accordance with military standard 
specification (mil. spec.) 8625F, Type II, Class 1 in reference 4 of 
section 13.0 of this appendix. This anodic surface coating shall not be 
dyed or pigmented. Following anodization, the surfaces shall be sealed 
by immersion in boiling deionized water for not less than 15 minutes. 
Section 53.51(d)(2) of this chapter should also be consulted.
    7.3.8 Sampling height. The sampler shall be equipped with legs, a 
stand, or other means to maintain the sampler in a stable, upright 
position and such that the center of the sample air entrance to the 
inlet, during sample collection, is maintained in a horizontal plane and 
is 2.0 0.2 meters above the floor or other 
horizontal supporting surface. Suitable bolt holes, brackets, tie-downs, 
or other means should be provided to facilitate mechanically securing 
the sample to the supporting surface to prevent toppling of the sampler 
due to wind.
    7.4 Performance specifications.
    7.4.1 Sample flow rate. Proper operation of the impactor requires 
that specific air velocities be maintained through the device. 
Therefore, the design sample air flow rate through the inlet shall be 
16.67 L/min (1.000 m\3\/hour) measured as actual volumetric flow rate at 
the temperature and pressure of the sample air entering the inlet.
    7.4.2 Sample air flow rate control system. The sampler shall have a 
sample air flow rate control system which shall be capable of providing 
a sample air volumetric flow rate within the specified range, under 
section 7.4.1 of this appendix, for the specified filter, under section 
6.0 of this appendix, at any atmospheric conditions specified, under 
section 7.4.7 of this appendix, at a filter pressure drop equal to that 
of a clean filter plus up to 75 cm water column (55 mm Hg), and over the 
specified range of supply line voltage, under section 7.4.15.1 of this 
appendix. This flow control system shall allow for operator adjustment 
of the operational flow rate of the sampler over a range of at least 
15 percent of the flow rate specified in section 
7.4.1 of this appendix.
    7.4.3 Sample flow rate regulation. The sample flow rate shall be 
regulated such that for the specified filter, under section 6.0 of this 
appendix, at any atmospheric conditions specified, under section 7.4.7 
of this appendix, at a filter pressure drop equal to that of a clean 
filter plus up to 75 cm water column (55 mm Hg), and over the specified 
range of supply line voltage, under section 7.4.15.1 of this appendix, 
the flow rate is regulated as follows:
    7.4.3.1 The volumetric flow rate, measured or averaged over 
intervals of not more than 5 minutes over a 24-hour period, shall not 
vary more than 5 percent from the specified 16.67 
L/min flow rate over the entire sample period.
    7.4.3.2 The coefficient of variation (sample standard deviation 
divided by the mean) of the flow rate, measured over a 24-hour period, 
shall not be greater than 2 percent.
    7.4.3.3 The amplitude of short-term flow rate pulsations, such as 
may originate from some types of vacuum pumps, shall be attenuated such 
that they do not cause significant flow measurement error or affect the 
collection of particles on the particle collection filter.
    7.4.4 Flow rate cut off. The sampler's sample air flow rate control 
system shall terminate sample collection and stop all sample flow for 
the remainder of the sample period in the event that the sample flow 
rate deviates by more than 10 percent from the sampler design flow rate 
specified in section 7.4.1 of this appendix for more than 60 seconds. 
However, this sampler cut-off provision shall not apply during periods 
when the sampler is inoperative due to a temporary power interruption, 
and the elapsed time of the inoperative period shall not be included in 
the total sample time measured and reported by the sampler, under 
section 7.4.13 of this appendix.
    7.4.5 Flow rate measurement.
    7.4.5.1 The sampler shall provide a means to measure and indicate 
the instantaneous sample air flow rate, which shall be measured as 
volumetric flow rate at the temperature and pressure of the sample air 
entering the inlet, with an accuracy of 2 percent. 
The measured flow rate shall be available for display to the sampler 
operator at any time in either sampling or standby modes, and the 
measurement shall be updated at least every 30 seconds. The sampler 
shall also provide a simple means by which the sampler operator can 
manually start the sample flow temporarily during non-sampling modes of 
operation, for the purpose of checking the sample flow rate or the flow 
rate measurement system.
    7.4.5.2 During each sample period, the sampler's flow rate 
measurement system shall automatically monitor the sample volumetric 
flow rate, obtaining flow rate measurements at intervals of not greater 
than 30 seconds.
    (a) Using these interval flow rate measurements, the sampler shall 
determine or calculate the following flow-related parameters, scaled in 
the specified engineering units:
    (1) The instantaneous or interval-average flow rate, in L/min.
    (2) The value of the average sample flow rate for the sample period, 
in L/min.

[[Page 78]]

    (3) The value of the coefficient of variation (sample standard 
deviation divided by the average) of the sample flow rate for the sample 
period, in percent.
    (4) The occurrence of any time interval during the sample period in 
which the measured sample flow rate exceeds a range of 5 percent of the average flow rate for the sample period 
for more than 5 minutes, in which case a warning flag indicator shall be 
set.
    (5) The value of the integrated total sample volume for the sample 
period, in m\3\.
    (b) Determination or calculation of these values shall properly 
exclude periods when the sampler is inoperative due to temporary 
interruption of electrical power, under section 7.4.13 of this appendix, 
or flow rate cut off, under section 7.4.4 of this appendix.
    (c) These parameters shall be accessible to the sampler operator as 
specified in table L-1 of section 7.4.19 of this appendix. In addition, 
it is strongly encouraged that the flow rate for each 5-minute interval 
during the sample period be available to the operator following the end 
of the sample period.
    7.4.6 Leak test capability.
    7.4.6.1 External leakage. The sampler shall include an external air 
leak-test capability consisting of components, accessory hardware, 
operator interface controls, a written procedure in the associated 
Operation/Instruction Manual, under section 7.4.18 of this appendix, and 
all other necessary functional capability to permit and facilitate the 
sampler operator to conveniently carry out a leak test of the sampler at 
a field monitoring site without additional equipment. The sampler 
components to be subjected to this leak test include all components and 
their interconnections in which external air leakage would or could 
cause an error in the sampler's measurement of the total volume of 
sample air that passes through the sample filter.
    (a) The suggested technique for the operator to use for this leak 
test is as follows:
    (1) Remove the sampler inlet and installs the flow rate measurement 
adapter supplied with the sampler, under section 7.3.6 of this appendix.
    (2) Close the valve on the flow rate measurement adapter and use the 
sampler air pump to draw a partial vacuum in the sampler, including (at 
least) the impactor, filter holder assembly (filter in place), flow 
measurement device, and interconnections between these devices, of at 
least 55 mm Hg (75 cm water column), measured at a location downstream 
of the filter holder assembly.
    (3) Plug the flow system downstream of these components to isolate 
the components under vacuum from the pump, such as with a built-in 
valve.
    (4) Stop the pump.
    (5) Measure the trapped vacuum in the sampler with a built-in 
pressure measuring device.
    (6) (i) Measure the vacuum in the sampler with the built-in pressure 
measuring device again at a later time at least 10 minutes after the 
first pressure measurement.
    (ii) Caution: Following completion of the test, the adaptor valve 
should be opened slowly to limit the flow rate of air into the sampler. 
Excessive air flow rate may blow oil out of the impactor.
    (7) Upon completion of the test, open the adaptor valve, remove the 
adaptor and plugs, and restore the sampler to the normal operating 
configuration.
    (b) The associated leak test procedure shall require that for 
successful passage of this test, the difference between the two pressure 
measurements shall not be greater than the number of mm of Hg specified 
for the sampler by the manufacturer, based on the actual internal volume 
of the sampler, that indicates a leak of less than 80 mL/min.
    (c) Variations of the suggested technique or an alternative external 
leak test technique may be required for samplers whose design or 
configuration would make the suggested technique impossible or 
impractical. The specific proposed external leak test procedure, or 
particularly an alternative leak test technique, proposed for a 
particular candidate sampler may be described and submitted to the EPA 
for specific individual acceptability either as part of a reference or 
equivalent method application under part 53 of this chapter or in 
writing in advance of such an intended application under part 53 of this 
chapter.
    7.4.6.2 Internal, filter bypass leakage. The sampler shall include 
an internal, filter bypass leak-check capability consisting of 
components, accessory hardware, operator interface controls, a written 
procedure in the Operation/Instruction Manual, and all other necessary 
functional capability to permit and facilitate the sampler operator to 
conveniently carry out a test for internal filter bypass leakage in the 
sampler at a field monitoring site without additional equipment. The 
purpose of the test is to determine that any portion of the sample flow 
rate that leaks past the sample filter without passing through the 
filter is insignificant relative to the design flow rate for the 
sampler.
    (a) The suggested technique for the operator to use for this leak 
test is as follows:
    (1) Carry out an external leak test as provided under section 
7.4.6.1 of this appendix which indicates successful passage of the 
prescribed external leak test.
    (2) Install a flow-impervious membrane material in the filter 
cassette, either with or without a filter, as appropriate, which 
effectively prevents air flow through the filter.
    (3) Use the sampler air pump to draw a partial vacuum in the 
sampler, downstream of the filter holder assembly, of at least 55 mm Hg 
(75 cm water column).

[[Page 79]]

    (4) Plug the flow system downstream of the filter holder to isolate 
the components under vacuum from the pump, such as with a built-in 
valve.
    (5) Stop the pump.
    (6) Measure the trapped vacuum in the sampler with a built-in 
pressure measuring device.
    (7) Measure the vacuum in the sampler with the built-in pressure 
measuring device again at a later time at least 10 minutes after the 
first pressure measurement.
    (8) Remove the flow plug and membrane and restore the sampler to the 
normal operating configuration.
    (b) The associated leak test procedure shall require that for 
successful passage of this test, the difference between the two pressure 
measurements shall not be greater than the number of mm of Hg specified 
for the sampler by the manufacturer, based on the actual internal volume 
of the portion of the sampler under vacuum, that indicates a leak of 
less than 80 mL/min.
    (c) Variations of the suggested technique or an alternative 
internal, filter bypass leak test technique may be required for samplers 
whose design or configuration would make the suggested technique 
impossible or impractical. The specific proposed internal leak test 
procedure, or particularly an alternative internal leak test technique 
proposed for a particular candidate sampler may be described and 
submitted to the EPA for specific individual acceptability either as 
part of a reference or equivalent method application under part 53 of 
this chapter or in writing in advance of such intended application under 
part 53 of this chapter.
    7.4.7 Range of operational conditions. The sampler is required to 
operate properly and meet all requirements specified in this appendix 
over the following operational ranges.
    7.4.7.1 Ambient temperature. -30 to =45 [deg]C (Note: Although for 
practical reasons, the temperature range over which samplers are 
required to be tested under part 53 of this chapter is -20 to =40 
[deg]C, the sampler shall be designed to operate properly over this 
wider temperature range.).
    7.4.7.2 Ambient relative humidity. 0 to 100 percent.
    7.4.7.3 Barometric pressure range. 600 to 800 mm Hg.
    7.4.8 Ambient temperature sensor. The sampler shall have capability 
to measure the temperature of the ambient air surrounding the sampler 
over the range of -30 to =45 [deg]C, with a resolution of 0.1 [deg]C and 
accuracy of 2.0 [deg]C, referenced as described in 
reference 3 in section 13.0 of this appendix, with and without maximum 
solar insolation.
    7.4.8.1 The ambient temperature sensor shall be mounted external to 
the sampler enclosure and shall have a passive, naturally ventilated sun 
shield. The sensor shall be located such that the entire sun shield is 
at least 5 cm above the horizontal plane of the sampler case or 
enclosure (disregarding the inlet and downtube) and external to the 
vertical plane of the nearest side or protuberance of the sampler case 
or enclosure. The maximum temperature measurement error of the ambient 
temperature measurement system shall be less than 1.6 [deg]C at 1 m/s 
wind speed and 1000 W/m2 solar radiation intensity.
    7.4.8.2 The ambient temperature sensor shall be of such a design and 
mounted in such a way as to facilitate its convenient dismounting and 
immersion in a liquid for calibration and comparison to the filter 
temperature sensor, under section 7.4.11 of this appendix.
    7.4.8.3 This ambient temperature measurement shall be updated at 
least every 30 seconds during both sampling and standby (non-sampling) 
modes of operation. A visual indication of the current (most recent) 
value of the ambient temperature measurement, updated at least every 30 
seconds, shall be available to the sampler operator during both sampling 
and standby (non-sampling) modes of operation, as specified in table L-1 
of section 7.4.19 of this appendix.
    7.4.8.4 This ambient temperature measurement shall be used for the 
purpose of monitoring filter temperature deviation from ambient 
temperature, as required by section 7.4.11 of this appendix, and may be 
used for purposes of effecting filter temperature control, under section 
7.4.10 of this appendix, or computation of volumetric flow rate, under 
sections 7.4.1 to 7.4.5 of this appendix, if appropriate.
    7.4.8.5 Following the end of each sample period, the sampler shall 
report the maximum, minimum, and average temperature for the sample 
period, as specified in table L-1 of section 7.4.19 of this appendix.
    7.4.9 Ambient barometric sensor. The sampler shall have capability 
to measure the barometric pressure of the air surrounding the sampler 
over a range of 600 to 800 mm Hg referenced as described in reference 3 
in section 13.0 of this appendix; also see part 53, subpart E of this 
chapter. This barometric pressure measurement shall have a resolution of 
5 mm Hg and an accuracy of 10 mm Hg and shall be 
updated at least every 30 seconds. A visual indication of the value of 
the current (most recent) barometric pressure measurement, updated at 
least every 30 seconds, shall be available to the sampler operator 
during both sampling and standby (non-sampling) modes of operation, as 
specified in table L-1 of section 7.4.19 of this appendix. This 
barometric pressure measurement may be used for purposes of computation 
of volumetric flow rate, under sections 7.4.1 to 7.4.5 of this appendix, 
if appropriate. Following the end of a sample period, the sampler shall 
report the maximum, minimum, and mean barometric pressures for the 
sample period,

[[Page 80]]

as specified in table L-1 of section 7.4.19 of this appendix.
    7.4.10 Filter temperature control (sampling and post-sampling). The 
sampler shall provide a means to limit the temperature rise of the 
sample filter (all sample filters for sequential samplers), from 
insolation and other sources, to no more 5 [deg]C above the temperature 
of the ambient air surrounding the sampler, during both sampling and 
post-sampling periods of operation. The post-sampling period is the non-
sampling period between the end of the active sampling period and the 
time of retrieval of the sample filter by the sampler operator.
    7.4.11 Filter temperature sensor(s).
    7.4.11.1 The sampler shall have the capability to monitor the 
temperature of the sample filter (all sample filters for sequential 
samplers) over the range of -30 to =45 [deg]C during both sampling and 
non-sampling periods. While the exact location of this temperature 
sensor is not explicitly specified, the filter temperature measurement 
system must demonstrate agreement, within 1 [deg]C, with a test 
temperature sensor located within 1 cm of the center of the filter 
downstream of the filter during both sampling and non-sampling modes, as 
specified in the filter temperature measurement test described in part 
53, subpart E of this chapter. This filter temperature measurement shall 
have a resolution of 0.1 [deg]C and accuracy of 1.0 [deg]C, referenced as described in reference 3 in 
section 13.0 of this appendix. This temperature sensor shall be of such 
a design and mounted in such a way as to facilitate its reasonably 
convenient dismounting and immersion in a liquid for calibration and 
comparison to the ambient temperature sensor under section 7.4.8 of this 
appendix.
    7.4.11.2 The filter temperature measurement shall be updated at 
least every 30 seconds during both sampling and standby (non-sampling) 
modes of operation. A visual indication of the current (most recent) 
value of the filter temperature measurement, updated at least every 30 
seconds, shall be available to the sampler operator during both sampling 
and standby (non-sampling) modes of operation, as specified in table L-1 
of section 7.4.19 of this appendix.
    7.4.11.3 For sequential samplers, the temperature of each filter 
shall be measured individually unless it can be shown, as specified in 
the filter temperature measurement test described in Sec. 53.57 of this 
chapter, that the temperature of each filter can be represented by fewer 
temperature sensors.
    7.4.11.4 The sampler shall also provide a warning flag indicator 
following any occurrence in which the filter temperature (any filter 
temperature for sequential samplers) exceeds the ambient temperature by 
more than 5 [deg]C for more than 30 consecutive minutes during either 
the sampling or post-sampling periods of operation, as specified in 
table L-1 of section 7.4.19 of this appendix, under section 10.12 of 
this appendix, regarding sample validity when a warning flag occurs. It 
is further recommended (not required) that the sampler be capable of 
recording the maximum differential between the measured filter 
temperature and the ambient temperature and its time and date of 
occurrence during both sampling and post-sampling (non-sampling) modes 
of operation and providing for those data to be accessible to the 
sampler operator following the end of the sample period, as suggested in 
table L-1 of section 7.4.19 of this appendix.
    7.4.12 Clock/timer system.
    (a) The sampler shall have a programmable real-time clock timing/
control system that:
    (1) Is capable of maintaining local time and date, including year, 
month, day-of-month, hour, minute, and second to an accuracy of 1.0 minute per month.
    (2) Provides a visual indication of the current system time, 
including year, month, day-of-month, hour, and minute, updated at least 
each minute, for operator verification.
    (3) Provides appropriate operator controls for setting the correct 
local time and date.
    (4) Is capable of starting the sample collection period and sample 
air flow at a specific, operator-settable time and date, and stopping 
the sample air flow and terminating the sampler collection period 24 
hours (1440 minutes) later, or at a specific, operator-settable time and 
date.
    (b) These start and stop times shall be readily settable by the 
sampler operator to within 1.0 minute. The system 
shall provide a visual indication of the current start and stop time 
settings, readable to 1.0 minute, for verification 
by the operator, and the start and stop times shall also be available 
via the data output port, as specified in table L-1 of section 7.4.19 of 
this appendix. Upon execution of a programmed sample period start, the 
sampler shall automatically reset all sample period information and 
warning flag indications pertaining to a previous sample period. Refer 
also to section 7.4.15.4 of this appendix regarding retention of current 
date and time and programmed start and stop times during a temporary 
electrical power interruption.
    7.4.13 Sample time determination. The sampler shall be capable of 
determining the elapsed sample collection time for each PM2.5 
sample, accurate to within 1.0 minute, measured as 
the time between the start of the sampling period, under section 7.4.12 
of this appendix and the termination of the sample period, under section 
7.4.12 of this appendix or section 7.4.4 of this appendix. This elapsed 
sample time shall not include periods when the sampler is inoperative 
due to a temporary interruption of electrical power, under section 
7.4.15.4 of this appendix. In the event that the elapsed sample time 
determined for the sample period is not within the

[[Page 81]]

range specified for the required sample period in section 3.3 of this 
appendix, the sampler shall set a warning flag indicator. The date and 
time of the start of the sample period, the value of the elapsed sample 
time for the sample period, and the flag indicator status shall be 
available to the sampler operator following the end of the sample 
period, as specified in table L-1 of section 7.4.19 of this appendix.
    7.4.14 Outdoor environmental enclosure. The sampler shall have an 
outdoor enclosure (or enclosures) suitable to protect the filter and 
other non-weatherproof components of the sampler from precipitation, 
wind, dust, extremes of temperature and humidity; to help maintain 
temperature control of the filter (or filters, for sequential samplers); 
and to provide reasonable security for sampler components and settings.
    7.4.15 Electrical power supply.
    7.4.15.1 The sampler shall be operable and function as specified 
herein when operated on an electrical power supply voltage of 105 to 125 
volts AC (RMS) at a frequency of 59 to 61 Hz. Optional operation as 
specified at additional power supply voltages and/or frequencies shall 
not be precluded by this requirement.
    7.4.15.2 The design and construction of the sampler shall comply 
with all applicable National Electrical Code and Underwriters 
Laboratories electrical safety requirements.
    7.4.15.3 The design of all electrical and electronic controls shall 
be such as to provide reasonable resistance to interference or 
malfunction from ordinary or typical levels of stray electromagnetic 
fields (EMF) as may be found at various monitoring sites and from 
typical levels of electrical transients or electronic noise as may often 
or occasionally be present on various electrical power lines.
    7.4.15.4 In the event of temporary loss of electrical supply power 
to the sampler, the sampler shall not be required to sample or provide 
other specified functions during such loss of power, except that the 
internal clock/timer system shall maintain its local time and date 
setting within 1 minute per week, and the sampler 
shall retain all other time and programmable settings and all data 
required to be available to the sampler operator following each sample 
period for at least 7 days without electrical supply power. When 
electrical power is absent at the operator-set time for starting a 
sample period or is interrupted during a sample period, the sampler 
shall automatically start or resume sampling when electrical power is 
restored, if such restoration of power occurs before the operator-set 
stop time for the sample period.
    7.4.15.5 The sampler shall have the capability to record and retain 
a record of the year, month, day-of-month, hour, and minute of the start 
of each power interruption of more than 1 minute duration, up to 10 such 
power interruptions per sample period. (More than 10 such power 
interruptions shall invalidate the sample, except where an exceedance is 
measured, under section 3.3 of this appendix.) The sampler shall provide 
for these power interruption data to be available to the sampler 
operator following the end of the sample period, as specified in table 
L-1 of section 7.4.19 of this appendix.
    7.4.16 Control devices and operator interface. The sampler shall 
have mechanical, electrical, or electronic controls, control devices, 
electrical or electronic circuits as necessary to provide the timing, 
flow rate measurement and control, temperature control, data storage and 
computation, operator interface, and other functions specified. 
Operator-accessible controls, data displays, and interface devices shall 
be designed to be simple, straightforward, reliable, and easy to learn, 
read, and operate under field conditions. The sampler shall have 
provision for operator input and storage of up to 64 characters of 
numeric (or alphanumeric) data for purposes of site, sampler, and sample 
identification. This information shall be available to the sampler 
operator for verification and change and for output via the data output 
port along with other data following the end of a sample period, as 
specified in table L-1 of section 7.4.19 of this appendix. All data 
required to be available to the operator following a sample collection 
period or obtained during standby mode in a post-sampling period shall 
be retained by the sampler until reset, either manually by the operator 
or automatically by the sampler upon initiation of a new sample 
collection period.
    7.4.17 Data output port requirement. The sampler shall have a 
standard RS-232C data output connection through which digital data may 
be exported to an external data storage or transmission device. All 
information which is required to be available at the end of each sample 
period shall be accessible through this data output connection. The 
information that shall be accessible though this output port is 
summarized in table L-1 of section 7.4.19 of this appendix. Since no 
specific format for the output data is provided, the sampler 
manufacturer or vendor shall make available to sampler purchasers 
appropriate computer software capable of receiving exported sampler data 
and correctly translating the data into a standard spreadsheet format 
and optionally any other formats as may be useful to sampler users. This 
requirement shall not preclude the sampler from offering other types of 
output connections in addition to the required RS-232C port.
    7.4.18 Operation/instruction manual. The sampler shall include an 
associated comprehensive operation or instruction manual, as required by 
part 53 of this chapter, which includes detailed operating instructions 
on

[[Page 82]]

the setup, operation, calibration, and maintenance of the sampler. This 
manual shall provide complete and detailed descriptions of the 
operational and calibration procedures prescribed for field use of the 
sampler and all instruments utilized as part of this reference method. 
The manual shall include adequate warning of potential safety hazards 
that may result from normal use or malfunction of the method and a 
description of necessary safety precautions. The manual shall also 
include a clear description of all procedures pertaining to 
installation, operation, periodic and corrective maintenance, and 
troubleshooting, and shall include parts identification diagrams.
    7.4.19 Data reporting requirements. The various information that the 
sampler is required to provide and how it is to be provided is 
summarized in the following table L-1.

                                             Table L-1--Summary of Information To Be Provided By the Sampler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Availability                                        Format
                                    Appendix L section -------------------------------------------------------------------------------------------------
    Information to be provided          reference                        End of        Visual      Data output
                                                         Anytime \1\   period \2\    display \3\       \4\      Digital reading \5\         Units
--------------------------------------------------------------------------------------------------------------------------------------------------------
Flow rate, 30-second maximum       7.4.5.1............     [bcheck]   ............     [bcheck]             *   XX.X...............  L/min
 interval.
Flow rate, average for the sample  7.4.5.2............            *      [bcheck]             *      [bcheck]   XX.X...............  L/min
 period.
Flow rate, CV, for sample period.  7.4.5.2............            *      [bcheck]             *   [bcheck][msh  XX.X...............  %
                                                                                                         box]
Flow rate, 5-min. average out of   7.4.5.2............     [bcheck]      [bcheck]      [bcheck]   [bcheck][msh  On/Off.............  ...................
 spec. (FLAG \6\).                                                                                       box]
Sample volume, total.............  7.4.5.2............            *      [bcheck]      [bcheck]   [bcheck][msh  XX.X...............  m\3\
                                                                                                         box]
Temperature, ambient, 30-second    7.4.8..............     [bcheck]   ............     [bcheck]   ............  XX.X...............  [deg]C
 interval.
Temperature, ambient, min., max.,  7.4.8..............            *      [bcheck]      [bcheck]   [bcheck][msh  XX.X...............  [deg]C
 average for the sample period.                                                                          box]
Baro pressure, ambient, 30-second  7.4.9..............     [bcheck]   ............     [bcheck]   ............  XXX................  mm Hg
 interval.
Baro pressure, ambient, min.,      7.4.9..............            *      [bcheck]      [bcheck]   [bcheck][msh  XXX................  mm Hg
 max., average for the sample                                                                            box]
 period.
Filter temperature, 30-second      7.4.11.............     [bcheck]   ............     [bcheck]   ............  XX.X...............  [deg]C
 interval.
Filter temperature differential,   7.4.11.............            *      [bcheck]      [bcheck]   [bcheck][msh  On/Off.............  ...................
 30-second interval, out of spec.                                                                        box]
 (FLAG \6\).
Filter temperature, maximum        7.4.11.............            *             *             *             *   X.X, YY/MM/DD HH:mm  [deg]C, Yr./Mon./
 differential from ambient, date,                                                                                                     Day Hrs. min
 time of occurrence.
Date and time....................  7.4.12.............     [bcheck]   ............     [bcheck]   ............  YY/MM/DD HH:mm.....  Yr./Mon./Day Hrs.
                                                                                                                                      min
Sample start and stop time         7.4.12.............     [bcheck]      [bcheck]      [bcheck]      [bcheck]   YY/MM/DD HH:mm.....  Yr./Mon./Day Hrs.
 settings.                                                                                                                            min
Sample period start time.........  7.4.12.............  ............     [bcheck]      [bcheck]   [bcheck][msh  YYYY/MM/DD HH:mm...  Yr./Mon./Day Hrs.
                                                                                                         box]                         min
Elapsed sample time..............  7.4.13.............            *      [bcheck]      [bcheck]   [bcheck][msh  HH:mm..............  Hrs. min
                                                                                                         box]
Elapsed sample time, out of spec.  7.4.13.............  ............     [bcheck]      [bcheck]   [bcheck][msh  On/Off.............  ...................
 (FLAG \6\).                                                                                             box]

[[Page 83]]

 
Power interruptions <=1 min.,      7.4.15.5...........            *      [bcheck]             *      [bcheck]   1HH:mm, 2HH:mm, etc  Hrs. min
 start time of first 10.                                                                                         ....
User-entered information, such as  7.4.16.............     [bcheck]      [bcheck]      [bcheck]   [bcheck][msh  As entered.........  ...................
 sampler and site identification.                                                                        box]
--------------------------------------------------------------------------------------------------------------------------------------------------------
[bcheck] Provision of this information is required.
*Provision of this information is optional. If information related to the entire sample period is optionally provided prior to the end of the sample
  period, the value provided should be the value calculated for the portion of the sampler period completed up to the time the information is provided.
[mshbox] Indicates that this information is also required to be provided to the AIRS data bank; see Sec.  Sec.  58.26 and 58.35 of this chapter.
\1\ Information is required to be available to the operator at any time the sampler is operating, whether sampling or not.
\2\ Information relates to the entire sampler period and must be provided following the end of the sample period until reset manually by the operator or
  automatically by the sampler upon the start of a new sample period.
\3\ Information shall be available to the operator visually.
\4\ Information is to be available as digital data at the sampler's data output port specified in section 7.4.16 of this appendix following the end of
  the sample period until reset manually by the operator or automatically by the sampler upon the start of a new sample period.
\5\ Digital readings, both visual and data output, shall have not less than the number of significant digits and resolution specified.
\6\ Flag warnings may be displayed to the operator by a single-flag indicator or each flag may be displayed individually. Only a set (on) flag warning
  must be indicated; an off (unset) flag may be indicated by the absence of a flag warning. Sampler users should refer to section 10.12 of this appendix
  regarding the validity of samples for which the sampler provided an associated flag warning.

    8.0 Filter Weighing. See reference 2 in section 13.0 of this 
appendix, for additional, more detailed guidance.
    8.1 Analytical balance. The analytical balance used to weigh filters 
must be suitable for weighing the type and size of filters specified, 
under section 6.0 of this appendix, and have a readability of 1 [micro]g. The balance shall be calibrated as specified 
by the manufacturer at installation and recalibrated immediately prior 
to each weighing session. See reference 2 in section 13.0 of this 
appendix for additional guidance.
    8.2 Filter conditioning. All sample filters used shall be 
conditioned immediately before both the pre- and post-sampling weighings 
as specified below. See reference 2 in section 13.0 of this appendix for 
additional guidance.
    8.2.1 Mean temperature. 20 - 23 [deg]C.
    8.2.2 Temperature control. 2 [deg]C over 24 
hours.
    8.2.3 Mean humidity. Generally, 30-40 percent relative humidity; 
however, where it can be shown that the mean ambient relative humidity 
during sampling is less than 30 percent, conditioning is permissible at 
a mean relative humidity within 5 relative 
humidity percent of the mean ambient relative humidity during sampling, 
but not less than 20 percent.
    8.2.4 Humidity control. 5 relative humidity 
percent over 24 hours.
    8.2.5 Conditioning time. Not less than 24 hours.
    8.3 Weighing procedure.
    8.3.1 New filters should be placed in the conditioning environment 
immediately upon arrival and stored there until the pre-sampling 
weighing. See reference 2 in section 13.0 of this appendix for 
additional guidance.
    8.3.2 The analytical balance shall be located in the same controlled 
environment in which the filters are conditioned. The filters shall be 
weighed immediately following the conditioning period without 
intermediate or transient exposure to other conditions or environments.
    8.3.3 Filters must be conditioned at the same conditions (humidity 
within 5 relative humidity percent) before both 
the pre- and post-sampling weighings.
    8.3.4 Both the pre- and post-sampling weighings should be carried 
out on the same analytical balance, using an effective technique to 
neutralize static charges on the filter, under reference 2 in section 
13.0 of this appendix. If possible, both weighings should be carried out 
by the same analyst.
    8.3.5 The pre-sampling (tare) weighing shall be within 30 days of 
the sampling period.
    8.3.6 The post-sampling conditioning and weighing shall be completed 
within 240 hours (10 days) after the end of the sample period, unless 
the filter sample is maintained at 4 [deg]C or less during the entire 
time between retrieval from the sampler and the start of the 
conditioning, in which case the period shall not exceed 30 days. 
Reference 2 in section 13.0 of this appendix has additional guidance on 
transport of cooled filters.
    8.3.7 Filter blanks.

[[Page 84]]

    8.3.7.1 New field blank filters shall be weighed along with the pre-
sampling (tare) weighing of each lot of PM2.5 filters. These 
blank filters shall be transported to the sampling site, installed in 
the sampler, retrieved from the sampler without sampling, and reweighed 
as a quality control check.
    8.3.7.2 New laboratory blank filters shall be weighed along with the 
pre-sampling (tare) weighing of each set of PM2.5 filters. 
These laboratory blank filters should remain in the laboratory in 
protective containers during the field sampling and should be reweighed 
as a quality control check.
    8.3.8 Additional guidance for proper filter weighing and related 
quality assurance activities is provided in reference 2 in section 13.0 
of this appendix.
    9.0 Calibration. Reference 2 in section 13.0 of this appendix 
contains additional guidance.
    9.1 General requirements.
    9.1.1 Multipoint calibration and single-point verification of the 
sampler's flow rate measurement device must be performed periodically to 
establish and maintain traceability of subsequent flow measurements to a 
flow rate standard.
    9.1.2 An authoritative flow rate standard shall be used for 
calibrating or verifying the sampler's flow rate measurement device with 
an accuracy of 2 percent. The flow rate standard 
shall be a separate, stand-alone device designed to connect to the flow 
rate measurement adapter, Figure L-30 of this appendix. This flow rate 
standard must have its own certification and be traceable to a National 
Institute of Standards and Technology (NIST) primary standard for volume 
or flow rate. If adjustments to the sampler's flow rate measurement 
system calibration are to be made in conjunction with an audit of the 
sampler's flow measurement system, such adjustments shall be made 
following the audit. Reference 2 in section 13.0 of this appendix 
contains additional guidance.
    9.1.3 The sampler's flow rate measurement device shall be re-
calibrated after electromechanical maintenance or transport of the 
sampler.
    9.2 Flow rate calibration/verification procedure.
    9.2.1 PM2.5 samplers may employ various types of flow 
control and flow measurement devices. The specific procedure used for 
calibration or verification of the flow rate measurement device will 
vary depending on the type of flow rate controller and flow rate 
measurement employed. Calibration shall be in terms of actual ambient 
volumetric flow rates (Qa), measured at the sampler's inlet 
downtube. The generic procedure given here serves to illustrate the 
general steps involved in the calibration of a PM2.5 sampler. 
The sampler operation/instruction manual required under section 7.4.18 
of this appendix and the Quality Assurance Handbook in reference 2 in 
section 13.0 of this appendix provide more specific and detailed 
guidance for calibration.
    9.2.2 The flow rate standard used for flow rate calibration shall 
have its own certification and be traceable to a NIST primary standard 
for volume or flow rate. A calibration relationship for the flow rate 
standard, e.g., an equation, curve, or family of curves relating actual 
flow rate (Qa) to the flow rate indicator reading, shall be 
established that is accurate to within 2 percent over the expected range 
of ambient temperatures and pressures at which the flow rate standard 
may be used. The flow rate standard must be re-calibrated or re-verified 
at least annually.
    9.2.3 The sampler flow rate measurement device shall be calibrated 
or verified by removing the sampler inlet and connecting the flow rate 
standard to the sampler's downtube in accordance with the operation/
instruction manual, such that the flow rate standard accurately measures 
the sampler's flow rate. The sampler operator shall first carry out a 
sampler leak check and confirm that the sampler passes the leak test and 
then verify that no leaks exist between the flow rate standard and the 
sampler.
    9.2.4 The calibration relationship between the flow rate (in actual 
L/min) indicated by the flow rate standard and by the sampler's flow 
rate measurement device shall be established or verified in accordance 
with the sampler operation/instruction manual. Temperature and pressure 
corrections to the flow rate indicated by the flow rate standard may be 
required for certain types of flow rate standards. Calibration of the 
sampler's flow rate measurement device shall consist of at least three 
separate flow rate measurements (multipoint calibration) evenly spaced 
within the range of -10 percent to =10 percent of the sampler's 
operational flow rate, section 7.4.1 of this appendix. Verification of 
the sampler's flow rate shall consist of one flow rate measurement at 
the sampler's operational flow rate. The sampler operation/instruction 
manual and reference 2 in section 13.0 of this appendix provide 
additional guidance.
    9.2.5 If during a flow rate verification the reading of the 
sampler's flow rate indicator or measurement device differs by 4 percent or more from the flow rate measured by the 
flow rate standard, a new multipoint calibration shall be performed and 
the flow rate verification must then be repeated.
    9.2.6 Following the calibration or verification, the flow rate 
standard shall be removed from the sampler and the sampler inlet shall 
be reinstalled. Then the sampler's normal operating flow rate (in L/min) 
shall be determined with a clean filter in place. If the flow rate 
indicated by the sampler differs by 2 percent or 
more from the required sampler flow rate, the sampler flow rate must be 
adjusted to the required flow rate, under section 7.4.1 of this 
appendix.

[[Page 85]]

    9.3 Periodic calibration or verification of the calibration of the 
sampler's ambient temperature, filter temperature, and barometric 
pressure measurement systems is also required. Reference 3 of section 
13.0 of this appendix contains additional guidance.
    10.0 PM2.5 Measurement Procedure. The detailed procedure 
for obtaining valid PM2.5 measurements with each specific 
sampler designated as part of a reference method for PM2.5 
under part 53 of this chapter shall be provided in the sampler-specific 
operation or instruction manual required by section 7.4.18 of this 
appendix. Supplemental guidance is provided in section 2.12 of the 
Quality Assurance Handbook listed in reference 2 in section 13.0 of this 
appendix. The generic procedure given here serves to illustrate the 
general steps involved in the PM2.5 sample collection and 
measurement, using a PM2.5 reference method sampler.
    10.1 The sampler shall be set up, calibrated, and operated in 
accordance with the specific, detailed guidance provided in the specific 
sampler's operation or instruction manual and in accordance with a 
specific quality assurance program developed and established by the 
user, based on applicable supplementary guidance provided in reference 2 
in section 13.0 of this appendix.
    10.2 Each new sample filter shall be inspected for correct type and 
size and for pinholes, particles, and other imperfections. Unacceptable 
filters should be discarded. A unique identification number shall be 
assigned to each filter, and an information record shall be established 
for each filter. If the filter identification number is not or cannot be 
marked directly on the filter, alternative means, such as a number-
identified storage container, must be established to maintain positive 
filter identification.
    10.3 Each filter shall be conditioned in the conditioning 
environment in accordance with the requirements specified in section 8.2 
of this appendix.
    10.4 Following conditioning, each filter shall be weighed in 
accordance with the requirements specified in section 8.0 of this 
appendix and the presampling weight recorded with the filter 
identification number.
    10.5 A numbered and preweighed filter shall be installed in the 
sampler following the instructions provided in the sampler operation or 
instruction manual.
    10.6 The sampler shall be checked and prepared for sample collection 
in accordance with instructions provided in the sampler operation or 
instruction manual and with the specific quality assurance program 
established for the sampler by the user.
    10.7 The sampler's timer shall be set to start the sample collection 
at the beginning of the desired sample period and stop the sample 
collection 24 hours later.
    10.8 Information related to the sample collection (site location or 
identification number, sample date, filter identification number, and 
sampler model and serial number) shall be recorded and, if appropriate, 
entered into the sampler.
    10.9 The sampler shall be allowed to collect the PM2.5 
sample during the set 24-hour time period.
    10.10 Within 96 hours of the end of the sample collection period, 
the filter, while still contained in the filter cassette, shall be 
carefully removed from the sampler, following the procedure provided in 
the sampler operation or instruction manual and the quality assurance 
program, and placed in a protective container. The protective container 
shall contain no loose material that could be transferred to the filter. 
The protective container shall hold the filter cassette securely such 
that the cover shall not come in contact with the filter's surfaces. 
Reference 2 in section 13.0 of this appendix contains additional 
information.
    10.11 The total sample volume in actual m\3\ for the sampling period 
and the elapsed sample time shall be obtained from the sampler and 
recorded in accordance with the instructions provided in the sampler 
operation or instruction manual. All sampler warning flag indications 
and other information required by the local quality assurance program 
shall also be recorded.
    10.12 All factors related to the validity or representativeness of 
the sample, such as sampler tampering or malfunctions, unusual 
meteorological conditions, construction activity, fires or dust storms, 
etc. shall be recorded as required by the local quality assurance 
program. The occurrence of a flag warning during a sample period shall 
not necessarily indicate an invalid sample but rather shall indicate the 
need for specific review of the QC data by a quality assurance officer 
to determine sample validity.
    10.13 After retrieval from the sampler, the exposed filter 
containing the PM2.5 sample should be transported to the 
filter conditioning environment as soon as possible ideally to arrive at 
the conditioning environment within 24 hours for conditioning and 
subsequent weighing. During the period between filter retrieval from the 
sampler and the start of the conditioning, the filter shall be 
maintained as cool as practical and continuously protected from exposure 
to temperatures over 25 [deg]C. See section 8.3.6 of this appendix 
regarding time limits for completing the post-sampling weighing. See 
reference 2 in section 13.0 of this appendix for additional guidance on 
transporting filter samplers to the conditioning and weighing 
laboratory.
    10.14. The exposed filter containing the PM2.5 sample 
shall be re-conditioned in the conditioning environment in accordance 
with the requirements specified in section 8.2 of this appendix.

[[Page 86]]

    10.15. The filter shall be reweighed immediately after conditioning 
in accordance with the requirements specified in section 8.0 of this 
appendix, and the postsampling weight shall be recorded with the filter 
identification number.
    10.16 The PM2.5 concentration shall be calculated as 
specified in section 12.0 of this appendix.
    11.0 Sampler Maintenance. The sampler shall be maintained as 
described by the sampler's manufacturer in the sampler-specific 
operation or instruction manual required under section 7.4.18 of this 
appendix and in accordance with the specific quality assurance program 
developed and established by the user based on applicable supplementary 
guidance provided in reference 2 in section 13.0 of this appendix.
    12.0 Calculations
    12.1 (a) The PM2.5 concentration is calculated as:

PM2.5 = (Wf - Wi)/Va

where:

PM2.5 = mass concentration of PM2.5, [micro]g/
m\3\;
Wf, Wi = final and initial weights, respectively, 
of the filter used to collect the PM2.5 particle sample, 
[micro]g;
Va = total air volume sampled in actual volume units, as 
provided by the sampler, m\3\.

    Note: Total sample time must be between 1,380 and 1,500 minutes (23 
and 25 hrs) for a fully valid PM2.5 sample; however, see also 
section 3.3 of this appendix.
    13.0 References.
    1. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume I, Principles. EPA/600/R-94/038a, April 1994. Available from 
CERI, ORD Publications, U.S. Environmental Protection Agency, 26 West 
Martin Luther King Drive, Cincinnati, Ohio 45268.
    2. Copies of section 2.12 of the Quality Assurance Handbook for Air 
Pollution Measurement Systems, Volume II, Ambient Air Specific Methods, 
EPA/600/R-94/038b, are available from Department E (MD-77B), U.S. EPA, 
Research Triangle Park, NC 27711.
    3. Quality Assurance Handbook for Air Pollution Measurement Systems, 
Volume IV: Meteorological Measurements, (Revised Edition) EPA/600/R-94/
038d, March, 1995. Available from CERI, ORD Publications, U.S. 
Environmental Protection Agency, 26 West Martin Luther King Drive, 
Cincinnati, Ohio 45268.
    4. Military standard specification (mil. spec.) 8625F, Type II, 
Class 1 as listed in Department of Defense Index of Specifications and 
Standards (DODISS), available from DODSSP-Customer Service, 
Standardization Documents Order Desk, 700 Robbins Avenue, Building 4D, 
Philadelphia, PA 1911-5094.
    14.0 Figures L-1 through L-30 to Appendix L.

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[62 FR 38714, July 18, 1997, as amended at 64 FR 19719, Apr. 22, 1999]

[[Page 117]]

                    Appendix M to Part 50 [Reserved]

   Appendix N to Part 50--Interpretation of the National Ambient Air 
                 Quality Standards for PM2.5

    1.0 General.
    (a) This appendix explains the data handling conventions and 
computations necessary for determining when the annual and 24-hour 
primary and secondary national ambient air quality standards for PM 
specified in Sec. 50.7 of this part are met. Particulate matter is 
measured in the ambient air as PM2.5 (particles with an 
aerodynamic diameter less than or equal to a nominal 2.5 micrometers) by 
a reference method based on appendix L of this part, as applicable, and 
designated in accordance with part 53 of this chapter, or by an 
equivalent method designated in accordance with part 53 of this chapter. 
Data handling and computation procedures to be used in making 
comparisons between reported PM2.5 concentrations and the 
levels of the PM standards are specified in the following sections.
    (b) Data resulting from uncontrollable or natural events, for 
example structural fires or high winds, may require special 
consideration. In some cases, it may be appropriate to exclude these 
data because they could result in inappropriate values to compare with 
the levels of the PM standards. In other cases, it may be more 
appropriate to retain the data for comparison with the level of the PM 
standards and then allow the EPA to formulate the appropriate regulatory 
response. Whether to exclude, retain, or make adjustments to the data 
affected by uncontrollable or natural events is subject to the approval 
of the appropriate Regional Administrator.
    (c) The terms used in this appendix are defined as follows:
    Average and mean refer to an arithmetic mean.
    Daily value for PM refers to the 24-hour average concentration of 
PM2.5 calculated or measured from midnight to midnight (local 
time).
    Designated monitors are those monitoring sites designated in a State 
PM Monitoring Network Description for spatial averaging in areas opting 
for spatial averaging in accordance with part 58 of this chapter.
    98th percentile means the daily value out of a year of 
PM2.5 monitoring data below which 98 percent of all values in 
the group fall.
    Year refers to a calendar year.
    (d) Sections 2.1 and 2.5 of this appendix contain data handling 
instructions for the option of using a spatially averaged network of 
monitors for the annual standard. If spatial averaging is not considered 
for an area, then the spatial average is equivalent to the annual 
average of a single site and is treated accordingly in subsequent 
calculations. For example, paragraph (a)(3) of section 2.1 of this 
appendix could be eliminated since the spatial average would be 
equivalent to the annual average.
    2.0 Comparisons with the PM2.5 Standards.
    2.1 Annual PM2.5 Standard.
    (a) The annual PM2.5 standard is met when the 3-year 
average of the spatially averaged annual means is less than or equal to 
15.0 [micro]g/m\3\. The 3-year average of the spatially averaged annual 
means is determined by averaging quarterly means at each monitor to 
obtain the annual mean PM2.5 concentrations at each monitor, 
then averaging across all designated monitors, and finally averaging for 
3 consecutive years. The steps can be summarized as follows:
    (1) Average 24-hour measurements to obtain quarterly means at each 
monitor.
    (2) Average quarterly means to obtain annual means at each monitor.
    (3) Average across designated monitoring sites to obtain an annual 
spatial mean for an area (this can be one site in which case the spatial 
mean is equal to the annual mean).
    (4) Average 3 years of annual spatial means to obtain a 3-year 
average of spatially averaged annual means.
    (b) In the case of spatial averaging, 3 years of spatial averages 
are required to demonstrate that the standard has been met. Designated 
sites with less than 3 years of data shall be included in spatial 
averages for those years that data completeness requirements are met. 
For the annual PM2.5 standard, a year meets data completeness 
requirements when at least 75 percent of the scheduled sampling days for 
each quarter have valid data. However, years with high concentrations 
and more than a minimal amount of data (at least 11 samples in each 
quarter) shall not be ignored just because they are comprised of 
quarters with less than complete data. Thus, in computing annual 
spatially averaged means, years containing quarters with at least 11 
samples but less than 75 percent data completeness shall be included in 
the computation if the resulting spatially averaged annual mean 
concentration (rounded according to the conventions of section 2.3 of 
this appendix) is greater than the level of the standard.
    (c) Situations may arise in which there are compelling reasons to 
retain years containing quarters which do not meet the data completeness 
requirement of 75 percent or the minimum number of 11 samples. The use 
of less than complete data is subject to the approval of the appropriate 
Regional Administrator.
    (d) The equations for calculating the 3-year average annual mean of 
the PM2.5 standard are given in section 2.5 of this appendix.
    2.2 24-Hour PM2.5 Standard.
    (a) The 24-hour PM2.5 standard is met when the 3-year 
average of the 98th percentile values at each monitoring site 
is less than or

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equal to 65 [micro]g/m\3\. This comparison shall be based on 3 
consecutive, complete years of air quality data. A year meets data 
completeness requirements when at least 75 percent of the scheduled 
sampling days for each quarter have valid data. However, years with high 
concentrations shall not be ignored just because they are comprised of 
quarters with less than complete data. Thus, in computing the 3-year 
average 98th percentile value, years containing quarters with 
less than 75 percent data completeness shall be included in the 
computation if the annual 98th percentile value (rounded 
according to the conventions of section 2.3 of this appendix) is greater 
than the level of the standard.
    (b) Situations may arise in which there are compelling reasons to 
retain years containing quarters which do not meet the data completeness 
requirement. The use of less than complete data is subject to the 
approval of the appropriate Regional Administrator.
    (c) The equations for calculating the 3-year average of the annual 
98th percentile values is given in section 2.6 of this 
appendix.
    2.3 Rounding Conventions. For the purposes of comparing calculated 
values to the applicable level of the standard, it is necessary to round 
the final results of the calculations described in sections 2.5 and 2.6 
of this appendix. For the annual PM2.5 standard, the 3-year 
average of the spatially averaged annual means shall be rounded to the 
nearest 0.1 [micro]g/m\3\ (decimals 0.05 and greater are rounded up to 
the next 0.1, and any decimal lower than 0.05 is rounded down to the 
nearest 0.1). For the 24-hour PM2.5 standard, the 3-year 
average of the annual 98th percentile values shall be rounded 
to the nearest 1 [micro]g/m\3\ (decimals 0.5 and greater are rounded up 
to nearest whole number, and any decimal lower than 0.5 is rounded down 
to the nearest whole number).
    2.4 Monitoring Considerations.
    (a) Section 58.13 of this chapter specifies the required minimum 
frequency of sampling for PM2.5. Exceptions to the specified 
sampling frequencies, such as a reduced frequency during a season of 
expected low concentrations, are subject to the approval of the 
appropriate Regional Administrator. Section 58.14 of 40 CFR part 58 and 
section 2.8 of appendix D of 40 CFR part 58, specify which monitors are 
eligible for making comparisons with the PM standards. In determining a 
spatial mean using two or more monitoring sites operating in a given 
year, the annual mean for an individual site may be included in the 
spatial mean if and only if the mean for that site meets the criterion 
specified in Sec. 2.8 of appendix D of 40 CFR part 58. In the event 
data from an otherwise eligible site is excluded from being averaged 
with data from other sites on the basis of this criterion, then the 3-
year mean from that site shall be compared directly to the annual 
standard.
    (b) For the annual PM2.5 standard, when designated 
monitors are located at the same site and are reporting PM2.5 
values for the same time periods, and when spatial averaging has been 
chosen, their concentrations shall be averaged before an area-wide 
spatial average is calculated. Such monitors will then be considered as 
one monitor.
    2.5 Equations for the Annual PM2.5 Standard.
    (a) An annual mean value for PM2.5 is determined by first 
averaging the daily values of a calendar quarter:

                               Equation 1
[GRAPHIC] [TIFF OMITTED] TR18JY97.000

where:

xq,y,s = the mean for quarter q of year y for site s;
nq = the number of monitored values in the quarter; and
xi,q,y,s = the ith value in quarter q for year y 
for site s.

    (b) The following equation is then to be used for calculation of the 
annual mean:

                               Equation 2
[GRAPHIC] [TIFF OMITTED] TR18JY97.001

where:

xy,s = the annual mean concentration for year y (y = 1, 2, or 
3) and for site s; and
xq,y,s = the mean for quarter q of year y for site s.

    (c)(1) The spatially averaged annual mean for year y is computed by 
first calculating the annual mean for each site designated to be 
included in a spatial average, xy,s, and then computing the 
average of these values across sites:

                               Equation 3
[GRAPHIC] [TIFF OMITTED] TR18JY97.002

where:

xy = the spatially averaged mean for year y;
xy,s = the annual mean for year y and site s; and
ns = the number of sites designated to be averaged.

    (2) In the event that an area designated for spatial averaging has 
two or more sites at the same location producing data for the

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same time periods, the sites are averaged together before using Equation 
3 by:

                               Equation 4
[GRAPHIC] [TIFF OMITTED] TR18JY97.003

where:

xy,s* = the annual mean for year y for the sites at the same 
location (which will now be considered one site);
nc = the number of sites at the same location designated to 
be included in the spatial average; and
xy,s = the annual mean for year y and site s.

    (d) The 3-year average of the spatially averaged annual means is 
calculated by using the following equation:

                               Equation 5
[GRAPHIC] [TIFF OMITTED] TR18JY97.004

where:

x = the 3-year average of the spatially averaged annual means; and
xy = the spatially averaged annual mean for year y.

Example 1--Area Designated for Spatial Averaging That Meets the Primary 
                    Annual PM2.5 Standard.

    a. In an area designated for spatial averaging, four designated 
monitors recorded data in at least 1 year of a particular 3-year period. 
Using Equations 1 and 2, the annual means for PM2.5 at each 
site are calculated for each year. The following table can be created 
from the results. Data completeness percentages for the quarter with the 
fewest number of samples are also shown.

                                                         Table 1--Results from Equations 1 and 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Site          Site          Site          Site
                                                                                      [bottom]1     [bottom]2     [bottom]3     [bottom]4   Spatial mean
--------------------------------------------------------------------------------------------------------------------------------------------------------
Year 1.........................................  Annual mean ([micro]g/m\3\)......          12.7  ............  ............  ............         12.7
                                                 % data completeness..............          80             0             0             0    ............
Year 2.........................................  Annual mean ([micro]g/m\3\)......          12.6          17.5          15.2  ............         15.05
                                                 % data completeness..............          90            63            38             0    ............
Year 3.........................................  Annual mean ([micro]g/m\3\)......          12.5          18.5          14.1          16.9         15.50
                                                 % data completeness..............          90            80            85            50    ............
3-year mean....................................  .................................  ............  ............  ............  ............         14.42
--------------------------------------------------------------------------------------------------------------------------------------------------------

    b. The data from these sites are averaged in the order described in 
section 2.1 of this appendix. Note that the annual mean from site 
3 in year 2 and the annual mean from site 4 in year 3 
do not meet the 75 percent data completeness criteria. Assuming the 38 
percent data completeness represents a quarter with fewer than 11 
samples, site 3 in year 2 does not meet the minimum data 
completeness requirement of 11 samples in each quarter. The site is 
therefore excluded from the calculation of the spatial mean for year 2. 
However, since the spatial mean for year 3 is above the level of the 
standard and the minimum data requirement of 11 samples in each quarter 
has been met, the annual mean from site 4 in year 3 is included 
in the calculation of the spatial mean for year 3 and in the calculation 
of the 3-year average. The 3-year average is rounded to 14.4 [micro]g/
m\3\, indicating that this area meets the annual PM2.5 
standard.

 Example 2--Area With Two Monitors at the Same Location That Meets the 
                Primary Annual PM2.5 Standard.

    a. In an area designated for spatial averaging, six designated 
monitors, with two monitors at the same location (5 and 
6), recorded data in a particular 3-year period. Using 
Equations 1 and 2, the annual means for PM2.5 are calculated 
for each year. The following table can be created from the results.

                                                         Table 2--Results From Equations 1 and 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                  Average of
                                                        Site         Site         Site         Site         Site         Site      [bottom]5    Spatial
            Annual mean ([micro]g/m\3\)              [bottom]1    [bottom]2    [bottom]3    [bottom]4    [bottom]5    [bottom]6       and        mean
                                                                                                                                   [bottom]6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Year 1............................................         12.9          9.9         12.6         11.1         14.5         14.6       14.55       12.21
Year 2............................................         14.5         13.3         12.2         10.9         16.1         16.0       16.05       13.39
Year 3............................................         14.4         12.4         11.5          9.7         12.3         12.1       12.20       12.04
3-Year mean.......................................  ...........  ...........  ...........  ...........  ...........  ...........  ..........       12.55
--------------------------------------------------------------------------------------------------------------------------------------------------------


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    b. The annual means for sites 5 and 6 are averaged 
together using Equation 4 before the spatial average is calculated using 
Equation 3 since they are in the same location. The 3-year mean is 
rounded to 12.6 [micro]g/m\3\, indicating that this area meets the 
annual PM2.5 standard.

  Example 3--Area With a Single Monitor That Meets the Primary Annual 
                       PM2.5 Standard.

    a. Given data from a single monitor in an area, the calculations are 
as follows. Using Equations 1 and 2, the annual means for 
PM2.5 are calculated for each year. If the annual means are 
10.28, 17.38, and 12.25 [micro]g/m\3\, then the 3-year mean is:
[GRAPHIC] [TIFF OMITTED] TR18JY97.005

    b. This value is rounded to 13.3, indicating that this area meets 
the annual PM2.5 standard.
    2.6 Equations for the 24-Hour PM2.5 Standard.
    (a) When the data for a particular site and year meet the data 
completeness requirements in section 2.2 of this appendix, calculation 
of the 98th percentile is accomplished by the following 
steps. All the daily values from a particular site and year comprise a 
series of values (x1, x2, x3, ..., 
xn), that can be sorted into a series where each number is 
equal to or larger than the preceding number (x[1], 
x[2], x[3], ..., x[n]). In this case, 
x[1] is the smallest number and x[n] is the 
largest value. The 98th percentile is found from the sorted 
series of daily values which is ordered from the lowest to the highest 
number. Compute (0.98) x (n) as the number ``i.d'', where ``i'' is the 
integer part of the result and ``d'' is the decimal part of the result. 
The 98th percentile value for year y, P0.98, y, is 
given by Equation 6:

                               Equation 6
[GRAPHIC] [TIFF OMITTED] TR18JY97.006

where:

P0.98,y = 98th percentile for year y;
x[i=1] = the (i=1)th number in the ordered series 
of numbers; and
i = the integer part of the product of 0.98 and n.

    (b) The 3-year average 98th percentile is then calculated 
by averaging the annual 98th percentiles:

                               Equation 7
[GRAPHIC] [TIFF OMITTED] TR18JY97.007

    (c) The 3-year average 98th percentile is rounded 
according to the conventions in section 2.3 of this appendix before a 
comparison with the standard is made.

 Example 4--Ambient Monitoring Site With Every-Day Sampling That Meets 
             the Primary 24-Hour PM2.5 Standard.

    a. In each year of a particular 3 year period, varying numbers of 
daily PM2.5 values (e.g., 281, 304, and 296) out of a 
possible 365 values were recorded at a particular site with the 
following ranked values (in [micro]g/m\3\):

                                  Table 3--Ordered Monitoring Data For 3 Years
----------------------------------------------------------------------------------------------------------------
               Year 1                                Year 2                                Year 3
----------------------------------------------------------------------------------------------------------------
      j rank            Xj value            j rank            Xj value            j rank            Xj value
----------------------------------------------------------------------------------------------------------------
           275               57.9                296               54.3                290               66.0
           276               59.0                297               57.1                291               68.4
           277               62.2                298               63.0                292               69.8
----------------------------------------------------------------------------------------------------------------

    b. Using Equation 6, the 98th percentile values for each 
year are calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR18JY97.008


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[GRAPHIC] [TIFF OMITTED] TR18JY97.009

[GRAPHIC] [TIFF OMITTED] TR18JY97.010

    c.1. Using Equation 7, the 3-year average 98th percentile 
is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR18JY97.011

    2. Therefore, this site meets the 24-hour PM2.5 standard.

[62 FR 38755, July 18, 1997, as amended at 69 FR 45595, July 30, 2004]



PART 51_REQUIREMENTS FOR PREPARATION, ADOPTION, AND SUBMITTAL OF 
IMPLEMENTATION PLANS--Table of Contents




Sec.

           Subpart A_Emission Inventory Reporting Requirements

               General Information for Inventory Preparers

51.1 Who is responsible for actions described in this subpart?
51.5 What tools are available to help prepare and report emissions data?
51.10 How does my State report emissions that are required by the 
          NOX SIP Call?

                     Specific Reporting Requirements

51.15 What data does my State need to report to EPA?
51.20 What are the emission thresholds that separate point and area 
          sources?
51.25 What geographic area must my State's inventory cover?
51.30 When does my State report the data to EPA?
51.35 How can my State equalize the effort for annual reporting?
51.40 In what form should my State report the data to EPA?
51.45 Where should my State report the data?

Appendix A to Subpart A of Part 51--Tables and Glossary
Appendix B to Subpart A of Part 51 [Reserved]

Subparts B-E [Reserved]

                    Subpart F_Procedural Requirements

51.100 Definitions.
51.101 Stipulations.
51.102 Public hearings.
51.103 Submission of plans, preliminary review of plans.
51.104 Revisions.
51.105 Approval of plans.

                       Subpart G_Control Strategy

51.110 Attainment and maintenance of national standards.
51.111 Description of control measures.
51.112 Demonstration of adequacy.
51.113 [Reserved]
51.114 Emissions data and projections.
51.115 Air quality data and projections.
51.116 Data availability.
51.117 Additional provisions for lead.
51.118 Stack height provisions.
51.119 Intermittent control systems.
51.120 Requirements for State Implementation Plan revisions relating to 
          new motor vehicles.
51.121 Findings and requirements for submission of State implementation 
          plan revisions relating to emissions of oxides of nitrogen.
51.122 Emissions reporting requirements for SIP revisions relating to 
          budgets for NOX emissions.
51.123 Findings and requirements for submission of State implementation 
          plan revisions relating to emissions of oxides of nitrogen 
          pursuant to the Clean Air Interstate Rule.
51.124 Findings and requirements for submission of State implementation 
          plan revisions relating to emissions of sulfur dioxide 
          pursuant to the Clean Air Interstate Rule.
51.125 Emissions reporting requirements for SIP revisions relating to 
          budgets for SO2 and NOX emissions.

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        Subpart H_Prevention of Air Pollution Emergency Episodes

51.150 Classification of regions for episode plans.
51.151 Significant harm levels.
51.152 Contingency plans.
51.153 Reevaluation of episode plans.

            Subpart I_Review of New Sources and Modifications

51.160 Legally enforceable procedures.
51.161 Public availability of information.
51.162 Identification of responsible agency.
51.163 Administrative procedures.
51.164 Stack height procedures.
51.165 Permit requirements.
51.166 Prevention of significant deterioration of air quality.

               Subpart J_Ambient Air Quality Surveillance

51.190 Ambient air quality monitoring requirements.

                      Subpart K_Source Survelliance

51.210 General.
51.211 Emission reports and recordkeeping.
51.212 Testing, inspection, enforcement, and complaints.
51.213 Transportation control measures.
51.214 Continuous emission monitoring.

                        Subpart L_Legal Authority

51.230 Requirements for all plans.
51.231 Identification of legal authority.
51.232 Assignment of legal authority to local agencies.

                Subpart M_Intergovernmental Consultation

                           Agency Designation

51.240 General plan requirements.
51.241 Nonattainment areas for carbon monoxide and ozone.
51.242 [Reserved]

                     Subpart N_Compliance Schedules

51.260 Legally enforceable compliance schedules.
51.261 Final compliance schedules.
51.262 Extension beyond one year.

            Subpart O_Miscellaneous Plan Content Requirements

51.280 Resources.
51.281 Copies of rules and regulations.
51.285 Public notification.
51.286 Electronic reporting.

                   Subpart P_Protection of Visibility

51.300 Purpose and applicability.
51.301 Definitions.
51.302 Implementation control strategies for reasonably attributable 
          visibility impairment.
51.303 Exemptions from control.
51.304 Identification of integral vistas.
51.305 Monitoring for reasonably attributable visibility impairment.
51.306 Long-term strategy requirements for reasonably attributable 
          visibility impairment.
51.307 New source review.
51.308 Regional haze program requirements.
51.309 Requirements related to the Grand Canyon Visibility Transport 
          Commission.

                            Subpart Q_Reports

                       Air Quality Data Reporting

51.320 Annual air quality data report.

               Source Emissions and State Action Reporting

51.321 Annual source emissions and State action report.
51.322 Sources subject to emissions reporting.
51.323 Reportable emissions data and information.
51.324 Progress in plan enforcement.
51.326 Reportable revisions.
51.327 Enforcement orders and other State actions.
51.328 [Reserved]

                          Subpart R_Extensions

51.341 Request for 18-month extension.

          Subpart S_Inspection/Maintenance Program Requirements

51.350 Applicability.
51.351 Enhanced I/M performance standard.
51.352 Basic I/M performance standard.
51.353 Network type and program evaluation.
51.354 Adequate tools and resources.
51.355 Test frequency and convenience.
51.356 Vehicle coverage.
51.357 Test procedures and standards.
51.358 Test equipment.
51.359 Quality control.
51.360 Waivers and compliance via diagnostic inspection.
51.361 Motorist compliance enforcement.
51.362 Motorist compliance enforcement program oversight.
51.363 Quality assurance.
51.364 Enforcement against contractors, stations and inspectors.
51.365 Data collection.
51.366 Data analysis and reporting.

[[Page 123]]

51.367 Inspector training and licensing or certification.
51.368 Public information and consumer protection.
51.369 Improving repair effectiveness.
51.370 Compliance with recall notices.
51.371 On-road testing.
51.372 State Implementation Plan submissions.
51.373 Implementation deadlines.

Appendix A to Subpart S--Calibrations, Adjustments and Quality Control
Appendix B to Subpart S--Test Procedures
Appendix C to Subpart S--Steady-State Short Test Standards
Appendix D to Subpart S--Steady-State Short Test Equipment
Appendix E to Subpart S--Transient Test Driving Cycle

    Subpart T_Conformity to State or Federal Implementation Plans of 
   Transportation Plans, Programs, and Projects Developed, Funded or 
       Approved Under Title 23 U.S.C. or the Federal Transit Laws

51.390 Implementation plan revision.

                  Subpart U_Economic Incentive Programs

51.490 Applicability.
51.491 Definitions.
51.492 State program election and submittal.
51.493 State program requirements.
51.494 Use of program revenues.

Subpart W_Determining Conformity of General Federal Actions to State or 
                      Federal Implementation Plans

51.850 Prohibition.
51.851 State Implementation Plan (SIP) revision.
51.852 Definitions.
51.853 Applicability.
51.854 Conformity analysis.
51.855 Reporting requirements.
51.856 Public participation.
51.857 Frequency of conformity determinations.
51.858 Criteria for determining conformity of general Federal actions.
51.859 Procedures for conformity determinations of general Federal 
          actions.
51.860 Mitigation of air quality impacts.

Subpart X_Provisions for Implementation of 8-hour Ozone National Ambient 
                          Air Quality Standard

51.900 Definitions.
51.901 Applicability of part 51.
51.902 Which classification and area planning provisions of the CAA 
          shall apply to areas designated nonattainment for the 8-hour 
          NAAQS?
51.903 How do the classification and attainment date provisions in 
          section 181 of subpart 2 of the CAA apply to areas subject to 
          Sec. 51.902(a)?
51.904 How do the classification and attainment date provisions in 
          section 172(a) of subpart 1 of the CAA apply to areas subject 
          to Sec. 51.902(b)?
51.905 How do areas transition from the 1-hour NAAQS to the 8-hour NAAQS 
          and what are the anti-backsliding provisions?
51.906 Redesignation to nonattainment following initial designations for 
          the 8-hour NAAQS.
51.907 For an area that fails to attain the 8-hour NAAQS by its 
          attainment date, how does EPA interpret sections 
          172(a)(2)(C)(ii) and 181(a)(5)(B) of the CAA?
51.908 What modeling and attainment demonstration requirements apply for 
          purposes of the 8-hour ozone NAAQS?
51.909 [Reserved]
51.910 What requirements for reasonable further progress (RFP) under 
          sections 172(c)(2) and 182 apply for areas designated 
          nonattainment for the 8-hour ozone NAAQS?
51.911 [Reserved]
51.912 What requirements apply for reasonably available control 
          technology (RACT) and reasonably available control measures 
          (RACM) under the 8-hour NAAQS?
51.913 How do the section 182(f) NOX exemption provisions 
          apply for the 8-hour NAAQS?
51.914 What new source review requirements apply for 8-hour ozone 
          nonattainment areas?
51.915 What emissions inventory requirements apply under the 8-hour 
          NAAQS?
51.916 What are the requirements for an Ozone Transport Region under the 
          8-hour NAAQS?
51.917 What is the effective date of designation for the Las Vegas, NV, 
          8-hour ozone nonattainment area?
51.918 Can any SIP planning requirements be suspended in 8-hour ozone 
          nonattainment areas that have air quality data that meets the 
          NAAQS?

Appendixes A-K to Part 51 [Reserved]
Appendix L to Part 51--Example Regulations for Prevention of Air 
          Pollution Emergency Episodes
Appendix M to Part 51--Recommended Test Methods for State Implementation 
          Plans
Appendixes N-O to Part 51 [Reserved]
Appendix P to Part 51--Minimum Emission Monitoring Requirements
Appendixes Q-R to Part 51 [Reserved]
Appendix S to Part 51--Emission Offset Interpretative Ruling

[[Page 124]]

Appendixes T-U to Part 51 [Reserved]
Appendix V to Part 51--Criteria for Determining the Completeness of Plan 
          Submissions
Appendix W to Part 51--Guideline on Air Quality Models
Appendix X to Part 51--Examples of Economic Incentive Programs
Appendix Y to Part 51--Guidelines for BART Determinations Under the 
          Regional Haze Rule

    Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q.

    Source: 36 FR 22398, Nov. 25, 1971, unless otherwise noted.



           Subpart A_Emission Inventory Reporting Requirements

    Source: 67 FR 39611, June 10, 2002, unless otherwise noted.

               General Information for Inventory Preparers



Sec. 51.1  Who is responsible for actions described in this subpart?

    State agencies whose geographic coverage include any point, area, 
mobile, or biogenic sources must inventory these sources and report this 
information to EPA.



Sec. 51.5  What tools are available to help prepare and report emissions 
data?

    We urge your State to use estimation procedures described in 
documents from the Emission Inventory Improvement Program (EIIP). These 
procedures are standardized and ranked according to relative uncertainty 
for each emission estimating technique. Using this guidance will enable 
others to use your State's data and evaluate its quality and consistency 
with other data.



Sec. 51.10  How does my State report emissions that are required by the 
NOX SIP Call?

    The States and the District of Columbia that are subject to the 
NOX SIP Call (Sec. 51.121) should report their emissions 
under the provisions of Sec. 51.122. To avoid confusion, these 
requirements are not repeated here.

                     Specific Reporting Requirements



Sec. 51.15  What data does my State need to report to EPA?

    (a) Pollutants. Report actual emissions of the following (see 
Glossary to Appendix A to this subpart for precise definitions as 
required):
    (1) Required Pollutants:
    (i) Sulfur oxides.
    (ii) VOC.
    (iii) Nitrogen oxides.
    (iv) Carbon monoxide.
    (v) Lead and lead compounds.
    (vi) Primary PM2.5.
    (vii) Primary PM10.
    (viii) NH3.
    (2) Optional Pollutant:
    (i) Primary PM.
    (ii) [Reserved]
    (b) Sources. Emissions should be reported from the following 
sources:
    (1) Point.
    (2) Area.
    (3) Onroad mobile.
    (4) Nonroad mobile.
    (5) Biogenic.
    (c) Supporting information. Report the data elements in Tables 2a 
through 2d of Appendix A to this subpart. Depending on the format you 
choose to report your State data, additional information not listed in 
Tables 2a through 2d will be required. We may ask you for other data on 
a voluntary basis to meet special purposes.
    (d) Confidential data. We don't consider the data in Tables 2a 
through 2d of Appendix A to this subpart confidential, but some States 
limit release of this type of data. Any data that you submit to EPA 
under this rule will be considered in the public domain and cannot be 
treated as confidential. If Federal and State requirements are 
inconsistent, consult your EPA Regional Office for a final 
reconciliation.



Sec. 51.20  What are the emission thresholds that separate point and 
area sources?

    (a) All anthropogenic stationary sources must be included in your 
inventory as either point or area sources.
    (b) See Table 1 of Appendix A to this subpart for minimum reporting 
thresholds on point sources.
    (c) Your State has two alternatives to the point source reporting 
thresholds in paragraph (b) of this section:

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    (1) You may choose to define point sources by the definition of a 
major source used under CAA Title V, see 40 CFR 70.2.
    (2) If your State has lower emission reporting thresholds for point 
sources than paragraph (b) of this section, then you may use these in 
reporting your emissions to EPA.
    (d) All stationary sources that have actual emissions lower than the 
thresholds specified in paragraphs (b) and (c) of this section, should 
be reported as area sources.



Sec. 51.25  What geographic area must my State's inventory cover?

    Because of the regional nature of these pollutants, your State's 
inventory must be statewide, regardless of an area's attainment status.



Sec. 51.30  When does my State report the data to EPA?

    Your State is required to report two basic types of emission 
inventories to us: Annual Cycle Inventory; and Three-year Cycle 
Inventory.
    (a) Annual cycle. You are required to report annually data from Type 
A (large) point sources. Except as provided in paragraph (e) of this 
section, the first annual cycle inventory will be for the year 2001 and 
must be submitted to us within 17 months, i.e., by June 1, 2003. 
Subsequent annual cycle inventories will be due 17 months following the 
end of the reporting year. See Table 2a of Appendix A to this subpart 
for the specific data elements to report annually.
    (b) Three-year cycle. You are required to report triennially, data 
for Type B (all) point sources, area sources and mobile sources. Except 
as provided in paragraph (e) of this section, the first three-year cycle 
inventory will be for the year 2002 and must be submitted to us within 
17 months, i.e., by June 1, 2004. Subsequent three-year cycle 
inventories will be due 17 months following the end of the reporting 
year. See Tables 2a, 2b and 2c of Appendix A to this subpart for the 
specific data elements that must be reported triennially.
    (c) NOX SIP call. There are specific annual and three-
year reporting requirements for States subject to the NOX SIP 
call. See Sec. 51.122 for these requirements.
    (d) Biogenic emissions. Biogenic emissions are part of your 3-year 
cycle inventory. Your State must establish an initial baseline for 
biogenic emissions that is due as specified under paragraph (b) of this 
section. Your State need not submit more biogenic data unless land use 
characteristics or the methods for estimating emissions change 
substantially. If either of these changes, your State must report the 
biogenic emission data elements shown in Table 2d of Appendix A to this 
subpart. Report these data elements 17 months after the end of the 
reporting year.
    (e) Point Sources. States must commence reporting point source 
emissions of PM2.5 and NH3 on June 1, 2004 unless 
that date is less than 60 days after EPA publishes an approved 
Information Collection Request (ICR) addressing this section of the 
rule. If EPA fails to publish an approved ICR 60 days in advance of June 
1, 2004, States must commence reporting point source emissions of 
PM2.5 and NH3 on the next annual or triennial 
reporting date (as appropriate) that is at least 60 days after EPA 
publishes an approved ICR addressing this section.



Sec. 51.35  How can my State equalize the effort for annual reporting?

    (a) Compiling a 3-year cycle inventory means much more effort every 
three years. As an option, your State may ease this workload spike by 
using the following approach:
    (1) Annually collect and report data for all Type A (large) point 
sources (This is required for all Type A point sources).
    (2) Annually collect data for one-third of your smaller point 
sources (Type B point sources minus Type A (large) point sources). 
Collect data for a different third of these sources each year so that 
data has been collected for all of the smaller point sources by the end 
of each three-year cycle. You may report these data to EPA annually, or 
as an option you may save three years of data and then report all of the 
smaller point sources on the three-year cycle due date.

[[Page 126]]

    (3) Annually collect data for one-third of the area, nonroad mobile, 
onroad mobile and, if required, biogenic sources. You may report these 
data to EPA annually, or as an option you may save three years of data 
and then report all of these data on the three-year cycle due date.
    (b) For the sources described in paragraph (a) of this section, your 
State will therefore have data from three successive years at any given 
time, rather than from the single year in which it is compiled.
    (c) If your State chooses the method of inventorying one-third of 
your smaller point sources and 3-year cycle area, nonroad mobile, onroad 
mobile sources each year, your State must compile each year of the 
three-year period identically. For example, if a process hasn't changed 
for a source category or individual plant, your State must use the same 
emission factors to calculate emissions for each year of the three-year 
period. If your State has revised emission factors during the three 
years for a process that hasn't changed, resubmit previous year's data 
using the revised factor. If your State uses models to estimate 
emissions, you must make sure that the model is the same for all three 
years.
    (d) If your State chooses the method of inventorying one-third of 
your smaller point sources and 3-year cycle area, nonroad mobile, onroad 
mobile sources each year and reporting them on the 3-year cycle due 
date, the first required date for you to report on all such sources will 
be June 1, 2004 as specified in Sec. 51.25. You can satisfy the 2004 
reporting requirement by either: Starting to inventory one third of your 
sources in 2000; or doing a one-time complete 3-year cycle inventory for 
2002, then changing to the option of inventorying one third of your 
sources for subsequent years.
    (e) If your State needs a new reference year emission inventory for 
a selected pollutant, your State can't use these optional reporting 
frequencies for the new reference year.
    (f) If your State is a NOX SIP call State, you can't use 
these optional reporting frequencies for NOX SIP call 
reporting.



Sec. 51.40  In what form should my State report the data to EPA?

    You must report your emission inventory data to us in electronic 
form. We support specific electronic data reporting formats and you are 
required to report your data in a format consistent with these. Because 
electronic reporting technology continually changes, contact the 
Emission Factor and Inventory Group (EFIG) for the latest specific 
formats. You can find information on the current formats at the 
following Internet address: http://www.epa.gov/ttn/chief. You may also 
call our Info CHIEF help desk at (919) 541-1000 or email to 
[email protected].



Sec. 51.45  Where should my State report the data?

    (a) Your State submits or reports data by providing it directly to 
EPA.
    (b) The latest information on data reporting procedures is available 
at the following Internet address: http://www.epa.gov/ttn/chief.
    You may also call our Info CHIEF help desk at (919)541-1000 or email 
to [email protected].

         Appendix A to Subpart A of Part 51--Tables and Glossary

                    Table 1--Minimum Point Source Reporting Thresholds by Pollutant(tpy \1\)
----------------------------------------------------------------------------------------------------------------
                                                                             Three-year cycle
             Pollutant                  Annual cycle    --------------------------------------------------------
                                      (type A sources)   Type B sources \2\                NAA \3\
----------------------------------------------------------------------------------------------------------------
1. SOX.............................    =2500     =100  =100
2. VOC.............................     =250     =100  03 (moderate)>=100
3. VOC.............................  ..................  ..................  O3 (serious)>=50
4. VOC.............................  ..................  ..................  O3 (severe)>=25
5. VOC.............................  ..................  ..................  O3 (extreme)>=10
6. NOX.............................    =2500     =100  =100
7. CO..............................    =2500    =1000  O3 (all areas)>=100
8. CO..............................  ..................  ..................  CO (all areas)=100

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9. Pb..............................  ..................       =5  =5
10. PM10...........................     =250     =100  PM1010 (moderate)>=100
11. PM10...........................  ..................  ..................  PM10 (serious)>=70
12. PM2.5..........................     =250     =100  =100
13. NH3............................     =250     =100  =100
----------------------------------------------------------------------------------------------------------------
\1\ tpy = tons per year of actual emissions.
\2\ Type A sources are a subset of the Type B sources and are the larger emitting sources by pollutant.
\3\ NAA = Nonattainment Area. Special point source reporting thresholds apply for certain pollutants by type of
  nonattainment area. The pollutants by nonattainment area are: Ozone: VOC, NOX, CO; CO: CO; PM10: PM10.


    Table 2a--Data Elements That States Must Report for Point Sources
------------------------------------------------------------------------
                                                         Every 3 years
          Data elements             Annual (Type A      (Type B sources
                                       sources)            and NAAs)
------------------------------------------------------------------------
1. Inventory year...............           [bcheck]            [bcheck]
2. Inventory start date.........           [bcheck]            [bcheck]
3. Inventory end date...........           [bcheck]            [bcheck]
4. Inventory type...............           [bcheck]            [bcheck]
5. State FIPS code..............           [bcheck]            [bcheck]
6. County FIPS code.............           [bcheck]            [bcheck]
7. Facility ID code.............           [bcheck]            [bcheck]
8. Point ID code................           [bcheck]            [bcheck]
9. Process ID code..............           [bcheck]            [bcheck]
10. Stack ID code...............           [bcheck]            [bcheck]
11. Site name...................           [bcheck]            [bcheck]
12. Physical address............           [bcheck]            [bcheck]
13. SCC or PCC..................           [bcheck]            [bcheck]
14. Heat content (fuel) (annual            [bcheck]            [bcheck]
 average).......................
15. Ash content (fuel) (annual             [bcheck]            [bcheck]
 average).......................
16. Sulfur content (fuel)                  [bcheck]            [bcheck]
 (annual average)...............
17. Pollutant code..............           [bcheck]            [bcheck]
18. Activity/throughput (annual)           [bcheck]            [bcheck]
19. Activity/throughput (daily).           [bcheck]            [bcheck]
20. Work weekday emissions......           [bcheck]            [bcheck]
21. Annual emissions............           [bcheck]            [bcheck]
22. Emission factor.............           [bcheck]            [bcheck]
23. Winter throughput (%).......           [bcheck]            [bcheck]
24. Spring throughput (%).......           [bcheck]            [bcheck]
25. Summer throughput (%).......           [bcheck]            [bcheck]
26. Fall throughput (%).........           [bcheck]            [bcheck]
27. Hr/day in operation.........           [bcheck]            [bcheck]
28. Start time (hour)...........           [bcheck]            [bcheck]
29. Day/wk in operation.........           [bcheck]            [bcheck]
30. Wk/yr in operation..........           [bcheck]            [bcheck]
31. X stack coordinate            ..................           [bcheck]
 (latitude).....................
32. Y stack coordinate            ..................           [bcheck]
 (longitude)....................
33. Stack Height................  ..................           [bcheck]
34. Stack diameter..............  ..................           [bcheck]
35. Exit gas temperature........  ..................           [bcheck]
36. Exit gas velocity...........  ..................           [bcheck]
37. Exit gas flow rate..........  ..................           [bcheck]
38. SIC/NAICS...................  ..................           [bcheck]
39. Design capacity.............  ..................           [bcheck]
40. Maximum namemplate capacity.  ..................           [bcheck]
41. Primary control eff (%).....  ..................           [bcheck]
42. Secondary control eff (%)...  ..................           [bcheck]
43. Control device type.........  ..................           [bcheck]
44. Rule effectiveness (%)......  ..................           [bcheck]
------------------------------------------------------------------------


[[Page 128]]


  Table 2b--Data Elements that States Must Report for Area and Nonroad
                             Mobile Sources
------------------------------------------------------------------------
                                                               Every 3
                       Data elements                            years
------------------------------------------------------------------------
1. Inventory year.........................................     [bcheck]
2. Inventory start date...................................     [bcheck]
3. Inventory end date.....................................     [bcheck]
4. Inventory type.........................................     [bcheck]
5. State FIPS code........................................     [bcheck]
6. County FIPS code.......................................     [bcheck]
7. SCC or PCC.............................................     [bcheck]
8. Emission factor........................................     [bcheck]
9. Activity/throughput level (annual).....................     [bcheck]
10. Total capture/control efficiency (%)..................     [bcheck]
11. Rule effectiveness (%)................................     [bcheck]
12. Rule penetration (%)..................................     [bcheck]
13. Pollutant code........................................     [bcheck]
14. Summer/winter work weekday emissions..................     [bcheck]
15. Annual emissions......................................     [bcheck]
16. Winter throughput (%).................................     [bcheck]
17. Spring throughput (%).................................     [bcheck]
18. Summer throughput (%).................................     [bcheck]
19. Fall throughput (%)...................................     [bcheck]
20. Hrs/day in operation..................................     [bcheck]
21. Days/wk in operation..................................     [bcheck]
22. Wks/yr in operation...................................     [bcheck]
------------------------------------------------------------------------


    Table 2c--Data Elements that States Must Report for Onroad Mobile
                                 Sources
------------------------------------------------------------------------
                                                               Every 3
                       Data elements                            years
------------------------------------------------------------------------
1. Inventory year.........................................     [bcheck]
2. Inventory start date...................................     [bcheck]
3. Inventory end date.....................................     [bcheck]
4. Inventory type.........................................     [bcheck]
5. State FIPS code........................................     [bcheck]
6. County FIPS code.......................................     [bcheck]
7. SCC or PCC.............................................     [bcheck]
8. Emission factor........................................     [bcheck]
9. Activity (VMT by Roadway Class)........................     [bcheck]
10. Pollutant code........................................     [bcheck]
11. Summer/winter work weekday emissions..................     [bcheck]
12. Annual emissions......................................     [bcheck]
------------------------------------------------------------------------


  Table 2d--Data Elements that States Must Report for Biogenic Sources
------------------------------------------------------------------------
                                                               Every 3
                       Data elements                            years
------------------------------------------------------------------------
1. Inventory year.........................................     [bcheck]
2. Inventory start date...................................     [bcheck]
3. Inventory end date.....................................     [bcheck]
4. Inventory type.........................................     [bcheck]
5. State FIPS code........................................     [bcheck]
6. County FIPS code.......................................     [bcheck]
7. SCC or PCC.............................................     [bcheck]
8. Pollutant code.........................................     [bcheck]
9. Summer/winter work weekday emissions...................     [bcheck]
10. Annual emissions......................................     [bcheck]
------------------------------------------------------------------------

                                Glossary

    Activity rate/throughput (annual)--A measurable factor or parameter 
that relates directly or indirectly to the emissions of an air pollution 
source. Depending on the type of source category, activity information 
may refer to the amount of fuel combusted, raw material processed, 
product manufactured, or material handled or processed. It may also 
refer to population, employment, number of units, or miles traveled. 
Activity information is typically the value that is multiplied against 
an emission factor to generate an emissions estimate.
    Activity rate/throughput (daily)--The beginning and ending dates and 
times that define the emissions period used to estimate the daily 
activity rate/throughput.
    Annual emissions--Actual emissions for a plant, point, or process--
measured or calculated that represent a calendar year.
    Area sources--Area sources collectively represent individual sources 
that have not been inventoried as specific point, mobile, or biogenic 
sources. These individual sources treated collectively as area sources 
are typically too small, numerous, or difficult to inventory using the 
methods for the other classes of sources.
    Ash content--Inert residual portion of a fuel.
    Biogenic sources--Biogenic emissions are all pollutants emitted from 
non-anthropogenic sources. Example sources include trees and vegetation, 
oil and gas seeps, and microbial activity.
    Control device type--The name of the type of control device (e.g., 
wet scrubber, flaring, or process change).
    County FIPS Code--Federal Information Placement System (FIPS) is the 
system of unique numeric codes the government developed to identify 
States, counties and parishes for the entire United States, Puerto Rico, 
and Guam.
    Day/wk in operations--Days per week that the emitting process 
operates--average over the inventory period.
    Design capacity--A measure of the size of a point source, based on 
the reported maximum continuous capacity of the unit.
    Emission factor--Ratio relating emissions of a specific pollutant to 
an activity or material throughput level.
    Exit gas flow rate--Numeric value of stack gas's flow rate.
    Exit gas temperature--Numeric value of an exit gas stream's 
temperature.
    Exit gas velocity--Numeric value of an exit gas stream's velocity.
    Facility ID code--Unique code for a plant or facility, containing 
one or more pollutant-emitting sources. This is the data element in 
Appendix A, Table 2a, that is defined elsewhere in this glossary as a 
``point source''.
    Fall throughput(%)--Part of the throughput for the three Fall months 
(September, October, November). This expresses part of the annual 
activity information based on four seasons--typically spring, summer, 
fall, and winter. It can be a percentage of the annual activity (e.g., 
production in summer is

[[Page 129]]

40% of the year's production) or units of the activity (e.g., out of 600 
units produced, spring = 150 units, summer = 250 units, fall = 150 
units, and winter = 50 units).
    Heat content--The amount of thermal heat energy in a solid, liquid, 
or gaseous fuel. Fuel heat content is typically expressed in units of 
Btu/lb of fuel, Btu/gal of fuel, joules/kg of fuel, etc.
    Hr/day in operations--Hours per day that the emitting process 
operates--average over the inventory period.
    Inventory end date--Last day of the inventory period.
    Inventory start date--First day of the inventory period.
    Inventory type--Type of inventory represented by data (i.e., point, 
3-year cycle, daily).
    Inventory year--The calendar year for which you calculated emissions 
estimates.
    Lead (Pb)--As defined in 40 CFR 50.12, lead should be reported as 
elemental lead and its compounds.
    Maximum nameplate capacity--A measure of a unit's size that the 
manufacturer puts on the unit's nameplate.
    Mobile source--A motor vehicle, nonroad engine or nonroad vehicle.
     A ``motor vehicle'' is any self-propelled vehicle 
used to carry people or property on a street or highway.
     A ``nonroad engine'' is an internal combustion 
engine (including fuel system) that is not used in a motor vehicle or 
vehicle only used for competition, or that is not affected by sections 
111 or 202 of the CAA.
     A ``nonroad vehicle'' is a vehicle that is run by 
a nonroad engine and that is not a motor vehicle or a vehicle only used 
for competition.
    PM (Particulate Matter)--Particulate matter is a criteria air 
pollutant. For the purpose of this subpart, the following definitions 
apply:
    (1) Primary PM: Particles that enter the atmosphere as a direct 
emission from a stack or an open source. It is comprised of two 
components: Filterable PM and Condensible PM. (As specified in Sec. 
51.15 (a)(2), these two PM components are the components measured by a 
stack sampling train such as EPA Method 5 and have no upper particle 
size limit.)
    (2) Filterable PM: Particles that are directly emitted by a source 
as a solid or liquid at stack or release conditions and captured on the 
filter of a stack test train.
    (3) Condensible PM: Material that is vapor phase at stack 
conditions, but which condenses and/or reacts upon cooling and dilution 
in the ambient air to form solid or liquid PM immediately after 
discharge from the stack.
    (4) Secondary PM: Particles that form through chemical reactions in 
the ambient air well after dilution and condensation have occurred. 
Secondary PM is usually formed at some distance downwind from the 
source. Secondary PM should NOT be reported in the emission inventory 
and is NOT covered by this subpart.
    (5) Primary PM2.5: Also PM2.5 (or Filterable 
PM2.5 and Condensible PM individually. Note that all 
Condensible PM is assumed to be in the PM2.5 size fraction)--
Particulate matter with an aerodynamic diameter equal to or less than 
2.5 micrometers.
    (6) Primary PM10: Also PM10 (or Filterable 
PM10 and Condensible PM individually)--Particulate matter 
with an aerodynamic diameter equal to or less than 10 micrometers.
    PCC--Process classification code. A process-level code that 
describes the equipment or operation which is emitting pollutants. This 
code is being considered as a replacement for the SCC.
    Physical address--Street address of a facility. This is the address 
of the location where the emissions occur; not, for example, the 
corporate headquarters.
    Point ID code--Unique code for the point of generation of emissions, 
typically a physical piece of equipment.
    Point source--Point sources are large, stationary (non-mobile), 
identifiable sources of emissions that release pollutants into the 
atmosphere. As used in this rule, a point source is defined as a 
facility that annually emits more than a ``threshold'' value as defined 
under Sec. 51.20.
    Pollutant code--A unique code for each reported pollutant assigned 
in the Emission Inventory Improvement Program (EIIP) Data Model. The 
EIIP model was developed to promote consistency in organizations sharing 
emissions data. The model uses character names for criteria pollutants 
and Chemical Abstracts Service (CAS) numbers for all other pollutants. 
You may be using SAROAD codes for pollutants, but you should be able to 
map them to the pollutant codes in the EIIP Data Model.
    Process ID code--Unique code for the process generating the 
emissions, typically a description of a process.
    Roadway class--A classification system developed by the Federal 
Highway Administration that defines all public roadways as to type. 
Currently there are four roadway types: (1) Freeway, (2) freeway ramp, 
(3) arterial/collector and (4) local.
    Rule effectiveness (RE)--How well a regulatory program achieves all 
possible emission reductions. This rating reflects the assumption that 
controls typically aren't 100 percent effective because of equipment 
downtime, upsets, decreases in control efficiencies, and other 
deficiencies in emission estimates. RE adjusts the control efficiency.
    Rule penetration--The percentage of an area source category covered 
by an applicable regulation.

[[Page 130]]

    SCC--Source classification code. A process-level code that describes 
the equipment and/or operation which is emitting pollutants.
    Seasonal activity rate/throughput--A measurable factor or parameter 
that relates directly or indirectly to the pollutant season emissions of 
an air pollution source. Depending on the type of source category, 
activity information may refer to the amount of fuel combusted, raw 
material processed, product manufactured, or material handled or 
processed. It may also refer to population, employment, number of units, 
or miles traveled. Activity information is typically the value that is 
multiplied against an emission factor to generate an emissions estimate.
    Seasonal fuel heat content--The amount of thermal heat energy in a 
solid, liquid, or gaseous fuel used during the pollutant season. Fuel 
heat content is typically expressed in units of Btu/lb of fuel, Btu/gal 
of fuel, joules/kg of fuel, etc.
    Secondary control eff (%)--The emission reduction efficiency of a 
secondary control device. Control efficiency is usually expressed as a 
percentage or in tenths.
    SIC/NAICS--Standard Industrial Classification code. NAICS (North 
American Industry Classification System) codes will replace SIC codes. 
U.S. Department of Commerce's code for businesses by products or 
services.
    Site name--The name of the facility.
    Spring throughput (%)--Part of throughput or activity for the three 
spring months (March, April, May). See the definition of Fall 
Throughput.
    Stack diameter--A stack's inner physical diameter.
    Stack height--A stack's physical height above the surrounding 
terrain.
    Stack ID code--Unique code for the point where emissions from one or 
more processes release into the atmosphere.
    Start time (hour)--Start time (if available) that you used to 
calculate the emissions estimates.
    State FIPS Code--Federal Information Placement System (FIPS) is the 
system of unique numeric codes the government developed to identify 
States, counties and parishes for the entire United States, Puerto Rico, 
and Guam.
    Sulfur content--Sulfur content of a fuel, usually expressed as 
percent by weight.
    Summer throughput(%)--Part of throughput or activity for the three 
summer months (June, July, August). See the definition of Fall 
Throughput.
    Summer/winter work weekday emissions--Average day's emissions for a 
typical day. Ozone daily emissions = summer work weekday; CO and PM 
daily emissions = winter work weekday.
    Total capture/control efficiency--The emission reduction efficiency 
of a primary control device, which shows the amount controls or material 
changes reduce a particular pollutant from a process' emissions. Control 
efficiency is usually expressed as a percentage or in tenths.
    Type A source--Large point sources with actual annual emissions 
greater than or equal to any of the emission thresholds listed in Table 
1 for Type A sources.
    Type B source--Point sources with actual annual emissions during any 
year of the three year cycle greater than or equal to any of the 
emission thresholds listed in Table 1 for Type B sources. Type B sources 
include all Type A sources.
    VMT by Roadway Class--Vehicle miles traveled (VMT) expresses vehicle 
activity and is used with emission factors. The emission factors are 
usually expressed in terms of grams per mile of travel. Because VMT 
doesn't correlate directly to emissions that occur while the vehicle 
isn't moving, these nonmoving emissions are incorporated into the 
emission factors in EPA's MOBILE Model.
    VOC--Volatile Organic Compounds. The EPA's regulatory definition of 
VOC is in 40 CFR 51.100.
    Winter throughput (%)--Part of throughput or activity for the three 
winter months (December, January, February, all from the same year, 
e.g., Winter 2000 = January 2000 + February, 2000 + December 2000). See 
the definition of Fall Throughput.
    Wk/yr in operation--Weeks per year that the emitting process 
operates.
    Work Weekday--Any day of the week except Saturday or Sunday.
    X stack coordinate (latitude)--An object's north-south geographical 
coordinate. Y stack coordinate (longitude)--An object's east-west 
geographical coordinate.

              Appendix B to Subpart A of Part 51 [Reserved]

Subparts B-E [Reserved]



                    Subpart F_Procedural Requirements

    Authority: 42 U.S.C. 7401, 7411, 7412, 7413, 7414, 7470-7479, 7501-
7508, 7601, and 7602.



Sec. 51.100  Definitions.

    As used in this part, all terms not defined herein will have the 
meaning given them in the Act:
    (a) Act means the Clean Air Act (42 U.S.C. 7401 et seq., as amended 
by Pub. L. 91-604, 84 Stat. 1676 Pub. L. 95-95, 91 Stat., 685 and Pub. 
L. 95-190, 91 Stat., 1399.)

[[Page 131]]

    (b) Administrator means the Administrator of the Environmental 
Protection Agency (EPA) or an authorized representative.
    (c) Primary standard means a national primary ambient air quality 
standard promulgated pursuant to section 109 of the Act.
    (d) Secondary standard means a national secondary ambient air 
quality standard promulgated pursuant to section 109 of the Act.
    (e) National standard means either a primary or secondary standard.
    (f) Owner or operator means any person who owns, leases, operates, 
controls, or supervises a facility, building, structure, or installation 
which directly or indirectly result or may result in emissions of any 
air pollutant for which a national standard is in effect.
    (g) Local agency means any local government agency other than the 
State agency, which is charged with responsibility for carrying out a 
portion of the plan.
    (h) Regional Office means one of the ten (10) EPA Regional Offices.
    (i) State agency means the air pollution control agency primarily 
responsible for development and implementation of a plan under the Act.
    (j) Plan means an implementation plan approved or promulgated under 
section 110 of 172 of the Act.
    (k) Point source means the following:
    (1) For particulate matter, sulfur oxides, carbon monoxide, volatile 
organic compounds (VOC) and nitrogen dioxide--
    (i) Any stationary source the actual emissions of which are in 
excess of 90.7 metric tons (100 tons) per year of the pollutant in a 
region containing an area whose 1980 urban place population, as defined 
by the U.S. Bureau of the Census, was equal to or greater than 1 
million.
    (ii) Any stationary source the actual emissions of which are in 
excess of 22.7 metric tons (25 tons) per year of the pollutant in a 
region containing an area whose 1980 urban place population, as defined 
by the U.S. Bureau of the Census, was less than 1 million; or
    (2) For lead or lead compounds measured as elemental lead, any 
stationary source that actually emits a total of 4.5 metric tons (5 
tons) per year or more.
    (l) Area source means any small residential, governmental, 
institutional, commercial, or industrial fuel combustion operations; 
onsite solid waste disposal facility; motor vehicles, aircraft vessels, 
or other transportation facilities or other miscellaneous sources 
identified through inventory techniques similar to those described in 
the ``AEROS Manual series, Vol. II AEROS User's Manual,'' EPA-450/2-76-
029 December 1976.
    (m) Region means an area designated as an air quality control region 
(AQCR) under section 107(c) of the Act.
    (n) Control strategy means a combination of measures designated to 
achieve the aggregate reduction of emissions necessary for attainment 
and maintenance of national standards including, but not limited to, 
measures such as:
    (1) Emission limitations.
    (2) Federal or State emission charges or taxes or other economic 
incentives or disincentives.
    (3) Closing or relocation of residential, commercial, or industrial 
facilities.
    (4) Changes in schedules or methods of operation of commercial or 
industrial facilities or transportation systems, including, but not 
limited to, short-term changes made in accordance with standby plans.
    (5) Periodic inspection and testing of motor vehicle emission 
control systems, at such time as the Administrator determines that such 
programs are feasible and practicable.
    (6) Emission control measures applicable to in-use motor vehicles, 
including, but not limited to, measures such as mandatory maintenance, 
installation of emission control devices, and conversion to gaseous 
fuels.
    (7) Any transportation control measure including those 
transportation measures listed in section 108(f) of the Clean Air Act as 
amended.
    (8) Any variation of, or alternative to any measure delineated 
herein.
    (9) Control or prohibition of a fuel or fuel additive used in motor 
vehicles, if such control or prohibition is necessary to achieve a 
national primary or secondary air quality standard and is

[[Page 132]]

approved by the Administrator under section 211(c)(4)(C) of the Act.
    (o) Reasonably available control technology (RACT) means devices, 
systems, process modifications, or other apparatus or techniques that 
are reasonably available taking into account:
    (1) The necessity of imposing such controls in order to attain and 
maintain a national ambient air quality standard;
    (2) The social, environmental, and economic impact of such controls; 
and
    (3) Alternative means of providing for attainment and maintenance of 
such standard. (This provision defines RACT for the purposes of Sec. 
51.341(b) only.)
    (p) Compliance schedule means the date or dates by which a source or 
category of sources is required to comply with specific emission 
limitations contained in an implementation plan and with any increments 
of progress toward such compliance.
    (q) Increments of progress means steps toward compliance which will 
be taken by a specific source, including:
    (1) Date of submittal of the source's final control plan to the 
appropriate air pollution control agency;
    (2) Date by which contracts for emission control systems or process 
modifications will be awarded; or date by which orders will be issued 
for the purchase of component parts to accomplish emission control or 
process modification;
    (3) Date of initiation of on-site construction or installation of 
emission control equipment or process change;
    (4) Date by which on-site construction or installation of emission 
control equipment or process modification is to be completed; and
    (5) Date by which final compliance is to be achieved.
    (r) Transportation control measure means any measure that is 
directed toward reducing emissions of air pollutants from transportation 
sources. Such measures include, but are not limited to, those listed in 
section 108(f) of the Clean Air Act.
    (s) Volatile organic compounds (VOC) means any compound of carbon, 
excluding carbon monoxide, carbon dioxide, carbonic acid, metallic 
carbides or carbonates, and ammonium carbonate, which participates in 
atmospheric photochemical reactions.
    (1) This includes any such organic compound other than the 
following, which have been determined to have negligible photochemical 
reactivity: methane; ethane; methylene chloride (dichloromethane); 
1,1,1-trichloroethane (methyl chloroform); 1,1,2-trichloro-1,2,2-
trifluoroethane (CFC-113); trichlorofluoromethane (CFC-11); 
dichlorodifluoromethane (CFC-12); chlorodifluoromethane (HCFC-22); 
trifluoromethane (HFC-23); 1,2-dichloro 1,1,2,2-tetrafluoroethane (CFC-
114); chloropentafluoroethane (CFC-115); 1,1,1-trifluoro 2,2-
dichloroethane (HCFC-123); 1,1,1,2-tetrafluoroethane (HFC-134a); 1,1-
dichloro 1-fluoroethane (HCFC-141b); 1-chloro 1,1-difluoroethane (HCFC-
142b); 2-chloro-1,1,1,2-tetrafluoroethane (HCFC-124); pentafluoroethane 
(HFC-125); 1,1,2,2-tetrafluoroethane (HFC-134); 1,1,1-trifluoroethane 
(HFC-143a); 1,1-difluoroethane (HFC-152a); parachlorobenzotrifluoride 
(PCBTF); cyclic, branched, or linear completely methylated siloxanes; 
acetone; perchloroethylene (tetrachloroethylene); 3,3-dichloro-
1,1,1,2,2-pentafluoropropane (HCFC-225ca); 1,3-dichloro-1,1,2,2,3-
pentafluoropropane (HCFC-225cb); 1,1,1,2,3,4,4,5,5,5-decafluoropentane 
(HFC 43-10mee); difluoromethane (HFC-32); ethylfluoride (HFC-161); 
1,1,1,3,3,3-hexafluoropropane (HFC-236fa); 1,1,2,2,3-pentafluoropropane 
(HFC-245ca); 1,1,2,3,3-pentafluoropropane (HFC-245ea); 1,1,1,2,3-
pentafluoropropane (HFC-245eb); 1,1,1,3,3-pentafluoropropane (HFC-
245fa); 1,1,1,2,3,3-hexafluoropropane (HFC-236ea); 1,1,1,3,3-
pentafluorobutane (HFC-365mfc); chlorofluoromethane (HCFC-31); 1 chloro-
1-fluoroethane (HCFC-151a); 1,2-dichloro-1,1,2-trifluoroethane (HCFC-
123a); 1,1,1,2,2,3,3,4,4-nonafluoro-4-methoxy-butane 
(C4F9OCH3 or HFE-7100); 2-
(difluoromethoxymethyl)-1,1,1,2,3,3,3-heptafluoropropane 
((CF3)2CFCF2OCH3); 1-ethoxy-
1,1,2,2,3,3,4,4,4-nonafluorobutane 
(C4F9OC2H5 or HFE-7200); 2-
(ethoxydifluoromethyl)-1,1,1,2,3,3,3-heptafluoropropane 
((CF3)2CFCF2OC2H5)
; methyl acetate,

[[Page 133]]

1,1,1,2,2,3,3-heptafluoro-3-methoxy-propane (n-
C3F7OCH3, HFE-7000), 3-ethoxy-
1,1,1,2,3,4,4,5,5,6,6,6-dodecafluoro-2-(trifluoromethyl) hexane (HFE-
7500), 1,1,1,2,3,3,3-heptafluoropropane (HFC 227ea), and methyl formate 
(HCOOCH3), and perfluorocarbon compounds which fall into these classes:
    (i) Cyclic, branched, or linear, completely fluorinated alkanes;
    (ii) Cyclic, branched, or linear, completely fluorinated ethers with 
no unsaturations;
    (iii) Cyclic, branched, or linear, completely fluorinated tertiary 
amines with no unsaturations; and
    (iv) Sulfur containing perfluorocarbons with no unsaturations and 
with sulfur bonds only to carbon and fluorine.
    (2) For purposes of determining compliance with emissions limits, 
VOC will be measured by the test methods in the approved State 
implementation plan (SIP) or 40 CFR part 60, appendix A, as applicable. 
Where such a method also measures compounds with negligible 
photochemical reactivity, these negligibility-reactive compounds may be 
excluded as VOC if the amount of such compounds is accurately 
quantified, and such exclusion is approved by the enforcement authority.
    (3) As a precondition to excluding these compounds as VOC or at any 
time thereafter, the enforcement authority may require an owner or 
operator to provide monitoring or testing methods and results 
demonstrating, to the satisfaction of the enforcement authority, the 
amount of negligibly-reactive compounds in the source's emissions.
    (4) For purposes of Federal enforcement for a specific source, the 
EPA shall use the test methods specified in the applicable EPA-approved 
SIP, in a permit issued pursuant to a program approved or promulgated 
under title V of the Act, or under 40 CFR part 51, subpart I or appendix 
S, or under 40 CFR parts 52 or 60. The EPA shall not be bound by any 
State determination as to appropriate methods for testing or monitoring 
negligibly-reactive compounds if such determination is not reflected in 
any of the above provisions.
    (5) The following compound(s) are VOC for purposes of all 
recordkeeping, emissions reporting, photochemical dispersion modeling 
and inventory requirements which apply to VOC and shall be uniquely 
identified in emission reports, but are not VOC for purposes of VOC 
emissions limitations or VOC content requirements: t-butyl acetate.
    (6) For the purposes of determining compliance with California's 
aerosol coatings reactivity-based regulation, (as described in the 
California Code of Regulations, Title 17, Division 3, Chapter 1, 
Subchapter 8.5, Article 3), any organic compound in the volatile portion 
of an aerosol coating is counted towards that product's reactivity-based 
limit. Therefore, the compounds identified in paragraph (s) of this 
section as negligibly reactive and excluded from EPA's definition of 
VOCs are to be counted towards a product's reactivity limit for the 
purposes of determining compliance with California's aerosol coatings 
reactivity-based regulation.
    (t)-(w) [Reserved]
    (x) Time period means any period of time designated by hour, month, 
season, calendar year, averaging time, or other suitable 
characteristics, for which ambient air quality is estimated.
    (y) Variance means the temporary deferral of a final compliance date 
for an individual source subject to an approved regulation, or a 
temporary change to an approved regulation as it applies to an 
individual source.
    (z) Emission limitation and emission standard mean a requirement 
established by a State, local government, or the Administrator which 
limits the quantity, rate, or concentration of emissions of air 
pollutants on a continuous basis, including any requirements which limit 
the level of opacity, prescribe equipment, set fuel specifications, or 
prescribe operation or maintenance procedures for a source to assure 
continuous emission reduction.
    (aa) Capacity factor means the ratio of the average load on a 
machine or equipment for the period of time considered to the capacity 
rating of the machine or equipment.
    (bb) Excess emissions means emissions of an air pollutant in excess 
of an emission standard.

[[Page 134]]

    (cc) Nitric acid plant means any facility producing nitric acid 30 
to 70 percent in strength by either the pressure or atmospheric pressure 
process.
    (dd) Sulfuric acid plant means any facility producing sulfuric acid 
by the contact process by burning elemental sulfur, alkylation acid, 
hydrogen sulfide, or acid sludge, but does not include facilities where 
conversion to sulfuric acid is utilized primarily as a means of 
preventing emissions to the atmosphere of sulfur dioxide or other sulfur 
compounds.
    (ee) Fossil fuel-fired steam generator means a furnance or bioler 
used in the process of burning fossil fuel for the primary purpose of 
producing steam by heat transfer.
    (ff) Stack means any point in a source designed to emit solids, 
liquids, or gases into the air, including a pipe or duct but not 
including flares.
    (gg) A stack in existence means that the owner or operator had (1) 
begun, or caused to begin, a continuous program of physical on-site 
construction of the stack or (2) entered into binding agreements or 
contractual obligations, which could not be cancelled or modified 
without substantial loss to the owner or operator, to undertake a 
program of construction of the stack to be completed within a reasonable 
time.
    (hh)(1) Dispersion technique means any technique which attempts to 
affect the concentration of a pollutant in the ambient air by:
    (i) Using that portion of a stack which exceeds good engineering 
practice stack height:
    (ii) Varying the rate of emission of a pollutant according to 
atmospheric conditions or ambient concentrations of that pollutant; or
    (iii) Increasing final exhaust gas plume rise by manipulating source 
process parameters, exhaust gas parameters, stack parameters, or 
combining exhaust gases from several existing stacks into one stack; or 
other selective handling of exhaust gas streams so as to increase the 
exhaust gas plume rise.
    (2) The preceding sentence does not include:
    (i) The reheating of a gas stream, following use of a pollution 
control system, for the purpose of returning the gas to the temperature 
at which it was originally discharged from the facility generating the 
gas stream;
    (ii) The merging of exhaust gas streams where:
    (A) The source owner or operator demonstrates that the facility was 
originally designed and constructed with such merged gas streams;
    (B) After July 8, 1985 such merging is part of a change in operation 
at the facility that includes the installation of pollution controls and 
is accompanied by a net reduction in the allowable emissions of a 
pollutant. This exclusion from the definition of dispersion techniques 
shall apply only to the emission limitation for the pollutant affected 
by such change in operation; or
    (C) Before July 8, 1985, such merging was part of a change in 
operation at the facility that included the installation of emissions 
control equipment or was carried out for sound economic or engineering 
reasons. Where there was an increase in the emission limitation or, in 
the event that no emission limitation was in existence prior to the 
merging, an increase in the quantity of pollutants actually emitted 
prior to the merging, the reviewing agency shall presume that merging 
was significantly motivated by an intent to gain emissions credit for 
greater dispersion. Absent a demonstration by the source owner or 
operator that merging was not significantly motivated by such intent, 
the reviewing agency shall deny credit for the effects of such merging 
in calculating the allowable emissions for the source;
    (iii) Smoke management in agricultural or silvicultural prescribed 
burning programs;
    (iv) Episodic restrictions on residential woodburning and open 
burning; or
    (v) Techniques under Sec. 51.100(hh)(1)(iii) which increase final 
exhaust gas plume rise where the resulting allowable emissions of sulfur 
dioxide from the facility do not exceed 5,000 tons per year.
    (ii) Good engineering practice (GEP) stack height means the greater 
of:
    (1) 65 meters, measured from the ground-level elevation at the base 
of the stack:
    (2)(i) For stacks in existence on January 12, 1979, and for which 
the owner

[[Page 135]]

or operator had obtained all applicable permits or approvals required 
under 40 CFR parts 51 and 52.

Hg = 2.5H,


provided the owner or operator produces evidence that this equation was 
actually relied on in establishing an emission limitation:
    (ii) For all other stacks,

Hg = H + 1.5L

where:

Hg = good engineering practice stack height, measured from 
the ground-level elevation at the base of the stack,
H = height of nearby structure(s) measured from the ground-level 
elevation at the base of the stack.
L = lesser dimension, height or projected width, of nearby structure(s)


provided that the EPA, State or local control agency may require the use 
of a field study or fluid model to verify GEP stack height for the 
source; or
    (3) The height demonstrated by a fluid model or a field study 
approved by the EPA State or local control agency, which ensures that 
the emissions from a stack do not result in excessive concentrations of 
any air pollutant as a result of atmospheric downwash, wakes, or eddy 
effects created by the source itself, nearby structures or nearby 
terrain features.
    (jj) Nearby as used in Sec. 51.100(ii) of this part is defined for 
a specific structure or terrain feature and
    (1) For purposes of applying the formulae provided in Sec. 
51.100(ii)(2) means that distance up to five times the lesser of the 
height or the width dimension of a structure, but not greater than 0.8 
km (\1/2\ mile), and
    (2) For conducting demonstrations under Sec. 51.100(ii)(3) means 
not greater than 0.8 km (\1/2\ mile), except that the portion of a 
terrain feature may be considered to be nearby which falls within a 
distance of up to 10 times the maximum height (Ht) of the 
feature, not to exceed 2 miles if such feature achieves a height 
(Ht) 0.8 km from the stack that is at least 40 percent of the 
GEP stack height determined by the formulae provided in Sec. 
51.100(ii)(2)(ii) of this part or 26 meters, whichever is greater, as 
measured from the ground-level elevation at the base of the stack. The 
height of the structure or terrain feature is measured from the ground-
level elevation at the base of the stack.
    (kk) Excessive concentration is defined for the purpose of 
determining good engineering practice stack height under Sec. 
51.100(ii)(3) and means:
    (1) For sources seeking credit for stack height exceeding that 
established under Sec. 51.100(ii)(2) a maximum ground-level 
concentration due to emissions from a stack due in whole or part to 
downwash, wakes, and eddy effects produced by nearby structures or 
nearby terrain features which individually is at least 40 percent in 
excess of the maximum concentration experienced in the absence of such 
downwash, wakes, or eddy effects and which contributes to a total 
concentration due to emissions from all sources that is greater than an 
ambient air quality standard. For sources subject to the prevention of 
significant deterioration program (40 CFR 51.166 and 52.21), an 
excessive concentration alternatively means a maximum ground-level 
concentration due to emissions from a stack due in whole or part to 
downwash, wakes, or eddy effects produced by nearby structures or nearby 
terrain features which individually is at least 40 percent in excess of 
the maximum concentration experienced in the absence of such downwash, 
wakes, or eddy effects and greater than a prevention of significant 
deterioration increment. The allowable emission rate to be used in 
making demonstrations under this part shall be prescribed by the new 
source performance standard that is applicable to the source category 
unless the owner or operator demonstrates that this emission rate is 
infeasible. Where such demonstrations are approved by the authority 
administering the State implementation plan, an alternative emission 
rate shall be established in consultation with the source owner or 
operator.
    (2) For sources seeking credit after October 11, 1983, for increases 
in existing stack heights up to the heights established under Sec. 
51.100(ii)(2), either (i) a maximum ground-level concentration due in 
whole or part to downwash, wakes or eddy effects as provided in

[[Page 136]]

paragraph (kk)(1) of this section, except that the emission rate 
specified by any applicable State implementation plan (or, in the 
absence of such a limit, the actual emission rate) shall be used, or 
(ii) the actual presence of a local nuisance caused by the existing 
stack, as determined by the authority administering the State 
implementation plan; and
    (3) For sources seeking credit after January 12, 1979 for a stack 
height determined under Sec. 51.100(ii)(2) where the authority 
administering the State implementation plan requires the use of a field 
study or fluid model to verify GEP stack height, for sources seeking 
stack height credit after November 9, 1984 based on the aerodynamic 
influence of cooling towers, and for sources seeking stack height credit 
after December 31, 1970 based on the aerodynamic influence of structures 
not adequately represented by the equations in Sec. 51.100(ii)(2), a 
maximum ground-level concentration due in whole or part to downwash, 
wakes or eddy effects that is at least 40 percent in excess of the 
maximum concentration experienced in the absence of such downwash, 
wakes, or eddy effects.
    (ll)-(mm) [Reserved]
    (nn) Intermittent control system (ICS) means a dispersion technique 
which varies the rate at which pollutants are emitted to the atmosphere 
according to meteorological conditions and/or ambient concentrations of 
the pollutant, in order to prevent ground-level concentrations in excess 
of applicable ambient air quality standards. Such a dispersion technique 
is an ICS whether used alone, used with other dispersion techniques, or 
used as a supplement to continuous emission controls (i.e., used as a 
supplemental control system).
    (oo) Particulate matter means any airborne finely divided solid or 
liquid material with an aerodynamic diameter smaller than 100 
micrometers.
    (pp) Particulate matter emissions means all finely divided solid or 
liquid material, other than uncombined water, emitted to the ambient air 
as measured by applicable reference methods, or an equivalent or 
alternative method, specified in this chapter, or by a test method 
specified in an approved State implementation plan.
    (qq) PM10 means particulate matter with an aerodynamic 
diameter less than or equal to a nominal 10 micrometers as measured by a 
reference method based on appendix J of part 50 of this chapter and 
designated in accordance with part 53 of this chapter or by an 
equivalent method designated in accordance with part 53 of this chapter.
    (rr) PM10 emissions means finely divided solid or liquid 
material, with an aerodynamic diameter less than or equal to a nominal 
10 micrometers emitted to the ambient air as measured by an applicable 
reference method, or an equivalent or alternative method, specified in 
this chapter or by a test method specified in an approved State 
implementation plan.
    (ss) Total suspended particulate means particulate matter as 
measured by the method described in appendix B of part 50 of this 
chapter.

[51 FR 40661, Nov. 7, 1986, as amended at 52 FR 24712, July 1, 1987; 57 
FR 3945, Feb. 3, 1992; 61 FR 4590, Feb. 7, 1996; 61 FR 16060, Apr. 11, 
1996; 61 FR 30162, June 14, 1996; 61 FR 52850, Oct. 8, 1996; 62 FR 
44903, Aug. 25, 1997; 63 FR 9151, Feb. 24, 1998; 63 FR 17333, Apr. 9, 
1998; 69 FR 69298, 69304, Nov. 29, 2004; 70 FR 53935, Sept. 13, 2005]



Sec. 51.101  Stipulations.

    Nothing in this part will be construed in any manner:
    (a) To encourage a State to prepare, adopt, or submit a plan which 
does not provide for the protection and enhancement of air quality so as 
to promote the public health and welfare and productive capacity.
    (b) To encourage a State to adopt any particular control strategy 
without taking into consideration the cost-effectiveness of such control 
strategy in relation to that of alternative control strategies.
    (c) To preclude a State from employing techniques other than those 
specified in this part for purposes of estimating air quality or 
demonstrating the adequacy of a control strategy, provided that such 
other techniques are shown to be adequate and appropriate for such 
purposes.
    (d) To encourage a State to prepare, adopt, or submit a plan without 
taking

[[Page 137]]

into consideration the social and economic impact of the control 
strategy set forth in such plan, including, but not limited to, impact 
on availability of fuels, energy, transportation, and employment.
    (e) To preclude a State from preparing, adopting, or submitting a 
plan which provides for attainment and maintenance of a national 
standard through the application of a control strategy not specifically 
identified or described in this part.
    (f) To preclude a State or political subdivision thereof from 
adopting or enforcing any emission limitations or other measures or 
combinations thereof to attain and maintain air quality better than that 
required by a national standard.
    (g) To encourage a State to adopt a control strategy uniformly 
applicable throughout a region unless there is no satisfactory 
alternative way of providing for attainment and maintenance of a 
national standard throughout such region.

[61 FR 30163, June 14, 1996]



Sec. 51.102  Public hearings.

    (a) Except as otherwise provided in paragraph (c) of this section, 
States must conduct one or more public hearings on the following prior 
to adoption and submission to EPA of:
    (1) Any plan or revision of it required by Sec. 51.104(a).
    (2) Any individual compliance schedule under (Sec. 51.260).
    (3) Any revision under Sec. 51.104(d).
    (b) Separate hearings may be held for plans to implement primary and 
secondary standards.
    (c) No hearing will be required for any change to an increment of 
progress in an approved individual compliance schedule unless such 
change is likely to cause the source to be unable to comply with the 
final compliance date in the schedule. The requirements of Sec. Sec. 
51.104 and 51.105 will be applicable to such schedules, however.
    (d) Any hearing required by paragraph (a) of this section will be 
held only after reasonable notice, which will be considered to include, 
at least 30 days prior to the date of such hearing(s):
    (1) Notice given to the public by prominent advertisement in the 
area affected announcing the date(s), time(s), and place(s) of such 
hearing(s);
    (2) Availability of each proposed plan or revision for public 
inspection in at least one location in each region to which it will 
apply, and the availability of each compliance schedule for public 
inspection in at least one location in the region in which the affected 
source is located;
    (3) Notification to the Administrator (through the appropriate 
Regional Office);
    (4) Notification to each local air pollution control agency which 
will be significantly impacted by such plan, schedule or revision;
    (5) In the case of an interstate region, notification to any other 
States included, in whole or in part, in the regions which are 
significantly impacted by such plan or schedule or revision.
    (e) The State must prepare and retain, for inspection by the 
Administrator upon request, a record of each hearing. The record must 
contain, as a minimum, a list of witnesses together with the text of 
each presentation.
    (f) The State must submit with the plan, revision, or schedule a 
certification that the hearing required by paragraph (a) of this section 
was held in accordance with the notice required by paragraph (d) of this 
section.
    (g) Upon written application by a State agency (through the 
appropriate Regional Office), the Administrator may approve State 
procedures for public hearings. The following criteria apply:
    (1) Procedures approved under this section shall be deemed to 
satisfy the requirement of this part regarding public hearings.
    (2) Procedures different from this part may be approved if they--
    (i) Ensure public participation in matters for which hearings are 
required; and
    (ii) Provide adequate public notification of the opportunity to 
participate.
    (3) The Administrator may impose any conditions on approval he or 
she deems necessary.

[36 FR 22938, Nov. 25, 1971, as amended at 65 FR 8657, Feb. 22, 2000]

[[Page 138]]



Sec. 51.103  Submission of plans, preliminary review of plans.

    (a) The State makes an official plan submission to EPA only when the 
submission conforms to the requirements of appendix V to this part, and 
the State delivers five copies of the plan to the appropriate Regional 
Office, with a letter giving notice of such action.
    (b) Upon request of a State, the Administrator will provide 
preliminary review of a plan or portion thereof submitted in advance of 
the date such plan is due. Such requests must be made in writing to the 
appropriate Regional Office and must be accompanied by five copies of 
the materials to be reviewed. Requests for preliminary review do not 
relieve a State of the responsibility of adopting and submitting plans 
in accordance with prescribed due dates.

[51 FR 40661, Nov. 7, 1986, as amended at 55 FR 5830, Feb. 16, 1990; 63 
FR 9151, Feb. 24, 1998]



Sec. 51.104  Revisions.

    (a) States may revise the plan from time to time consistent with the 
requirements applicable to implementation plans under this part.
    (b) The States must submit any revision of any regulation or any 
compliance schedule under paragraph (c) of this section to the 
Administrator no later than 60 days after its adoption.
    (c) EPA will approve revisions only after applicable hearing 
requirements of Sec. 51.102 have been satisfied.
    (d) In order for a variance to be considered for approval as a 
revision to the State implementation plan, the State must submit it in 
accordance with the requirements of this section.

[51 FR 40661, Nov. 7, 1986, as amended at 61 FR 16060, Apr. 11, 1996]



Sec. 51.105  Approval of plans.

    Revisions of a plan, or any portion thereof, will not be considered 
part of an applicable plan until such revisions have been approved by 
the Administrator in accordance with this part.

[51 FR 40661, Nov. 7, 1986, as amended at 60 FR 33922, June 29, 1995]



                       Subpart G_Control Strategy

    Source: 51 FR 40665, Nov. 7, 1986, unless otherwise noted.



Sec. 51.110  Attainment and maintenance of national standards.

    (a) Each plan providing for the attainment of a primary or secondary 
standard must specify the projected attainment date.
    (b)-(f) [Reserved]
    (g) During developing of the plan, EPA encourages States to identify 
alternative control strategies, as well as the costs and benefits of 
each such alternative for attainment or maintenance of the national 
standard.

[51 FR 40661 Nov. 7, 1986 as amended at 61 FR 16060, Apr. 11, 1996; 61 
FR 30163, June 14, 1996]



Sec. 51.111  Description of control measures.

    Each plan must set forth a control strategy which includes the 
following:
    (a) A description of enforcement methods including, but not limited 
to:
    (1) Procedures for monitoring compliance with each of the selected 
control measures,
    (2) Procedures for handling violations, and
    (3) A designation of agency responsibility for enforcement of 
implementation.
    (b) [Reserved]

[51 FR 40665, Nov. 7, 1986, as amended at 60 FR 33922, June 29, 1995]



Sec. 51.112  Demonstration of adequacy.

    (a) Each plan must demonstrate that the measures, rules, and 
regulations contained in it are adequate to provide for the timely 
attainment and maintenance of the national standard that it implements.
    (1) The adequacy of a control strategy shall be demonstrated by 
means of applicable air quality models, data bases, and other 
requirements specified in appendix W of this part (Guideline on Air 
Quality Models).
    (2) Where an air quality model specified in appendix W of this part 
(Guideline on Air Quality Models) is inappropriate, the model may be 
modified or another model substituted. Such a modification or 
substitution of a model

[[Page 139]]

may be made on a case-by-case basis or, where appropriate, on a generic 
basis for a specific State program. Written approval of the 
Administrator must be obtained for any modification or substitution. In 
addition, use of a modified or substituted model must be subject to 
notice and opportunity for public comment under procedures set forth in 
Sec. 51.102.
    (b) The demonstration must include the following:
    (1) A summary of the computations, assumptions, and judgments used 
to determine the degree of reduction of emissions (or reductions in the 
growth of emissions) that will result from the implementation of the 
control strategy.
    (2) A presentation of emission levels expected to result from 
implementation of each measure of the control strategy.
    (3) A presentation of the air quality levels expected to result from 
implementation of the overall control strategy presented either in 
tabular form or as an isopleth map showing expected maximum pollutant 
concentrations.
    (4) A description of the dispersion models used to project air 
quality and to evaluate control strategies.
    (5) For interstate regions, the analysis from each constituent State 
must, where practicable, be based upon the same regional emission 
inventory and air quality baseline.

[51 FR 40665, Nov. 7, 1986, as amended at 58 FR 38821, July 20, 1993; 60 
FR 40468, Aug. 9, 1995; 61 FR 41840, Aug. 12, 1996]



Sec. 51.113  [Reserved]



Sec. 51.114  Emissions data and projections.

    (a) Except for lead, each plan must contain a detailed inventory of 
emissions from point and area sources. Lead requirements are specified 
in Sec. 51.117. The inventory must be based upon measured emissions or, 
where measured emissions are not available, documented emission factors.
    (b) Each plan must contain a summary of emission levels projected to 
result from application of the new control strategy.
    (c) Each plan must identify the sources of the data used in the 
projection of emissions.



Sec. 51.115  Air quality data and projections.

    (a) Each plan must contain a summary of data showing existing air 
quality.
    (b) Each plan must:
    (1) Contain a summary of air quality concentrations expected to 
result from application of the control strategy, and
    (2) Identify and describe the dispersion model, other air quality 
model, or receptor model used.
    (c) Actual measurements of air quality must be used where available 
if made by methods specified in appendix C to part 58 of this chapter. 
Estimated air quality using appropriate modeling techniques may be used 
to supplement measurements.
    (d) For purposes of developing a control strategy, background 
concentration shall be taken into consideration with respect to 
particulate matter. As used in this subpart, background concentration is 
that portion of the measured ambient levels that cannot be reduced by 
controlling emissions from man-made sources.
    (e) In developing an ozone control strategy for a particular area, 
background ozone concentrations and ozone transported into an area must 
be considered. States may assume that the ozone standard will be 
attained in upwind areas.



Sec. 51.116  Data availability.

    (a) The State must retain all detailed data and calculations used in 
the preparation of each plan or each plan revision, and make them 
available for public inspection and submit them to the Administrator at 
his request.
    (b) The detailed data and calculations used in the preparation of 
plan revisions are not considered a part of the plan.
    (c) Each plan must provide for public availability of emission data 
reported by source owners or operators or otherwise obtained by a State 
or local agency. Such emission data must be correlated with applicable 
emission limitations or other measures. As used in

[[Page 140]]

this paragraph, correlated means presented in such a manner as to show 
the relationship between measured or estimated amounts of emissions and 
the amounts of such emissions allowable under the applicable emission 
limitations or other measures.



Sec. 51.117  Additional provisions for lead.

    In addition to other requirements in Sec. Sec. 51.100 through 
51.116 the following requirements apply to lead. To the extent they 
conflict, there requirements are controlling over those of the 
proceeding sections.
    (a) Control strategy demonstration. Each plan must contain a 
demonstration showing that the plan will attain and maintain the 
standard in the following areas:
    (1) Areas in the vicinity of the following point sources of lead: 
Primary lead smelters, Secondary lead smelters, Primary copper smelters, 
Lead gasoline additive plants, Lead-acid storage battery manufacturing 
plants that produce 2,000 or more batteries per day. Any other 
stationary source that actually emits 25 or more tons per year of lead 
or lead compounds measured as elemental lead.
    (2) Any other area that has lead air concentrations in excess of the 
national ambient air quality standard concentration for lead, measured 
since January 1, 1974.
    (b) Time period for demonstration of adequacy. The demonstration of 
adequacy of the control strategy required under Sec. 51.112 may cover a 
longer period if allowed by the appropriate EPA Regional Administrator.
    (c) Special modeling provisions. (1) For urbanized areas with 
measured lead concentrations in excess of 4.0 [micro]g/m\3\, quarterly 
mean measured since January 1, 1974, the plan must employ the modified 
rollback model for the demonstration of attainment as a minimum, but may 
use an atmospheric dispersion model if desired, consistent with 
requirements contained in Sec. 51.112(a). If a proportional model is 
used, the air quality data should be the same year as the emissions 
inventory required under the paragraph e.
    (2) For each point source listed in Sec. 51.117(a), that plan must 
employ an atmospheric dispersion model for demonstration of attainment, 
consistent with requirements contained in Sec. 51.112(a).
    (3) For each area in the vicinity of an air quality monitor that has 
recorded lead concentrations in excess of the lead national standard 
concentration, the plan must employ the modified rollback model as a 
minimum, but may use an atmospheric dispersion model if desired for the 
demonstration of attainment, consistent with requirements contained in 
Sec. 51.112(a).
    (d) Air quality data and projections. (1) Each State must submit to 
the appropriate EPA Regional Office with the plan, but not part of the 
plan, all lead air quality data measured since January 1, 1974. This 
requirement does not apply if the data has already been submitted.
    (2) The data must be submitted in accordance with the procedures and 
data forms specified in Chapter 3.4.0 of the ``AEROS User's Manual'' 
concerning storage and retrieval of aerometric data (SAROAD) except 
where the Regional Administrator waives this requirement.
    (3) If additional lead air quality data are desired to determine 
lead air concentrations in areas suspected of exceeding the lead 
national ambient air quality standard, the plan may include data from 
any previously collected filters from particulate matter high volume 
samplers. In determining the lead content of the filters for control 
strategy demonstration purposes, a State may use, in addition to the 
reference method, X-ray fluorescence or any other method approved by the 
Regional Administrator.
    (e) Emissions data. (1) The point source inventory on which the 
summary of the baseline lead emissions inventory is based must contain 
all sources that emit five or more tons of lead per year.
    (2) Each State must submit lead emissions data to the appropriate 
EPA Regional Office with the original plan. The submission must be made 
with the plan, but not as part of the plan, and must include emissions 
data and information related to point and area source emissions. The 
emission data and information should include the information identified 
in the Hazardous

[[Page 141]]

and Trace Emissions System (HATREMS) point source coding forms for all 
point sources and the area source coding forms for all sources that are 
not point sources, but need not necessarily be in the format of those 
forms.

[41 FR 18388, May 3, 1976, as amended at 58 FR 38822, July 20, 1993]



Sec. 51.118  Stack height provisions.

    (a) The plan must provide that the degree of emission limitation 
required of any source for control of any air pollutant must not be 
affected by so much of any source's stack height that exceeds good 
engineering practice or by any other dispersion technique, except as 
provided in Sec. 51.118(b). The plan must provide that before a State 
submits to EPA a new or revised emission limitation that is based on a 
good engineering practice stack height that exceeds the height allowed 
by Sec. 51.100(ii) (1) or (2), the State must notify the public of the 
availabilty of the demonstration study and must provide opportunity for 
a public hearing on it. This section does not require the plan to 
restrict, in any manner, the actual stack height of any source.
    (b) The provisions of Sec. 51.118(a) shall not apply to (1) stack 
heights in existence, or dispersion techniques implemented on or before 
December 31, 1970, except where pollutants are being emitted from such 
stacks or using such dispersion techniques by sources, as defined in 
section 111(a)(3) of the Clean Air Act, which were constructed, or 
reconstructed, or for which major modifications, as defined in 
Sec. Sec. 51.165(a)(1)(v)(A), 51.166(b)(2)(i) and 52.21(b)(2)(i), were 
carried out after December 31, 1970; or (2) coal-fired steam electric 
generating units subject to the provisions of section 118 of the Clean 
Air Act, which commenced operation before July 1, 1957, and whose stacks 
were construced under a construction contract awarded before February 8, 
1974.



Sec. 51.119  Intermittent control systems.

    (a) The use of an intermittent control system (ICS) may be taken 
into account in establishing an emission limitation for a pollutant 
under a State implementation plan, provided:
    (1) The ICS was implemented before December 31, 1970, according to 
the criteria specified in Sec. 51.119(b).
    (2) The extent to which the ICS is taken into account is limited to 
reflect emission levels and associated ambient pollutant concentrations 
that would result if the ICS was the same as it was before December 31, 
1970, and was operated as specified by the operating system of the ICS 
before December 31, 1970.
    (3) The plan allows the ICS to compensate only for emissions from a 
source for which the ICS was implemented before December 31, 1970, and, 
in the event the source has been modified, only to the extent the 
emissions correspond to the maximum capacity of the source before 
December 31, 1970. For purposes of this paragraph, a source for which 
the ICS was implemented is any particular structure or equipment the 
emissions from which were subject to the ICS operating procedures.
    (4) The plan requires the continued operation of any constant 
pollution control system which was in use before December 31, 1970, or 
the equivalent of that system.
    (5) The plan clearly defines the emission limits affected by the ICS 
and the manner in which the ICS is taken into account in establishing 
those limits.
    (6) The plan contains requirements for the operation and maintenance 
of the qualifying ICS which, together with the emission limitations and 
any other necessary requirements, will assure that the national ambient 
air quality standards and any applicable prevention of significant 
deterioration increments will be attained and maintained. These 
requirements shall include, but not necessarily be limited to, the 
following:
    (i) Requirements that a source owner or operator continuously 
operate and maintain the components of the ICS specified at Sec. 
51.119(b)(3) (ii)-(iv) in a manner which assures that the ICS is at 
least as effective as it was before December 31, 1970. The air quality 
monitors and meteorological instrumentation specified at Sec. 51.119(b) 
may be operated by a local authority or other entity provided the source 
has ready access

[[Page 142]]

to the data from the monitors and instrumentation.
    (ii) Requirements which specify the circumstances under which, the 
extent to which, and the procedures through which, emissions shall be 
curtailed through the activation of ICS.
    (iii) Requirements for recordkeeping which require the owner or 
operator of the source to keep, for periods of at least 3 years, records 
of measured ambient air quality data, meteorological information 
acquired, and production data relating to those processes affected by 
the ICS.
    (iv) Requirements for reporting which require the owner or operator 
of the source to notify the State and EPA within 30 days of a NAAQS 
violation pertaining to the pollutant affected by the ICS.
    (7) Nothing in this paragraph affects the applicability of any new 
source review requirements or new source performance standards contained 
in the Clean Air Act or 40 CFR subchapter C. Nothing in this paragraph 
precludes a State from taking an ICS into account in establishing 
emission limitations to any extent less than permitted by this 
paragraph.
    (b) An intermittent control system (ICS) may be considered 
implemented for a pollutant before December 31, 1970, if the following 
criteria are met:
    (1) The ICS must have been established and operational with respect 
to that pollutant prior to December 31, 1970, and reductions in 
emissions of that pollutant must have occurred when warranted by 
meteorological and ambient monitoring data.
    (2) The ICS must have been designed and operated to meet an air 
quality objective for that pollutant such as an air quality level or 
standard.
    (3) The ICS must, at a minimum, have included the following 
components prior to December 31, 1970:
    (i) Air quality monitors. An array of sampling stations whose 
location and type were consistent with the air quality objective and 
operation of the system.
    (ii) Meteorological instrumentation. A meteorological data 
acquisition network (may be limited to a single station) which provided 
meteorological prediction capabilities sufficient to determine the need 
for, and degree of, emission curtailments necessary to achieve the air 
quality design objective.
    (iii) Operating system. A system of established procedures for 
determining the need for curtailments and for accomplishing such 
curtailments. Documentation of this system, as required by paragraph 
(n)(4), may consist of a compendium of memoranda or comparable material 
which define the criteria and procedures for curtailments and which 
identify the type and number of personnel authorized to initiate 
curtailments.
    (iv) Meteorologist. A person, schooled in meteorology, capable of 
interpreting data obtained from the meteorological network and qualified 
to forecast meteorological incidents and their effect on ambient air 
quality. Sources may have obtained meteorological services through a 
consultant. Services of such a consultant could include sufficient 
training of source personnel for certain operational procedures, but not 
for design, of the ICS.
    (4) Documentation sufficient to support the claim that the ICS met 
the criteria listed in this paragraph must be provided. Such 
documentation may include affidavits or other documentation.



Sec. 51.120  Requirements for State Implementation Plan revisions 
relating to new motor vehicles.

    (a) The EPA Administrator finds that the State Implementation Plans 
(SIPs) for the States of Connecticut, Delaware, Maine, Maryland, 
Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode 
Island, and Vermont, the portion of Virginia included (as of November 
15, 1990) within the Consolidated Metropolitan Statistical Area that 
includes the District of Columbia, are substantially inadequate to 
comply with the requirements of section 110(a)(2)(D) of the Clean Air 
Act, 42 U.S.C. 7410(a)(2)(D), and to mitigate adequately the interstate 
pollutant transport described in section 184 of the Clean Air Act, 42 
U.S.C. 7511C, to the extent that they do not provide for emission 
reductions from new motor vehicles in the amount that would be

[[Page 143]]

achieved by the Ozone Transport Commission low emission vehicle (OTC 
LEV) program described in paragraph (c) of this section. This inadequacy 
will be deemed cured for each of the aforementioned States (including 
the District of Columbia) in the event that EPA determines through 
rulemaking that a national LEV-equivalent new motor vehicle emission 
control program is an acceptable alternative for OTC LEV and finds that 
such program is in effect. In the event no such finding is made, each of 
those States must adopt and submit to EPA by February 15, 1996 a SIP 
revision meeting the requirements of paragraph (b) of this section in 
order to cure the SIP inadequacy.
    (b) If a SIP revision is required under paragraph (a) of this 
section, it must contain the OTC LEV program described in paragraph (c) 
of this section unless the State adopts and submits to EPA, as a SIP 
revision, other emission-reduction measures sufficient to meet the 
requirements of paragraph (d) of this section. If a State adopts and 
submits to EPA, as a SIP revision, other emission-reduction measures 
pursuant to paragraph (d) of this section, then for purposes of 
determining whether such a SIP revision is complete within the meaning 
of section 110(k)(1) (and hence is eligible at least for consideration 
to be approved as satisfying paragraph (d) of this section), such a SIP 
revision must contain other adopted emission-reduction measures that, 
together with the identified potentially broadly practicable measures, 
achieve at least the minimum level of emission reductions that could 
potentially satisfy the requirements of paragraph (d) of this section. 
All such measures must be fully adopted and enforceable.
    (c) The OTC LEV program is a program adopted pursuant to section 177 
of the Clean Air Act.
    (1) The OTC LEV program shall contain the following elements:
    (i) It shall apply to all new 1999 and later model year passenger 
cars and light-duty trucks (0-5750 pounds loaded vehicle weight), as 
defined in Title 13, California Code of Regulations, section 1900(b)(11) 
and (b)(8), respectively, that are sold, imported, delivered, purchased, 
leased, rented, acquired, received, or registered in any area of the 
State that is in the Northeast Ozone Transport Region as of December 19, 
1994.
    (ii) All vehicles to which the OTC LEV program is applicable shall 
be required to have a certificate from the California Air Resources 
Board (CARB) affirming compliance with California standards.
    (iii) All vehicles to which this LEV program is applicable shall be 
required to meet the mass emission standards for Non-Methane Organic 
Gases (NMOG), Carbon Monoxide (CO), Oxides of Nitrogen (NOX), 
Formaldehyde (HCHO), and particulate matter (PM) as specified in Title 
13, California Code of Regulations, section 1960.1(f)(2) (and 
formaldehyde standards under section 1960.1(e)(2), as applicable) or as 
specified by California for certification as a TLEV (Transitional Low-
Emission Vehicle), LEV (Low-Emission Vehicle), ULEV (Ultra-Low-Emission 
Vehicle), or ZEV (Zero-Emission Vehicle) under section 1960.1(g)(1) (and 
section 1960.1(e)(3), for formaldehyde standards, as applicable).
    (iv) All manufacturers of vehicles subject to the OTC LEV program 
shall be required to meet the fleet average NMOG exhaust emission values 
for production and delivery for sale of their passenger cars, light-duty 
trucks 0-3750 pounds loaded vehicle weight, and light-duty trucks 3751-
5750 pounds loaded vehicle weight specified in Title 13, California Code 
of Regulations, section 1960.1(g)(2) for each model year beginning in 
1999. A State may determine not to implement the NMOG fleet average in 
the first model year of the program if the State begins implementation 
of the program late in a calendar year. However, all States must 
implement the NMOG fleet average in any full model years of the LEV 
program.
    (v) All manufacturers shall be allowed to average, bank and trade 
credits in the same manner as allowed under the program specified in 
Title 13, California Code of Regulations, section 1960.1(g)(2) footnote 
7 for each model year beginning in 1999. States may account for credits 
banked by manufacturers in California or New York in years immediately 
preceding model year 1999, in a manner consistent with

[[Page 144]]

California banking and discounting procedures.
    (vi) The provisions for small volume manufacturers and intermediate 
volume manufacturers, as applied by Title 13, California Code of 
Regulations to California's LEV program, shall apply. Those 
manufacturers defined as small volume manufacturers and intermediate 
volume manufacturers in California under California's regulations shall 
be considered small volume manufacturers and intermediate volume 
manufacturers under this program.
    (vii) The provisions for hybrid electric vehicles (HEVs), as defined 
in Title 13 California Code of Regulations, section 1960.1, shall apply 
for purposes of calculating fleet average NMOG values.
    (viii) The provisions for fuel-flexible vehicles and dual-fuel 
vehicles specified in Title 13, California Code of Regulations, section 
1960.1(g)(1) footnote 4 shall apply.
    (ix) The provisions for reactivity adjustment factors, as defined by 
Title 13, California Code of Regulations, shall apply.
    (x) The aforementioned State OTC LEV standards shall be identical to 
the aforementioned California standards as such standards exist on 
December 19, 1994.
    (xi) All States' OTC LEV programs must contain any other provisions 
of California's LEV program specified in Title 13, California Code of 
Regulations necessary to comply with section 177 of the Clean Air Act.
    (2) States are not required to include the mandate for production of 
ZEVs specified in Title 13, California Code of Regulations, section 
1960.1(g)(2) footnote 9.
    (3) Except as specified elsewhere in this section, States may 
implement the OTC LEV program in any manner consistent with the Act that 
does not decrease the emissions reductions or jeopardize the 
effectiveness of the program.
    (d) The SIP revision that paragraph (b) of this section describes as 
an alternative to the OTC LEV program described in paragraph (c) of this 
section must contain a set of State-adopted measures that provides at 
least the following amount of emission reductions in time to bring 
serious ozone nonattainment areas into attainment by their 1999 
attainment date:
    (1) Reductions at least equal to the difference between:
    (i) The nitrogen oxides (NOX) emission reductions from 
the 1990 statewide emissions inventory achievable through implementation 
of all of the Clean Air Act-mandated and potentially broadly practicable 
control measures throughout all portions of the State that are within 
the Northeast Ozone Transport Region created under section 184(a) of the 
Clean Air Act as of December 19, 1994; and
    (ii) A reduction in NOX emissions from the 1990 statewide 
inventory in such portions of the State of 50% or whatever greater 
reduction is necessary to prevent significant contribution to 
nonattainment in, or interference with maintenance by, any downwind 
State.
    (2) Reductions at least equal to the difference between:
    (i) The VOC emission reductions from the 1990 statewide emissions 
inventory achievable through implementation of all of the Clean Air Act-
mandated and potentially broadly practicable control measures in all 
portions of the State in, or near and upwind of, any of the serious or 
severe ozone nonattainment areas lying in the series of such areas 
running northeast from the Washington, DC, ozone nonattainment area to 
and including the Portsmouth, New Hampshire ozone nonattainment area; 
and
    (ii) A reduction in VOC emissions from the 1990 emissions inventory 
in all such areas of 50% or whatever greater reduction is necessary to 
prevent significant contribution to nonattainment in, or interference 
with maintenance by, any downwind State.

[60 FR 4736, Jan. 24, 1995]



Sec. 51.121  Findings and requirements for submission of State 
implementation plan revisions relating to emissions of oxides of nitrogen.

    (a)(1) The Administrator finds that the State implementation plan 
(SIP) for each jurisdiction listed in paragraph (c) of this section is 
substantially inadequate to comply with the requirements of section 
110(a)(2)(D)(i)(I) of the Clean Air Act

[[Page 145]]

(CAA), 42 U.S.C. 7410(a)(2)(D)(i)(I), because the SIP does not include 
adequate provisions to prohibit sources and other activities from 
emitting nitrogen oxides (``NOX'') in amounts that will 
contribute significantly to nonattainment in one or more other States 
with respect to the 1-hour ozone national ambient air quality standards 
(NAAQS). Each of the jurisdictions listed in paragraph (c) of this 
section must submit to EPA a SIP revision that cures the inadequacy.
    (2) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each jurisdiction listed in paragraph (c) 
of this section must submit a SIP revision to comply with the 
requirements of section 110(a)(2)(D)(i)(I), 42 U.S.C. 
7410(a)(2)(D)(i)(I), through the adoption of adequate provisions 
prohibiting sources and other activities from emitting NOX in 
amounts that will contribute significantly to nonattainment in, or 
interfere with maintenance by, one or more other States with respect to 
the 8-hour ozone NAAQS.
    (3)(i) For purposes of this section, the term ``Phase I SIP 
Submission'' means those SIP revisions submitted by States on or before 
October 30, 2000 in compliance with paragraph (b)(1)(ii) of this 
section. A State's Phase I SIP submission may include portions of the 
NOX budget, under paragraph (e)(3) of this section, that a 
State is required to include in a Phase II SIP submission.
    (ii) For purposes of this section, the term ``Phase II SIP 
Submission'' means those SIP revisions that must be submitted by a State 
in compliance with paragraph (b)(1)(ii) of this section and which 
includes portions of the NOX budget under paragraph (e)(3) of 
this section.
    (b)(1) For each jurisdiction listed in paragraph (c) of this 
section, the SIP revision required under paragraph (a) of this section 
will contain adequate provisions, for purposes of complying with section 
110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if 
the SIP revision:
    (i) Contains control measures adequate to prohibit emissions of 
NOX that would otherwise be projected, in accordance with 
paragraph (g) of this section, to cause the jurisdiction's overall 
NOX emissions to be in excess of the budget for that 
jurisdiction described in paragraph (e) of this section (except as 
provided in paragraph (b)(2) of this section),
    (ii) Requires full implementation of all such control measures by no 
later than May 31, 2004 for the sources covered by a Phase I SIP 
submission and May 1, 2007 for the sources covered by a Phase II SIP 
submission.
    (iii) Meets the other requirements of this section. The SIP 
revision's compliance with the requirement of paragraph (b)(1)(i) of 
this section shall be considered compliance with the jurisdiction's 
budget for purposes of this section.
    (2) The requirements of paragraph (b)(1)(i) of this section shall be 
deemed satisfied, for the portion of the budget covered by an interstate 
trading program, if the SIP revision:
    (i) Contains provisions for an interstate trading program that EPA 
determines will, in conjunction with interstate trading programs for one 
or more other jurisdictions, prohibit NOX emissions in excess 
of the sum of the portion of the budgets covered by the trading programs 
for those jurisdictions; and
    (ii) Conforms to the following criteria:
    (A) Emissions reductions used to demonstrate compliance with the 
revision must occur during the ozone season.
    (B) Emissions reductions occurring prior to the first year in which 
any sources covered by Phase I or Phase II SIP submission are subject to 
control measures under paragraph (b)(1)(i) of this section may be used 
by a source to demonstrate compliance with the SIP revision for the 
first and second ozone seasons in which any sources covered by a Phase I 
or Phase II SIP submission are subject to such control measures, 
provided the SIPs provisions regarding such use comply with the 
requirements of paragraph (e)(4) of this section.
    (C) Emissions reductions credits or emissions allowances held by a 
source or other person following the first

[[Page 146]]

ozone season in which any sources covered by a Phase I or Phase II SIP 
submission are subject to control measures under paragraph (b)(1)(i) of 
this section or any ozone season thereafter that are not required to 
demonstrate compliance with the SIP for the relevant ozone season may be 
banked and used to demonstrate compliance with the SIP in a subsequent 
ozone season.
    (D) Early reductions created according to the provisions in 
paragraph (b)(2)(ii)(B) of this section and used in the first ozone 
season in which any sources covered by Phase I or Phase II submissions 
are subject to the control measures under paragraph (b)(1)(i) of this 
section are not subject to the flow control provisions set forth in 
paragraph (b)(2)(ii)(E) of this section.
    (E) Starting with the second ozone season in which any sources 
covered by a Phase I or Phase II SIP submission are subject to control 
measures under paragraph (b)(1)(i) of this section, the SIP shall 
include provisions to limit the use of banked emissions reductions 
credits or emissions allowances beyond a predetermined amount as 
calculated by one of the following approaches:
    (1) Following the determination of compliance after each ozone 
season, if the total number of emissions reduction credits or banked 
allowances held by sources or other persons subject to the trading 
program exceeds 10 percent of the sum of the allowable ozone season 
NOX emissions for all sources subject to the trading program, 
then all banked allowances used for compliance for the following ozone 
season shall be subject to the following:
    (i) A ratio will be established according to the following formula: 
(0.10) x (the sum of the allowable ozone season NOX emissions 
for all sources subject to the trading program) / (the total number of 
banked emissions reduction credits or emissions allowances held by all 
sources or other persons subject to the trading program).
    (ii) The ratio, determined using the formula specified in paragraph 
(b)(2)(ii)(E)(1)(i) of this section, will be multiplied by the number of 
banked emissions reduction credits or emissions allowances held in each 
account at the time of compliance determination. The resulting product 
is the number of banked emissions reduction credits or emissions 
allowances in the account which can be used in the current year's ozone 
season at a rate of 1 credit or allowance for every 1 ton of emissions. 
The SIP shall specify that banked emissions reduction credits or 
emissions allowances in excess of the resulting product either may not 
be used for compliance, or may only be used for compliance at a rate no 
less than 2 credits or allowances for every 1 ton of emissions.
    (2) At the time of compliance determination for each ozone season, 
if the total number of banked emissions reduction credits or emissions 
allowances held by a source subject to the trading program exceeds 10 
percent of the source's allowable ozone season NOX emissions, 
all banked emissions reduction credits or emissions allowances used for 
compliance in such ozone season by the source shall be subject to the 
following:
    (i) The source may use an amount of banked emissions reduction 
credits or emissions allowances not greater than 10 percent of the 
source's allowable ozone season NOX emissions for compliance 
at a rate of 1 credit or allowance for every 1 ton of emissions.
    (ii) The SIP shall specify that banked emissions reduction credits 
or emissions allowances in excess of 10 percent of the source's 
allowable ozone season NOX emissions may not be used for 
compliance, or may only be used for compliance at a rate no less than 2 
credits or allowances for every 1 ton of emissions.
    (c) The following jurisdictions (hereinafter referred to as 
``States'') are subject to the requirement of this section:
    (1) With respect to the 1-hour ozone NAAQS: Connecticut, Delaware, 
Illinois, Indiana, Kentucky, Maryland, Massachusetts, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, 
Tennessee, Virginia, West Virginia, and the District of Columbia.
    (2) With respect to the 1-hour ozone NAAQS, the portions of 
Missouri, Michigan, Alabama, and Georgia within the fine grid of the 
OTAG modeling domain. The fine grid is the area encompassed by a box 
with the following

[[Page 147]]

geographic coordinates: Southwest Corner, 92 degrees West longitude and 
32 degrees North latitude; and Northeast Corner, 69.5 degrees West 
longitude and 44 degrees North latitude.
    (d)(1) The SIP submissions required under paragraph (a) of this 
section must be submitted to EPA by no later than October 30, 2000 for 
Phase I SIP submissions and no later than April 1, 2005 for Phase II SIP 
submissions.
    (2) The State makes an official submission of its SIP revision to 
EPA only when:
    (i) The submission conforms to the requirements of appendix V to 
this part; and
    (ii) The State delivers five copies of the plan to the appropriate 
Regional Office, with a letter giving notice of such action.
    (e)(1) Except as provided in paragraph (e)(2)(ii) of this section, 
the NOX budget for a State listed in paragraph (c) of this 
section is defined as the total amount of NOX emissions from 
all sources in that State, as indicated in paragraph (e)(2)(i) of this 
section with respect to that State, which the State must demonstrate 
that it will not exceed in the 2007 ozone season pursuant to paragraph 
(g)(1) of this section.
    (2)(i) The State-by-State amounts of the NOX budget, 
expressed in tons, are as follows:

------------------------------------------------------------------------
                      State                          Final budget   Budget
------------------------------------------------------------------ --------
Alabama..........................................          119,827
Connecticut......................................           42,850
Delaware.........................................           22,862
District of Columbia.............................            6,657
Georgia..........................................          150,656
Illinois.........................................          271,091
Indiana..........................................          230,381
Kentucky.........................................          162,519
Maryland.........................................           81,947
Massachusetts....................................           84,848
Michigan.........................................          190,908
Missouri.........................................           61,406
New Jersey.......................................           96,876
New York.........................................          240,322
North Carolina...................................          165,306
Ohio.............................................          249,541
Pennsylvania.....................................          257,928
Rhode Island.....................................            9,378
South Carolina...................................          123,496
Tennessee........................................          198,286
Virginia.........................................          180,521
West Virginia....................................           83,921
                                                  ------------------
  Total..........................................       $3,031,527
------------------------------------------------------------------------

    (ii) (A) For purposes of paragraph (e)(2)(i) of this section, in the 
case of each State listed in paragraphs (e)(2)(ii)(B) through (E) of 
this section, the NOX budget is defined as the total amount 
of NOX emissions from all sources in the specified counties 
in that State, as indicated in paragraph (e)(2)(i) of this section with 
respect to the State, which the State must demonstrate that it will not 
exceed in the 2007 ozone season pursuant to paragraph (g)(1) of this 
section.
    (B) In the case of Alabama, the counties are: Autauga, Bibb, Blount, 
Calhoun, Chambers, Cherokee, Chilton, Clay, Cleburne, Colbert, Coosa, 
Cullman, Dallas, De Kalb, Elmore, Etowah, Fayette, Franklin, Greene, 
Hale, Jackson, Jefferson, Lamar, Lauderdale, Lawrence, Lee, Limestone, 
Macon, Madison, Marion, Marshall, Morgan, Perry, Pickens, Randolph, 
Russell, St. Clair, Shelby, Sumter, Talladega, Tallapoosa, Tuscaloosa, 
Walker, and Winston.
    (C) In the case of Georgia, the counties are: Baldwin, Banks, 
Barrow, Bartow, Bibb, Bleckley, Bulloch, Burke, Butts, Candler, Carroll, 
Catoosa, Chattahoochee, Chattooga, Cherokee, Clarke, Clayton, Cobb, 
Columbia, Coweta, Crawford, Dade, Dawson, De Kalb, Dooly, Douglas, 
Effingham, Elbert, Emanuel, Evans, Fannin, Fayette, Floyd, Forsyth, 
Franklin, Fulton, Gilmer, Glascock, Gordon, Greene, Gwinnett, Habersham, 
Hall, Hancock, Haralson, Harris, Hart, Heard, Henry, Houston, Jackson, 
Jasper, Jefferson, Jenkins, Johnson, Jones, Lamar, Laurens, Lincoln, 
Lumpkin, McDuffie, Macon, Madison, Marion, Meriwether, Monroe, Morgan, 
Murray, Muscogee, Newton, Oconee, Oglethorpe, Paulding, Peach, Pickens, 
Pike, Polk, Pulaski, Putnam, Rabun, Richmond, Rockdale, Schley, Screven, 
Spalding, Stephens, Talbot, Taliaferro, Taylor, Towns, Treutlen, Troup, 
Twiggs, Union, Upson, Walker, Walton, Warren, Washington, White, 
Whitfield, Wilkes, and Wilkinson.
    (D) In the case of Michigan, the counties are: Allegan, Barry, Bay, 
Berrien, Branch, Calhoun, Cass, Clinton, Eaton, Genesee, Gratiot, 
Hillsdale, Ingham, Ionia, Isabella, Jackson, Kalamazoo, Kent, Lapeer, 
Lenawee, Livingston, Macomb, Mecosta, Midland, Monroe, Montcalm, 
Muskegon, Newaygo, Oakland, Oceana, Ottawa, Saginaw, St.

[[Page 148]]

Clair, St. Joseph, Sanilac, Shiawassee, Tuscola, Van Buren, Washtenaw, 
and Wayne.
    (E) In the case of Missouri, the counties are: Bollinger, Butler, 
Cape Girardeau, Carter, Clark, Crawford, Dent, Dunklin, Franklin, 
Gasconade, Iron, Jefferson, Lewis, Lincoln, Madison, Marion, 
Mississippi, Montgomery, New Madrid, Oregon, Pemiscot, Perry, Pike, 
Ralls, Reynolds, Ripley, St. Charles, St. Genevieve, St. Francois, St. 
Louis, St. Louis City, Scott, Shannon, Stoddard, Warren, Washington, and 
Wayne.
    (3) The State-by-State amounts of the portion of the NOX 
budget provided in paragraph (e)(1) of this section, expressed in tons, 
that the States may include in a Phase II SIP submission are as follows:

------------------------------------------------------------------------
                                                             Phase II
                         State                             incremental
                                                              budget
------------------------------------------------------------------------
Alabama................................................            4,968
Connecticut............................................               41
Delaware...............................................              660
District of Columbia...................................                1
Illinois...............................................            7,055
Indiana................................................            4,244
Kentucky...............................................            2,556
Maryland...............................................              780
Massachusetts..........................................            1,023
Michigan...............................................            1,033
New Jersey.............................................             -994
New York...............................................            1,659
North Carolina.........................................            6,026
Ohio...................................................            2,741
Pennsylvania...........................................           10,230
Rhode Island...........................................              192
South Carolina.........................................            4,260
Tennessee..............................................            2,877
Virginia...............................................            6,168
West Virginia..........................................            1,124
                                                        ----------------
    Total..............................................           56,644
------------------------------------------------------------------------

    (4)(i) Notwithstanding the State's obligation to comply with the 
budgets set forth in paragraph (e)(2) of this section, a SIP revision 
may allow sources required by the revision to implement NOX 
emission control measures to demonstrate compliance in the first and 
second ozone seasons in which any sources covered by a Phase I or Phase 
II SIP submission are subject to control measures under paragraph 
(b)(1)(i) of this section using credit issued from the State's 
compliance supplement pool, as set forth in paragraph (e)(4)(iii) of 
this section.
    (ii) A source may not use credit from the compliance supplement pool 
to demonstrate compliance after the second ozone season in which any 
sources are covered by a Phase I or Phase II SIP submission.
    (iii) The State-by-State amounts of the compliance supplement pool 
are as follows:

------------------------------------------------------------------------
                                                            Compliance
                         State                           supplement pool
                                                           (tons of NOX)
------------------------------------------------------------------------
Alabama................................................            8,962
Connecticut............................................              569
Delaware...............................................              168
District of Columbia...................................                0
Georgia................................................           10,728
Illinois...............................................           17,688
Indiana................................................           19,915
Kentucky...............................................           13,520
Maryland...............................................            3,882
Massachusetts..........................................              404
Michigan...............................................            9,907
Missouri...............................................            5,630
New Jersey.............................................            1,550
New York...............................................            2,764
North Carolina.........................................           10,737
Ohio...................................................           22,301
Pennsylvania...........................................           15,763
Rhode Island...........................................               15
South Carolina.........................................            5,344
Tennessee..............................................           10,565
Virginia...............................................            5,504
West Virginia..........................................           16,709
                                                        ----------------
  Total................................................          182,625
------------------------------------------------------------------------

    (iv) The SIP revision may provide for the distribution of the 
compliance supplement pool to sources that are required to implement 
control measures using one or both of the following two mechanisms:
    (A) The State may issue some or all of the compliance supplement 
pool to sources that implement emissions reductions during the ozone 
season beyond all applicable requirements in the first ozone season in 
which any sources covered by a Phase I or Phase II SIP submission are 
subject to control measures under paragraph (b)(1)(i) of this section.
    (1) The State shall complete the issuance process by no later than 
the commencement of the first ozone season in which any sources covered 
by a Phase I or Phase II SIP submission are subject to control measures 
under paragraph (b)(1)(i) of this section.
    (2) The emissions reduction may not be required by the State's SIP 
or be otherwise required by the CAA.

[[Page 149]]

    (3) The emissions reductions must be verified by the source as 
actually having occurred during an ozone season between September 30, 
1999 and the commencement of the first ozone season in which any sources 
covered by a Phase I or Phase II SIP submission are subject to control 
measures under paragraph (b)(1)(i) of this section.
    (4) The emissions reduction must be quantified according to 
procedures set forth in the SIP revision and approved by EPA. Emissions 
reductions implemented by sources serving electric generators with a 
nameplate capacity greater than 25 MWe, or boilers, combustion turbines 
or combined cycle units with a maximum design heat input greater than 
250 mmBtu/hr, must be quantified according to the requirements in 
paragraph (i)(4) of this section.
    (5) If the SIP revision contains approved provisions for an 
emissions trading program, sources that receive credit according to the 
requirements of this paragraph may trade the credit to other sources or 
persons according to the provisions in the trading program.
    (B) The State may issue some or all of the compliance supplement 
pool to sources that demonstrate a need for an extension of the earliest 
date on which any sources covered by a Phase I or Phase II SIP 
submission are subject to control measures under paragraph (b)(1)(i) of 
this section according to the following provisions:
    (1) The State shall initiate the issuance process by the later date 
of September 30 before the first ozone season in which any sources 
covered by a Phase I or Phase II SIP submission are subject to control 
measures under paragraph (b)(1)(i) of this section or after the State 
issues credit according to the procedures in paragraph (e)(4)(iv)(A) of 
this section.
    (2) The State shall complete the issuance process by no later than 
the commencement of the first ozone season in which any sources covered 
by a Phase I or Phase II SIP submission are subject to control measures 
under paragraph (b)(1)(i) of this section.
    (3) The State shall issue credit to a source only if the source 
demonstrates the following:
    (i) For a source used to generate electricity, compliance with the 
SIP revision's applicable control measures by the commencement of the 
first ozone season in which any sources covered by a Phase I or Phase II 
SIP submission are subject to control measures under paragraph (b)(1)(i) 
of this section, would create undue risk for the reliability of the 
electricity supply. This demonstration must include a showing that it 
would not be feasible to import electricity from other electricity 
generation systems during the installation of control technologies 
necessary to comply with the SIP revision.
    (ii) For a source not used to generate electricity, compliance with 
the SIP revision's applicable control measures by the commencement of 
the first ozone season in which any sources covered by a Phase I or 
Phase II SIP submission are subject to control measures under paragraph 
(b)(1)(i) of this section would create undue risk for the source or its 
associated industry to a degree that is comparable to the risk described 
in paragraph (e)(4)(iv)(B)(3)(i) of this section.
    (iii) For a source subject to an approved SIP revision that allows 
for early reduction credits in accordance with paragraph (e)(4)(iv)(A) 
of this section, it was not possible for the source to comply with 
applicable control measures by generating early reduction credits or 
acquiring early reduction credits from other sources.
    (iv) For a source subject to an approved emissions trading program, 
it was not possible to comply with applicable control measures by 
acquiring sufficient credit from other sources or persons subject to the 
emissions trading program.
    (4) The State shall ensure the public an opportunity, through a 
public hearing process, to comment on the appropriateness of allocating 
compliance supplement pool credits to a source under paragraph 
(e)(3)(iv)(B) of this section.
    (5) If, no later than February 22, 1999, any member of the public 
requests revisions to the source-specific data and vehicle miles 
traveled (VMT) and nonroad mobile growth rates, VMT distribution by 
vehicle class, average speed by roadway type, inspection and

[[Page 150]]

maintenance program parameters, and other input parameters used to 
establish the State budgets set forth in paragraph (e)(2) of this 
section or the 2007 baseline sub-inventory information set forth in 
paragraph (g)(2)(ii) of this section, then EPA will act on that request 
no later than April 23, 1999 provided:
    (i) The request is submitted in electronic format;
    (ii) Information is provided to corroborate and justify the need for 
the requested modification;
    (iii) The request includes the following data information regarding 
any electricity-generating source at issue:
    (A) Federal Information Placement System (FIPS) State Code;
    (B) FIPS County Code;
    (C) Plant name;
    (D) Plant ID numbers (ORIS code preferred, State agency tracking 
number also or otherwise);
    (E) Unit ID numbers (a unit is a boiler or other combustion device);
    (F) Unit type;
    (G) Primary fuel on a heat input basis;
    (H) Maximum rated heat input capacity of unit;
    (I) Nameplate capacity of the largest generator the unit serves;
    (J) Ozone season heat inputs for the years 1995 and 1996;
    (K) 1996 (or most recent) average NOX rate for the ozone 
season;
    (L) Latitude and longitude coordinates;
    (M) Stack parameter information ;
    (N) Operating parameter information;
    (O) Identification of specific change to the inventory; and
    (P) Reason for the change;
    (iv) The request includes the following data information regarding 
any non-electricity generating point source at issue:
    (A) FIPS State Code;
    (B) FIPS County Code;
    (C) Plant name;
    (D) Facility primary standard industrial classification code (SIC);
    (E) Plant ID numbers (NEDS, AIRS/AFS, and State agency tracking 
number also or otherwise);
    (F) Unit ID numbers (a unit is a boiler or other combustion device);
    (G) Primary source classification code (SCC);
    (H) Maximum rated heat input capacity of unit;
    (I) 1995 ozone season or typical ozone season daily NOX 
emissions;
    (J) 1995 existing NOX control efficiency;
    (K) Latitude and longitude coordinates;
    (L) Stack parameter information;
    (M) Operating parameter information;
    (N) Identification of specific change to the inventory; and
    (O) Reason for the change;
    (v) The request includes the following data information regarding 
any stationary area source or nonroad mobile source at issue:
    (A) FIPS State Code;
    (B) FIPS County Code;
    (C) Primary source classification code (SCC);
    (D) 1995 ozone season or typical ozone season daily NOX 
emissions;
    (E) 1995 existing NOX control efficiency;
    (F) Identification of specific change to the inventory; and
    (G) Reason for the change;
    (vi) The request includes the following data information regarding 
any highway mobile source at issue:
    (A) FIPS State Code;
    (B) FIPS County Code;
    (C) Primary source classification code (SCC) or vehicle type;
    (D) 1995 ozone season or typical ozone season daily vehicle miles 
traveled (VMT);
    (E) 1995 existing NOX control programs;
    (F) identification of specific change to the inventory; and
    (G) reason for the change.
    (f) Each SIP revision must set forth control measures to meet the 
NOX budget in accordance with paragraph (b)(1)(i) of this 
section, which include the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;
    (ii) Procedures for handling violations; and

[[Page 151]]

    (iii) A designation of agency responsibility for enforcement of 
implementation.
    (2) Should a State elect to impose control measures on fossil fuel-
fired NOX sources serving electric generators with a 
nameplate capacity greater than 25 MWe or boilers, combustion turbines 
or combined cycle units with a maximum design heat input greater than 
250 mmBtu/hr as a means of meeting its NOX budget, then those 
measures must:
    (i)(A) Impose a NOX mass emissions cap on each source;
    (B) Impose a NOX emissions rate limit on each source and 
assume maximum operating capacity for every such source for purposes of 
estimating mass NOX emissions; or
    (C) Impose any other regulatory requirement which the State has 
demonstrated to EPA provides equivalent or greater assurance than 
options in paragraphs (f)(2)(i)(A) or (f)(2)(i)(B) of this section that 
the State will comply with its NOX budget in the 2007 ozone 
season; and
    (ii) Impose enforceable mechanisms, in accordance with paragraphs 
(b)(1) (i) and (ii) of this section, to assure that collectively all 
such sources, including new or modified units, will not exceed in the 
2007 ozone season the total NOX emissions projected for such 
sources by the State pursuant to paragraph (g) of this section.
    (3) For purposes of paragraph (f)(2) of this section, the term 
``fossil fuel-fired'' means, with regard to a NOX source:
    (i) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel actually combusted comprises more than 50 
percent of the annual heat input on a Btu basis during any year starting 
in 1995 or, if a NOX source had no heat input starting in 
1995, during the last year of operation of the NOX source 
prior to 1995; or
    (ii) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel is projected to comprise more than 50 
percent of the annual heat input on a Btu basis during any year; 
provided that the NOX source shall be ``fossil fuel-fired'' 
as of the date, during such year, on which the NOX source 
begins combusting fossil fuel.
    (g)(1) Each SIP revision must demonstrate that the control measures 
contained in it are adequate to provide for the timely compliance with 
the State's NOX budget during the 2007 ozone season.
    (2) The demonstration must include the following:
    (i) Each revision must contain a detailed baseline inventory of 
NOX mass emissions from the following sources in the year 
2007, absent the control measures specified in the SIP submission: 
electric generating units (EGU), non-electric generating units (non-
EGU), area, nonroad and highway sources. The State must use the same 
baseline emissions inventory that EPA used in calculating the State's 
NOX budget, as set forth for the State in paragraph 
(g)(2)(ii) of this section, except that EPA may direct the State to use 
different baseline inventory information if the State fails to certify 
that it has implemented all of the control measures assumed in 
developing the baseline inventory.
    (ii) The revised NOX emissions sub-inventories for each 
State, expressed in tons per ozone season, are as follows:

----------------------------------------------------------------------------------------------------------------
                     State                          EGU      Non-EGU    Area     Nonroad    Highway      Total
----------------------------------------------------------------------------------------------------------------
Alabama.......................................      29,022    43,415    28,762    20,146      51,274     172,619
Connecticut...................................       2,652     5,216     4,821    10,736      19,424      42,849
Delaware......................................       5,250     2,473     1,129     5,651       8,358      22,861
District of Columbia..........................         207       282       830     3,135       2,204       6,658
Georgia.......................................      30,402    29,716    13,212    26,467      88,775     188,572
Illinois......................................      32,372    59,577     9,369    56,724     112,518     270,560
Indiana.......................................      47,731    47,363    29,070    26,494      79,307     229,965
Kentucky......................................      36,503    25,669    31,807    15,025      53,268     162,272
Maryland......................................      14,656    12,585     4,448    20,026      30,183      81,898
Massachusetts.................................      15,146    10,298    11,048    20,166      28,190      84,848
Michigan......................................      32,228    60,055    31,721    26,935      78,763     229,702
Missouri......................................      24,216    21,602     7,341    20,829      51,615     125,603
New Jersey....................................      10,250    15,464    12,431    23,565      35,166      96,876
New York......................................      31,036    25,477    17,423    42,091     124,261     240,288

[[Page 152]]

 
North Carolina................................      31,821    26,434    11,067    22,005      73,695     165,022
Ohio..........................................      48,990    40,194    21,860    43,380      94,850     249,274
Pennsylvania..................................      47,469    70,132    17,842    30,571      91,578     257,592
Rhode Island..................................         997     1,635       448     2,455       3,843       9,378
South Carolina................................      16,772    27,787     9,415    14,637      54,494     123,105
Tennessee.....................................      25,814    39,636    13,333    52,920      66,342     198,045
Virginia......................................      17,187    35,216    27,738    27,859      72,195     180,195
West Virginia.................................      26,859    20,238     5,459    10,433      20,844      83,833
Wisconsin.....................................      17,381    19,853    11,253    17,965      69,319     135,771
                                               -----------------------------------------------------------------
    Total.....................................     544,961   640,317   321,827   540,215   1,310,466  3,357,786
----------------------------------------------------------------------------------------------------------------
Note to paragraph (g)(2)(ii): Totals may not sum due to rounding.

    (iii) Each revision must contain a summary of NOX mass 
emissions in 2007 projected to result from implementation of each of the 
control measures specified in the SIP submission and from all 
NOX sources together following implementation of all such 
control measures, compared to the baseline 2007 NOX emissions 
inventory for the State described in paragraph (g)(2)(i) of this 
section. The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected 2007 NOX emissions that will be achieved from the 
implementation of the new control measures compared to the baseline 
emissions inventory.
    (iv) Each revision must identify the sources of the data used in the 
projection of emissions.
    (h) Each revision must comply with Sec. 51.116 of this part 
(regarding data availability).
    (i) Each revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the NOX 
budget. Specifically, the revision must meet the following requirements:
    (1) The revision must provide for legally enforceable procedures for 
requiring owners or operators of stationary sources to maintain records 
of and periodically report to the State:
    (i) Information on the amount of NOX emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable portions 
of the control measures;
    (2) The revision must comply with Sec. 51.212 of this part 
(regarding testing, inspection, enforcement, and complaints);
    (3) If the revision contains any transportation control measures, 
then the revision must comply with Sec. 51.213 of this part (regarding 
transportation control measures);
    (4) If the revision contains measures to control fossil fuel-fired 
NOX sources serving electric generators with a nameplate 
capacity greater than 25 MWe or boilers, combustion turbines or combined 
cycle units with a maximum design heat input greater than 250 mmBtu/hr, 
then the revision must require such sources to comply with the 
monitoring provisions of part 75, subpart H.
    (5) For purposes of paragraph (i)(4) of this section, the term 
``fossil fuel-fired'' means, with regard to a NOX source:
    (i) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel actually combusted comprises more than 50 
percent of the annual heat input on a Btu basis during any year starting 
in 1995 or, if a NOX source had no heat input starting in 
1995, during the last year of operation of the NOX source 
prior to 1995; or
    (ii) The combustion of fossil fuel, alone or in combination with any 
other fuel, where fossil fuel is projected to comprise more than 50 
percent of the annual heat input on a Btu basis during any year, 
provided that the NOX source shall be ``fossil fuel-fired'' 
as of the date, during such year, on which the NOX source 
begins combusting fossil fuel.

[[Page 153]]

    (j) Each revision must show that the State has legal authority to 
carry out the revision, including authority to:
    (1) Adopt emissions standards and limitations and any other measures 
necessary for attainment and maintenance of the State's NOX 
budget specified in paragraph (e) of this section;
    (2) Enforce applicable laws, regulations, and standards, and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources;
    (4) Require owners or operators of stationary sources to install, 
maintain, and use emissions monitoring devices and to make periodic 
reports to the State on the nature and amounts of emissions from such 
stationary sources; also authority for the State to make such data 
available to the public as reported and as correlated with any 
applicable emissions standards or limitations.
    (k)(1) The provisions of law or regulation which the State 
determines provide the authorities required under this section must be 
specifically identified, and copies of such laws or regulations must be 
submitted with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (j)(3) and (4) of this section may be delegated to the State 
under section 114 of the CAA.
    (l)(1) A revision may assign legal authority to local agencies in 
accordance with Sec. 51.232 of this part.
    (2) Each revision must comply with Sec. 51.240 of this part 
(regarding general plan requirements).
    (m) Each revision must comply with Sec. 51.280 of this part 
(regarding resources).
    (n) For purposes of the SIP revisions required by this section, EPA 
may make a finding as applicable under section 179(a)(1)-(4) of the CAA, 
42 U.S.C. 7509(a)(1)-(4), starting the sanctions process set forth in 
section 179(a) of the CAA. Any such finding will be deemed a finding 
under Sec. 52.31(c) of this part and sanctions will be imposed in 
accordance with the order of sanctions and the terms for such sanctions 
established in Sec. 52.31 of this part.
    (o) Each revision must provide for State compliance with the 
reporting requirements set forth in Sec. 51.122 of this part.
    (p)(1) Notwithstanding any other provision of this section, if a 
State adopts regulations substantively identical to 40 CFR part 96 (the 
model NOX budget trading program for SIPs), incorporates such 
part by reference into its regulations, or adopts regulations that 
differ substantively from such part only as set forth in paragraph 
(p)(2) of this section, then that portion of the State's SIP revision is 
automatically approved as satisfying the same portion of the State's 
NOX emission reduction obligations as the State projects such 
regulations will satisfy, provided that:
    (i) The State has the legal authority to take such action and to 
implement its responsibilities under such regulations, and
    (ii) The SIP revision accurately reflects the NOX 
emissions reductions to be expected from the State's implementation of 
such regulations.
    (2) If a State adopts an emissions trading program that differs 
substantively from 40 CFR part 96 in only the following respects, then 
such portion of the State's SIP revision is approved as set forth in 
paragraph (p)(1) of this section:
    (i) The State may expand the applicability provisions of the trading 
program to include units (as defined in 40 CFR 96.2) that are smaller 
than the size criteria thresholds set forth in 40 CFR 96.4(a);
    (ii) The State may decline to adopt the exemption provisions set 
forth in 40 CFR 96.4(b);
    (iii) The State may decline to adopt the opt-in provisions set forth 
in subpart I of 40 CFR part 96;
    (iv) The State may decline to adopt the allocation provisions set 
forth in subpart E of 40 CFR part 96 and may instead adopt any 
methodology for allocating NOX allowances to individual 
sources, provided that:
    (A) The State's methodology does not allow the State to allocate 
NOX allowances in excess of the total amount of

[[Page 154]]

NOX emissions which the State has assigned to its trading 
program; and
    (B) The State's methodology conforms with the timing requirements 
for submission of allocations to the Administrator set forth in 40 CFR 
96.41; and
    (v) The State may decline to adopt the early reduction credit 
provisions set forth in 40 CFR 96.55(c) and may instead adopt any 
methodology for issuing credit from the State's compliance supplement 
pool that complies with paragraph (e)(3) of this section.
    (3) If a State adopts an emissions trading program that differs 
substantively from 40 CFR part 96 other than as set forth in paragraph 
(p)(2) of this section, then such portion of the State's SIP revision is 
not automatically approved as set forth in paragraph (p)(1) of this 
section but will be reviewed by the Administrator for approvability in 
accordance with the other provisions of this section.
    (q) Stay of Findings of Significant Contribution with respect to the 
8-hour standard. Notwithstanding any other provisions of this subpart, 
the effectiveness of paragraph (a)(2) of this section is stayed.
    (r)(1) Notwithstanding any provisions of paragraph (p) of this 
section, subparts A through I of part 96 of this chapter, and any 
State's SIP to the contrary, the Administrator will not carry out any of 
the functions set forth for the Administrator in subparts A through I of 
part 96 of this chapter, or in any emissions trading program in a 
State's SIP approved under paragraph (p) of this section, with regard to 
any ozone season that occurs after September 30, 2008.
    (2) Except as provided in Sec. 51.123(bb), a State whose SIP is 
approved as meeting the requirements of this section and that includes 
an emissions trading program approved under paragraph (p) of this 
section must revise the SIP to adopt control measures that satisfy the 
same portion of the State's NOX emission reduction 
requirements under this section as the State projected such emissions 
trading program would satisfy.
    (s) Stay of Finding of Significant Contribution with respect to the 
1-hour standard. Notwithstanding any other provisions of this subpart, 
the effectiveness of paragraph (a)(1) of this section is stayed as it 
relates to the State of Georgia, only as of September 30, 2005.

[63 FR 57491, Oct. 27, 1998, as amended at 63 FR 71225, Dec. 24, 1998; 
64 FR 26305, May 14, 1999; 65 FR 11230, Mar. 2, 2000; 65 FR 56251, Sept. 
18, 2000; 69 FR 21642, Apr. 21, 2004; 70 FR 25317, May 12, 2005; 70 FR 
51597, Aug. 31, 2005]



Sec. 51.122  Emissions reporting requirements for SIP revisions relating 
to budgets for NOX emissions.

    (a) For its transport SIP revision under Sec. 51.121, each State 
must submit to EPA NOX emissions data as described in this 
section.
    (b) Each revision must provide for periodic reporting by the State 
of NOX emissions data to demonstrate whether the State's 
emissions are consistent with the projections contained in its approved 
SIP submission.
    (1) Annual reporting. Each revision must provide for annual 
reporting of NOX emissions data as follows:
    (i) The State must report to EPA emissions data from all 
NOX sources within the State for which the State specified 
control measures in its SIP submission under Sec. 51.121(g) of this 
part. This would include all sources for which the State has adopted 
measures that differ from the measures incorporated into the baseline 
inventory for the year 2007 that the State developed in accordance with 
Sec. 51.121(g).
    (ii) If sources report NOX emissions data to EPA annually 
pursuant to a trading program approved under Sec. 51.121(p) or pursuant 
to the monitoring and reporting requirements of subpart H of 40 CFR part 
75, then the State need not provide annual reporting to EPA for such 
sources.
    (2) Triennial reporting. Each plan must provide for triennial (i.e., 
every third year) reporting of NOX emissions data from all 
sources within the State.
    (3) The data availability requirements in Sec. 51.116 must be 
followed for all data submitted to meet the requirements of paragraphs 
(b)(1) and (2) of this section.
    (c) The data reported in paragraph (b) of this section for 
stationary point sources must meet the following minimum criteria:

[[Page 155]]

    (1) For annual data reporting purposes the data must include the 
following minimum elements:
    (i) Inventory year.
    (ii) State Federal Information Placement System code.
    (iii) County Federal Information Placement System code.
    (iv) Federal ID code (plant).
    (v) Federal ID code (point).
    (vi) Federal ID code (process).
    (vii) Federal ID code (stack).
    (viii) Site name.
    (ix) Physical address.
    (x) SCC.
    (xi) Pollutant code.
    (xii) Ozone season emissions.
    (xiii) Area designation.
    (2) In addition, the annual data must include the following minimum 
elements as applicable to the emissions estimation methodology.
    (i) Fuel heat content (annual).
    (ii) Fuel heat content (seasonal).
    (iii) Source of fuel heat content data.
    (iv) Activity throughput (annual).
    (v) Activity throughput (seasonal).
    (vi) Source of activity/throughput data.
    (vii) Spring throughput (%).
    (viii) Summer throughput (%).
    (ix) Fall throughput (%).
    (x) Work weekday emissions.
    (xi) Emission factor.
    (xii) Source of emission factor.
    (xiii) Hour/day in operation.
    (xiv) Operations Start time (hour).
    (xv) Day/week in operation.
    (xvi) Week/year in operation.
    (3) The triennial inventories must include the following data 
elements:
    (i) The data required in paragraphs (c)(1) and (c)(2) of this 
section.
    (ii) X coordinate (longitude).
    (iii) Y coordinate (latitude).
    (iv) Stack height.
    (v) Stack diameter.
    (vi) Exit gas temperature.
    (vii) Exit gas velocity.
    (viii) Exit gas flow rate.
    (ix) SIC.
    (x) Boiler/process throughput design capacity.
    (xi) Maximum design rate.
    (xii) Maximum capacity.
    (xiii) Primary control efficiency.
    (xiv) Secondary control efficiency.
    (xv) Control device type.
    (d) The data reported in paragraph (b) of this section for non-point 
sources must include the following minimum elements:
    (1) For annual inventories it must include:
    (i) Inventory year.
    (ii) State FIPS code.
    (iii) County FIPS code.
    (iv) SCC.
    (v) Emission factor.
    (vi) Source of emission factor.
    (vii) Activity/throughput level (annual).
    (viii) Activity throughput level (seasonal).
    (ix) Source of activity/throughput data.
    (x) Spring throughput (%).
    (xi) Summer throughput (%).
    (xii) Fall throughput (%).
    (xiii) Control efficiency (%).
    (xiv) Pollutant code.
    (xv) Ozone season emissions.
    (xvi) Source of emissions data.
    (xvii) Hour/day in operation.
    (xviii) Day/week in operation.
    (xix) Week/year in operations.
    (2) The triennial inventories must contain, at a minimum, all the 
data required in paragraph (d)(1) of this section.
    (e) The data reported in paragraph (b) of this section for mobile 
sources must meet the following minimum criteria:
    (1) For the annual and triennial inventory purposes, the following 
data must be reported:
    (i) Inventory year.
    (ii) State FIPS code.
    (iii) County FIPS code.
    (iv) SCC.
    (v) Emission factor.
    (vi) Source of emission factor.
    (vii) Activity (this must be reported for both highway and nonroad 
activity. Submit nonroad activity in the form of hours of activity at 
standard load (either full load or average load) for each engine type, 
application, and horsepower range. Submit highway activity in the form 
of vehicle miles traveled (VMT) by vehicle class on each roadway type. 
Report both highway and nonroad activity for a typical ozone season 
weekday day, if the State uses EPA's default weekday/weekend activity 
ratio. If the State uses a different weekday/weekend activity ratio, 
submit separate activity level information for weekday days and weekend 
days.)

[[Page 156]]

    (viii) Source of activity data.
    (ix) Pollutant code.
    (x) Summer work weekday emissions.
    (xi) Ozone season emissions.
    (xii) Source of emissions data.
    (2) [Reserved]
    (f) Approval of ozone season calculation by EPA. Each State must 
submit for EPA approval an example of the calculation procedure used to 
calculate ozone season emissions along with sufficient information for 
EPA to verify the calculated value of ozone season emissions.
    (g) Reporting schedules. (1) Data collection is to begin during the 
ozone season one year prior to the State's NOX SIP Call 
compliance date.
    (2) Reports are to be submitted according to paragraph (b) of this 
section and the schedule in Table 1. After 2008, trienniel reports are 
to be submitted every third year and annual reports are to be submitted 
each year that a trienniel report is not required.

                Table 1--Schedule for Submitting Reports
------------------------------------------------------------------------
            Data collection year               Type of  report required
------------------------------------------------------------------------
2002.......................................  Trienniel.
2003.......................................  Annual.
2004.......................................  Annual.
2005.......................................  Trienniel.
2006.......................................  Annual.
2007.......................................  Annual.
2008.......................................  Trienniel.
------------------------------------------------------------------------

    (3) States must submit data for a required year no later than 12 
months after the end of the calendar year for which the data are 
collected.
    (h) Data Reporting Procedures. When submitting a formal 
NOX budget emissions report and associated data, States shall 
notify the appropriate EPA Regional Office.
    (1) States are required to report emissions data in an electronic 
format to EPA. Several options are available for data reporting. States 
can obtain information on the current formats at the following Internet 
address: http://www.epa.gov/ttn/chief, by calling the EPA Info CHIEF 
help desk at (919) 541-1000 or by sending an e-mail to 
[email protected]. Because electronic reporting technology continually 
changes, States are to contact the Emission Inventory Group (EIG) for 
the latest specific formats.
    (2) For annual reporting (not for triennial reports), a State may 
have sources submit the data directly to EPA to the extent the sources 
are subject to a trading program that qualifies for approval under Sec. 
51.121(q), and the State has agreed to accept data in this format. The 
EPA will make both the raw data submitted in this format and summary 
data available to any State that chooses this option.
    (i) Definitions. As used in this section, the following words and 
terms shall have the meanings set forth below:
    (1) Annual emissions. Actual emissions for a plant, point, or 
process, either measured or calculated.
    (2) Ash content. Inert residual portion of a fuel.
    (3) Area designation. The designation of the area in which the 
reporting source is located with regard to the ozone NAAQS. This would 
include attainment or nonattainment designations. For nonattainment 
designations, the classification of the nonattainment area must be 
specified, i.e., transitional, marginal, moderate, serious, severe, or 
extreme.
    (4) Boiler design capacity. A measure of the size of a boiler, based 
on the reported maximum continuous steam flow. Capacity is calculated in 
units of MMBtu/hr.
    (5) Control device type. The name of the type of control device 
(e.g., wet scrubber, flaring, or process change).
    (6) Control efficiency. The emissions reduction efficiency of a 
primary control device, which shows the amount of reductions of a 
particular pollutant from a process's emissions due to controls or 
material change. Control efficiency is usually expressed as a percentage 
or in tenths.
    (7) Day/week in operations. Days per week that the emitting process 
operates.
    (8) Emission factor. Ratio relating emissions of a specific 
pollutant to an activity or material throughput level.
    (9) Exit gas flow rate. Numeric value of stack gas flow rate.
    (10) Exit gas temperature. Numeric value of an exit gas stream 
temperature.
    (11) Exit gas velocity. Numeric value of an exit gas stream 
velocity.

[[Page 157]]

    (12) Fall throughput (%). Portion of throughput for the 3 fall 
months (September, October, November). This represents the expression of 
annual activity information on the basis of four seasons, typically 
spring, summer, fall, and winter. It can be represented either as a 
percentage of the annual activity (e.g., production in summer is 40 
percent of the year's production), or in terms of the units of the 
activity (e.g., out of 600 units produced, spring = 150 units, summer = 
250 units, fall = 150 units, and winter = 50 units).
    (13) Federal ID code (plant). Unique codes for a plant or facility, 
containing one or more pollutant-emitting sources.
    (14) Federal ID code (point). Unique codes for the point of 
generation of emissions, typically a physical piece of equipment.
    (15) Federal ID code (stack number). Unique codes for the point 
where emissions from one or more processes are released into the 
atmosphere.
    (16) Federal Information Placement System (FIPS). The system of 
unique numeric codes developed by the government to identify States, 
counties, towns, and townships for the entire United States, Puerto 
Rico, and Guam.
    (17) Heat content. The thermal heat energy content of a solid, 
liquid, or gaseous fuel. Fuel heat content is typically expressed in 
units of Btu/lb of fuel, Btu/gal of fuel, joules/kg of fuel, etc.
    (18) Hr/day in operations. Hours per day that the emitting process 
operates.
    (19) Maximum design rate. Maximum fuel use rate based on the 
equipment's or process' physical size or operational capabilities.
    (20) Maximum nameplate capacity. A measure of the size of a 
generator which is put on the unit's nameplate by the manufacturer. The 
data element is reported in megawatts (MW) or kilowatts (KW).
    (21) Mobile source. A motor vehicle, nonroad engine or nonroad 
vehicle, where:
    (i) Motor vehicle means any self-propelled vehicle designed for 
transporting persons or property on a street or highway;
    (ii) Nonroad engine means an internal combustion engine (including 
the fuel system) that is not used in a motor vehicle or a vehicle used 
solely for competition, or that is not subject to standards promulgated 
under section 111 or section 202 of the CAA;
    (iii) Nonroad vehicle means a vehicle that is powered by a nonroad 
engine and that is not a motor vehicle or a vehicle used solely for 
competition.
    (22) Ozone season. The period May 1 through September 30 of a year.
    (23) Physical address. Street address of facility.
    (24) Point source. A non-mobile source which emits 100 tons of 
NOX or more per year unless the State designates as a point 
source a non-mobile source emitting at a specified level lower than 100 
tons of NOX per year. A non-mobile source which emits less 
NOX per year than the point source threshold is a non-point 
source.
    (25) Pollutant code. A unique code for each reported pollutant that 
has been assigned in the EIIP Data Model. Character names are used for 
criteria pollutants, while Chemical Abstracts Service (CAS) numbers are 
used for all other pollutants. Some States may be using storage and 
retrieval of aerometric data (SAROAD) codes for pollutants, but these 
should be able to be mapped to the EIIP Data Model pollutant codes.
    (26) Process rate/throughput. A measurable factor or parameter that 
is directly or indirectly related to the emissions of an air pollution 
source. Depending on the type of source category, activity information 
may refer to the amount of fuel combusted, the amount of a raw material 
processed, the amount of a product that is manufactured, the amount of a 
material that is handled or processed, population, employment, number of 
units, or miles traveled. Activity information is typically the value 
that is multiplied against an emission factor to generate an emissions 
estimate.
    (27) SCC. Source category code. A process-level code that describes 
the equipment or operation emitting pollutants.
    (28) Secondary control efficiency (%). The emissions reductions 
efficiency of a secondary control device, which shows the amount of 
reductions of a particular pollutant from a process'

[[Page 158]]

emissions due to controls or material change. Control efficiency is 
usually expressed as a percentage or in tenths.
    (29) SIC. Standard Industrial Classification code. U.S. Department 
of Commerce's categorization of businesses by their products or 
services.
    (30) Site name. The name of the facility.
    (31) Spring throughput (%). Portion of throughput or activity for 
the 3 spring months (March, April, May). See the definition of Fall 
Throughput.
    (32) Stack diameter. Stack physical diameter.
    (33) Stack height. Stack physical height above the surrounding 
terrain.
    (34) Start date (inventory year). The calendar year that the 
emissions estimates were calculated for and are applicable to.
    (35) Start time (hour). Start time (if available) that was 
applicable and used for calculations of emissions estimates.
    (36) Summer throughput (%). Portion of throughput or activity for 
the 3 summer months (June, July, August). See the definition of Fall 
Throughput.
    (37) Summer work weekday emissions. Average day's emissions for a 
typical day.
    (38) VMT by Roadway Class. This is an expression of vehicle activity 
that is used with emission factors. The emission factors are usually 
expressed in terms of grams per mile of travel. Since VMT does not 
directly correlate to emissions that occur while the vehicle is not 
moving, these non-moving emissions are incorporated into EPA's MOBILE 
model emission factors.
    (39) Week/year in operation. Weeks per year that the emitting 
process operates.
    (40) Work Weekday. Any day of the week except Saturday or Sunday.
    (41) X coordinate (longitude). An object's east-west geographical 
coordinate.
    (42) Y coordinate (latitude). An object's north-south geographical 
coordinate.

[70 FR 25317, May 12, 2005]



Sec. 51.123  Findings and requirements for submission of State 
implementation plan revisions relating to emissions of oxides of 
nitrogen pursuant to the Clean Air Interstate Rule.

    (a)(1) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each State identified in paragraph (c)(1) 
and (2) of this section must submit a SIP revision to comply with the 
requirements of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 
7410(a)(2)(D)(i)(I), through the adoption of adequate provisions 
prohibiting sources and other activities from emitting NOX in 
amounts that will contribute significantly to nonattainment in, or 
interfere with maintenance by, one or more other States with respect to 
the fine particles (PM2.5) NAAQS.
    (2)(a) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each State identified in paragraph (c)(1) 
and (3) of this section must submit a SIP revision to comply with the 
requirements of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 
7410(a)(2)(D)(i)(I), through the adoption of adequate provisions 
prohibiting sources and other activities from emitting NOX in 
amounts that will contribute significantly to nonattainment in, or 
interfere with maintenance by, one or more other States with respect to 
the 8-hour ozone NAAQS.
    (b) For each State identified in paragraph (c) of this section, the 
SIP revision required under paragraph (a) of this section will contain 
adequate provisions, for purposes of complying with section 
110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if 
the SIP revision contains control measures that assure compliance with 
the applicable requirements of this section.
    (c) In addition to being subject to the requirements in paragraphs 
(b) and (d) of this section:
    (1) Alabama, Delaware, Florida, Illinois, Indiana, Iowa, Kentucky, 
Louisiana, Maryland, Michigan, Mississippi, Missouri, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 
Virginia, West Virginia, Wisconsin, and the District of Columbia shall 
be subject to the requirements contained in paragraphs (e) through (cc) 
of this section;

[[Page 159]]

    (2) Georgia, Minnesota, and Texas shall be subject to the 
requirements in paragraphs (e) through (o) and (cc) of this section; and
    (3) Arkansas, Connecticut, and Massachusetts shall be subject to the 
requirements contained in paragraphs (q) through (cc) of this section.
    (d)(1) The State's SIP revision under paragraph (a) of this section 
must be submitted to EPA by no later than September 11, 2006.
    (2) The requirements of appendix V to this part shall apply to the 
SIP revision under paragraph (a) of this section.
    (3) The State shall deliver 5 copies of the SIP revision under 
paragraph (a) of this section to the appropriate Regional Office, with a 
letter giving notice of such action.
    (e) The State's SIP revision shall contain control measures and 
demonstrate that they will result in compliance with the State's Annual 
EGU NOX Budget, if applicable, and achieve the State's Annual 
Non-EGU NOX Reduction Requirement, if applicable, for the 
appropriate periods. The amounts of the State's Annual EGU 
NOX Budget and Annual Non-EGU NOX Reduction 
Requirement shall be determined as follows:
    (1)(i) The Annual EGU NOX Budget for the State is defined 
as the total amount of NOX emissions from all EGUs in that 
State for a year, if the State meets the requirements of paragraph 
(a)(1) of this section by imposing control measures, at least in part, 
on EGUs. If the State imposes control measures under this section on 
only EGUs, the Annual EGU NOX Budget for the State shall not 
exceed the amount, during the indicated periods, specified in paragraph 
(e)(2) of this section.
    (ii) The Annual Non-EGU NOX Reduction Requirement, if 
applicable, is defined as the total amount of NOX emission 
reductions that the State demonstrates, in accordance with paragraph (g) 
of this section, it will achieve from non-EGUs during the appropriate 
period. If the State meets the requirements of paragraph (a)(1) of this 
section by imposing control measures on only non-EGUs, then the State's 
Annual Non-EGU NOX Reduction Requirement shall equal or 
exceed, during the appropriate periods, the amount determined in 
accordance with paragraph (e)(3) of this section.
    (iii) If a State meets the requirements of paragraph (a)(1) of this 
section by imposing control measures on both EGUs and non-EGUs, then:
    (A) The Annual Non-EGU NOX Reduction Requirement shall 
equal or exceed the difference between the amount specified in paragraph 
(e)(2) of this section for the appropriate period and the amount of the 
State's Annual EGU NOX Budget specified in the SIP revision 
for the appropriate period; and
    (B) The Annual EGU NOX Budget shall not exceed, during 
the indicated periods, the amount specified in paragraph (e)(2) of this 
section plus the amount of the Annual Non-EGU NOX Reduction 
Requirement under paragraph (e)(1)(iii)(A) of this section for the 
appropriate period.
    (2) For a State that complies with the requirements of paragraph 
(a)(1) of this section by imposing control measures on only EGUs, the 
amount of the Annual EGU NOX Budget, in tons of 
NOX per year, shall be as follows, for the indicated State 
for the indicated period:

------------------------------------------------------------------------
                                                          Annual EGU NOX
                                          Annual EGU NOX    budget for
                  State                     budget for       2015 and
                                             2009-2014      thereafter
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................          69,020          57,517
Delaware................................           4,166           3,472
District of Columbia....................             144             120
Florida.................................          99,445          82,871
Georgia.................................          66,321          55,268
Illinois................................          76,230          63,525
Indiana.................................         108,935          90,779
Iowa....................................          32,692          27,243
Kentucky................................          83,205          69,337
Louisiana...............................          35,512          29,593
Maryland................................          27,724          23,104
Michigan................................          65,304          54,420
Minnesota...............................          31,443          26,203
Mississippi.............................          17,807          14,839
Missouri................................          59,871          49,892
New Jersey..............................          12,670          10,558
New York................................          45,617          38,014
North Carolina..........................          62,183          51,819
Ohio....................................         108,667          90,556
Pennsylvania............................          99,049          82,541
South Carolina..........................          32,662          27,219
Tennessee...............................          50,973          42,478
Texas...................................         181,014         150,845
Virginia................................          36,074          30,062
West Virginia...........................          74,220          61,850
Wisconsin...............................          40,759          33,966
------------------------------------------------------------------------

    (3) For a State that complies with the requirements of paragraph 
(a)(1) of

[[Page 160]]

this section by imposing control measures on only non-EGUs, the amount 
of the Annual Non-EGU NOX Reduction Requirement, in tons of 
NOX per year, shall be determined, for the State for 2009 and 
thereafter, by subtracting the amount of the State's Annual EGU 
NOX Budget for the appropriate year, specified in paragraph 
(e)(2) of this section from the amount of the State's NOX 
baseline EGU emissions inventory projected for the appropriate year, 
specified in Table 5 of ``Regional and State SO2 and 
NOX Budgets'', March 2005 (available at http://www.epa.gov/
cleanairinterstaterule).
    (4)(i) Notwithstanding the State's obligation to comply with 
paragraph (e)(2) or (3) of this section, the State's SIP revision may 
allow sources required by the revision to implement control measures to 
demonstrate compliance using credit issued from the State's compliance 
supplement pool, as set forth in paragraph (e)(4)(ii) of this section.
    (ii) The State-by-State amounts of the compliance supplement pool 
are as follows:

------------------------------------------------------------------------
                                                            Compliance
                          State                             supplement
                                                               pool
------------------------------------------------------------------------
Alabama.................................................          10,166
Delaware................................................             843
District of Columbia....................................               0
Florida.................................................           8,335
Georgia.................................................          12,397
Illinois................................................          11,299
Indiana.................................................          20,155
Iowa....................................................           6,978
Kentucky................................................          14,935
Louisiana...............................................           2,251
Maryland................................................           4,670
Michigan................................................           8,347
Minnesota...............................................           6,528
Mississippi.............................................           3,066
Missouri................................................           9,044
New Jersey..............................................             660
New York................................................               0
North Carolina..........................................               0
Ohio....................................................          25,037
Pennsylvania............................................          16,009
South Carolina..........................................           2,600
Tennessee...............................................           8,944
Texas...................................................             772
Virginia................................................           5,134
West Virginia...........................................          16,929
Wisconsin...............................................           4,898
------------------------------------------------------------------------

    (iii) The SIP revision may provide for the distribution of credits 
from the compliance supplement pool to sources that are required to 
implement control measures using one or both of the following two 
mechanisms:
    (A) The State may issue credit from compliance supplement pool to 
sources that are required by the SIP revision to implement 
NOX emission control measures and that implement 
NOX emission reductions in 2007 and 2008 that are not 
necessary to comply with any State or federal emissions limitation 
applicable at any time during such years. Such a source may be issued 
one credit from the compliance supplement pool for each ton of such 
emission reductions in 2007 and 2008.
    (1) The State shall complete the issuance process by January 1, 
2010.
    (2) The emissions reductions for which credits are issued must have 
been demonstrated by the owners and operators of the source to have 
occurred during 2007 and 2008 and not to be necessary to comply with any 
applicable State or federal emissions limitation.
    (3) The emissions reductions for which credits are issued must have 
been quantified by the owners and operators of the source:
    (i) For EGUs and for fossil-fuel-fired non-EGUs that are boilers or 
combustion turbines with a maximum design heat input greater than 250 
mmBut/hr, using emissions data determined in accordance with subpart H 
of part 75 of this chapter; and
    (ii) For non-EGUs not described in paragraph (e)(4)(iii)(A)(3)(i) of 
this section, using emissions data determined in accordance with subpart 
H of part 75 of this chapter or, if the State demonstrates that 
compliance with subpart H of part 75 of this chapter is not practicable, 
determined, to the extent practicable, with the same degree of assurance 
with which emissions data are determined for sources subject to subpart 
H of part 75.
    (4) If the SIP revision contains approved provisions for an 
emissions trading program, the owners and operators of sources that 
receive credit according to the requirements of this paragraph may 
transfer the credit to other sources or persons according to the 
provisions in the emissions trading program.
    (B) The State may issue credit from the compliance supplement pool 
to sources that are required by the SIP revision to implement 
NOX emission

[[Page 161]]

control measures and whose owners and operators demonstrate a need for 
an extension, beyond 2009, of the deadline for the source for 
implementing such emission controls.
    (1) The State shall complete the issuance process by January 1, 
2010.
    (2) The State shall issue credit to a source only if the owners and 
operators of the source demonstrate that:
    (i) For a source used to generate electricity, implementation of the 
SIP revision's applicable control measures by 2009 would create undue 
risk for the reliability of the electricity supply. This demonstration 
must include a showing that it would not be feasible for the owners and 
operators of the source to obtain a sufficient amount of electricity, to 
prevent such undue risk, from other electricity generation facilities 
during the installation of control technology at the source necessary to 
comply with the SIP revision.
    (ii) For a source not used to generate electricity, compliance with 
the SIP revision's applicable control measures by 2009 would create 
undue risk for the source or its associated industry to a degree that is 
comparable to the risk described in paragraph (e)(4)(iii)(B)(2)(i) of 
this section.
    (iii) This demonstration must include a showing that it would not be 
possible for the source to comply with applicable control measures by 
obtaining sufficient credits under paragraph (e)(4)(iii)(A) of this 
section, or by acquiring sufficient credits from other sources or 
persons, to prevent undue risk.
    (f) Each SIP revision must set forth control measures to meet the 
amounts specified in paragraph (e) of this section, as applicable, 
including the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;
    (ii) Procedures for handling violations; and
    (iii) A designation of agency responsibility for enforcement of 
implementation.
    (2)(i) If a State elects to impose control measures on EGUs, then 
those measures must impose an annual NOX mass emissions cap 
on all such sources in the State.
    (ii) If a State elects to impose control measures on fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then those measures must 
impose an annual NOX mass emissions cap on all such sources 
in the State.
    (iii) If a State elects to impose control measures on non-EGUs other 
than those described in paragraph (f)(2)(ii) of this section, then those 
measures must impose an annual NOX mass emissions cap on all 
such sources in the State or the State must demonstrate why such 
emissions cap is not practicable and adopt alternative requirements that 
ensure that the State will comply with its requirements under paragraph 
(e) of this section, as applicable, in 2009 and subsequent years.
    (g)(1) Each SIP revision that contains control measures covering 
non-EGUs as part or all of a State's obligation in meeting its 
requirement under paragraph (a)(1) of this section must demonstrate that 
such control measures are adequate to provide for the timely compliance 
with the State's Annual Non-EGU NOX Reduction Requirement 
under paragraph (e) of this section and are not adopted or implemented 
by the State, as of May 12, 2005, and are not adopted or implemented by 
the Federal government, as of the date of submission of the SIP revision 
by the State to EPA.
    (2) The demonstration under paragraph (g)(1) of this section must 
include the following, with respect to each source category of non-EGUs 
for which the SIP revision requires control measures:
    (i) A detailed historical baseline inventory of NOX mass 
emissions from the source category in a representative year consisting, 
at the State's election, of 2002, 2003, 2004, or 2005, or an average of 
2 or more of those years, absent the control measures specified in the 
SIP revision.
    (A) This inventory must represent estimates of actual emissions 
based on monitoring data in accordance with subpart H of part 75 of this 
chapter, if

[[Page 162]]

the source category is subject to monitoring requirements in accordance 
with subpart H of part 75 of this chapter.
    (B) In the absence of monitoring data in accordance with subpart H 
of part 75 of this chapter, actual emissions must be quantified, to the 
maximum extent practicable, with the same degree of assurance with which 
emissions are quantified for sources subject to subpart H of part 75 of 
this chapter and using source-specific or source-category-specific 
assumptions that ensure a source's or source category's actual emissions 
are not overestimated. If a State uses factors to estimate emissions, 
production or utilization, or effectiveness of controls or rules for a 
source category, such factors must be chosen to ensure that emissions 
are not overestimated.
    (C) For measures to reduce emissions from motor vehicles, emission 
estimates must be based on an emissions model that has been approved by 
EPA for use in SIP development and must be consistent with the planning 
assumptions regarding vehicle miles traveled and other factors current 
at the time of the SIP development.
    (D) For measures to reduce emissions from nonroad engines or 
vehicles, emission estimates methodologies must be approved by EPA.
    (ii) A detailed baseline inventory of NOX mass emissions 
from the source category in the years 2009 and 2015, absent the control 
measures specified in the SIP revision and reflecting changes in these 
emissions from the historical baseline year to the years 2009 and 2015, 
based on projected changes in the production input or output, 
population, vehicle miles traveled, economic activity, or other factors 
as applicable to this source category.
    (A) These inventories must account for implementation of any control 
measures that are otherwise required by final rules already promulgated, 
as of May 12, 2005, or adopted or implemented by any federal agency, as 
of the date of submission of the SIP revision by the State to EPA, and 
must exclude any control measures specified in the SIP revision to meet 
the NOX emissions reduction requirements of this section.
    (B) Economic and population forecasts must be as specific as 
possible to the applicable industry, State, and county of the source or 
source category and must be consistent with both national projections 
and relevant official planning assumptions, including estimates of 
population and vehicle miles traveled developed through consultation 
between State and local transportation and air quality agencies. 
However, if these official planning assumptions are inconsistent with 
official U.S. Census projections of population or with energy 
consumption projections contained in the U.S. Department of Energy's 
most recent Annual Energy Outlook, then the SIP revision must make 
adjustments to correct the inconsistency or must demonstrate how the 
official planning assumptions are more accurate.
    (C) These inventories must account for any changes in production 
method, materials, fuels, or efficiency that are expected to occur 
between the historical baseline year and 2009 or 2015, as appropriate.
    (iii) A projection of NOX mass emissions in 2009 and 2015 
from the source category assuming the same projected changes as under 
paragraph (g)(2)(ii) of this section and resulting from implementation 
of each of the control measures specified in the SIP revision.
    (A) These inventories must address the possibility that the State's 
new control measures may cause production or utilization, and emissions, 
to shift to unregulated or less stringently regulated sources in the 
source category in the same or another State, and these inventories must 
include any such amounts of emissions that may shift to such other 
sources.
    (B) The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected 2009 and 2015 NOX emissions that will be achieved 
from the implementation of the new control measures compared to the 
relevant baseline emissions inventory.
    (iv) The result of subtracting the amounts in paragraph (g)(2)(iii) 
of this section for 2009 and 2015, respectively, from the lower of the 
amounts in paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2009 
and 2015, respectively, may be credited towards the State's Annual

[[Page 163]]

Non-EGU NOX Reduction Requirement in paragraph (e)(3) of this 
section for the appropriate period.
    (v) Each SIP revision must identify the sources of the data used in 
each estimate and each projection of emissions.
    (h) Each SIP revision must comply with Sec. 51.116 (regarding data 
availability).
    (i) Each SIP revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the State's 
requirements under paragraph (e) of this section as follows:
    (1) The SIP revision must provide for legally enforceable procedures 
for requiring owners or operators of stationary sources to maintain 
records of, and periodically report to the State:
    (i) Information on the amount of NOX emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable portions 
of the control measures;
    (2) The SIP revision must comply with Sec. 51.212 (regarding 
testing, inspection, enforcement, and complaints);
    (3) If the SIP revision contains any transportation control 
measures, then the SIP revision must comply with Sec. 51.213 (regarding 
transportation control measures);
    (4)(i) If the SIP revision contains measures to control EGUs, then 
the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of subpart H of part 
75 of this chapter.
    (ii) If the SIP revision contains measures to control fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then the SIP revision must 
require such sources to comply with the monitoring, recordkeeping, and 
reporting provisions of subpart H of part 75 of this chapter.
    (iii) If the SIP revision contains measures to control any other 
non-EGUs that are not described in paragraph (i)(4)(ii) of this section, 
then the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of subpart H of part 
75 of this chapter, or the State must demonstrate why such requirements 
are not practicable and adopt alternative requirements that ensure that 
the required emissions reductions will be quantified, to the maximum 
extent practicable, with the same degree of assurance with which 
emissions are quantified for sources subject to subpart H of part 75 of 
this chapter.
    (j) Each SIP revision must show that the State has legal authority 
to carry out the SIP revision, including authority to:
    (1) Adopt emissions standards and limitations and any other measures 
necessary for attainment and maintenance of the State's relevant Annual 
EGU NOX Budget or the Annual Non-EGU NOX Reduction 
Requirement, as applicable, under paragraph (e) of this section;
    (2) Enforce applicable laws, regulations, and standards and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources; and
    (4)(i) Require owners or operators of stationary sources to install, 
maintain, and use emissions monitoring devices and to make periodic 
reports to the State on the nature and amounts of emissions from such 
stationary sources; and
    (ii) Make the data described in paragraph (j)(4)(i) of this section 
available to the public within a reasonable time after being reported 
and as correlated with any applicable emissions standards or 
limitations.
    (k)(1) The provisions of law or regulation that the State determines 
provide the authorities required under this section must be specifically 
identified, and copies of such laws or regulations must be submitted 
with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (j)(3) and (4) of this section may be delegated

[[Page 164]]

to the State under section 114 of the CAA.
    (l)(1) A SIP revision may assign legal authority to local agencies 
in accordance with Sec. 51.232.
    (2) Each SIP revision must comply with Sec. 51.240 (regarding 
general plan requirements).
    (m) Each SIP revision must comply with Sec. 51.280 (regarding 
resources).
    (n) Each SIP revision must provide for State compliance with the 
reporting requirements in Sec. 51.125.
    (o)(1) Notwithstanding any other provision of this section, if a 
State adopts regulations substantively identical to subparts AA through 
II of part 96 of this chapter (CAIR NOX Annual Trading 
Program), incorporates such subparts by reference into its regulations, 
or adopts regulations that differ substantively from such subparts only 
as set forth in paragraph (o)(2) of this section, then such emissions 
trading program in the State's SIP revision is automatically approved as 
meeting the requirements of paragraph (e) of this section, provided that 
the State has the legal authority to take such action and to implement 
its responsibilities under such regulations.
    (2) If a State adopts an emissions trading program that differs 
substantively from subparts AA through II of part 96 of this chapter 
only as follows, then the emissions trading program is approved as set 
forth in paragraph (o)(1) of this section.
    (i) The State may decline to adopt the CAIR NOX opt-in 
provisions of:
    (A) Subpart II of this part and the provisions applicable only to 
CAIR NOX opt-in units in subparts AA through HH of this part;
    (B) Section 96.188(b) of this chapter and the provisions of subpart 
II of this part applicable only to CAIR NOX opt-in units 
under Sec. 96.188(b); or
    (C) Section 96.188(c) of this chapter and the provisions of subpart 
II of this part applicable only to CAIR NOX opt-in units 
under Sec. 96.188(c).
    (ii) The State may decline to adopt the allocation provisions set 
forth in subpart EE of part 96 of this chapter and may instead adopt any 
methodology for allocating CAIR NOX allowances to individual 
sources, as follows:
    (A) The State's methodology must not allow the State to allocate 
CAIR NOX allowances for a year in excess of the amount in the 
State's Annual EGU NOX Budget for such year;
    (B) The State's methodology must require that, for EGUs commencing 
operation before January 1, 2001, the State will determine, and notify 
the Administrator of, each unit's allocation of CAIR NOX 
allowances by October 31, 2006 for 2009, 2010, and 2011 and by October 
31, 2008 and October 31 of each year thereafter for 4th the year after 
the year of the notification deadline;
    (C) The State's methodology must require that, for EGUs commencing 
operation on or after January 1, 2001, the State will determine, and 
notify the Administrator of, each unit's allocation of CAIR 
NOX allowances by October 31 of the year for which the CAIR 
NOX allowances are allocated; and
    (D) The State's methodology for allocating the compliance supplement 
pool must be substantively identical to Sec. 97.143 (except that the 
permitting authority makes the allocations and the Administrator records 
the allocations made by the permitting authority) or otherwise in 
accordance with paragraph (e)(4) of this section.
    (3) A State that adopts an emissions trading program in accordance 
with paragraph (o)(1) or (2) of this section is not required to adopt an 
emissions trading program in accordance with paragraph (aa)(1) or (2) of 
this section or Sec. 96.124(o)(1) or (2).
    (4) If a State adopts an emissions trading program that differs 
substantively from subparts AA through HH of part 96 of this chapter, 
other than as set forth in paragraph (o)(2) of this section, then such 
emissions trading program is not automatically approved as set forth in 
paragraph (o)(1) or (2) of this section and will be reviewed by the 
Administrator for approvability in accordance with the other provisions 
of this section, provided that the NOX allowances issued 
under such emissions trading program shall not, and the SIP revision 
shall state that such NOX allowances shall not, qualify as 
CAIR NOX allowances or CAIR NOX Ozone Season 
allowances under any emissions trading program

[[Page 165]]

approved under paragraphs (o)(1) or (2) or (aa)(1) or (2) of this 
section.
    (p) Notwithstanding any other provision of this section, a State may 
adopt, and include in a SIP revision submitted by March 31, 2007, 
regulations relating to the Federal CAIR NOX Annual Trading 
Program under subparts AA through HH of part 97 of this chapter as 
follows:
    (1) The State may adopt, as CAIR NOX allowance allocation 
provisions replacing the provisions in subpart EE of part 97 of this 
chapter:
    (i) Allocation provisions substantively identical to subpart EE of 
part 96 of this chapter, under which the permitting authority makes the 
allocations; or
    (ii) Any methodology for allocating CAIR NOX allowances 
to individual sources under which the permitting authority makes the 
allocations, provided that:
    (A) The State's methodology must not allow the permitting authority 
to allocate CAIR NOX allowances for a year in excess of the 
amount in the State's Annual EGU NOX budget for such year.
    (B) The State's methodology must require that, for EGUs commencing 
operation before January 1, 2001, the permitting authority will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX allowances by April 30, 2007 for 2009, 2010, and 
2011 and by October 31, 2008 and October 31 of each year thereafter for 
the 4th year after the year of the notification deadline.
    (C) The State's methodology must require that, for EGUs commencing 
operation on or after January 1, 2001, the permitting authority will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX allowances by October 31 of the year for which the 
CAIR NOX allowances are allocated.
    (2) The State may adopt, as compliance supplement pool provisions 
replacing the provisions in ( 97.143 of this chapter:
    (i) Provisions for allocating the State's compliance supplement pool 
that are substantively identical to Sec. 97.143 of this chapter, except 
that the permitting authority makes the allocations and the 
Administrator records the allocations made by the permitting authority;
    (ii) Provisions for allocating the State's compliance supplement 
pool that are substantively identical to Sec. 96.143 of this chapter; 
or
    (iii) Other provisions for allocating the State's compliance 
supplement pool that are in accordance with paragraph (e)(4) of this 
section.
    (3) The State may adopt CAIR opt-in unit provisions as follows:
    (i) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX allowances for CAIR opt-in units, that are 
substantively identical to subpart II of part 96 of this chapter and the 
provisions of subparts AA through HH that are applicable to CAIR opt-in 
units or units for which a CAIR opt-in permit application is submitted 
and not withdrawn and a CAIR opt-in permit is not yet issued or denied;
    (ii) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX allowances for CAIR opt-in units, that are 
substantively identical to subpart II of part 96 of this chapter and the 
provisions of subparts AA through HH that are applicable to CAIR opt-in 
units or units for which a CAIR opt-in permit application is submitted 
and not withdrawn and a CAIR opt-in permit is not yet issued or denied, 
except that the provisions exclude Sec. 96.188(b) of this chapter and 
the provisions of subpart II of part 96 of this chapter that apply only 
to units covered by Sec. 96.188(b) of this chapter; or
    (iii) Provisions for applications for CAIR opt-in units, including 
provisions for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX allowances for CAIR opt-in units, that are 
substantively identical to subpart II of part 96 of this chapter and the 
provisions of subparts AA through HH that are applicable to CAIR opt-in

[[Page 166]]

units or units for which a CAIR opt-in permit application is submitted 
and not withdrawn and a CAIR opt-in permit is not yet issued or denied, 
except that the provisions exclude Sec. 96.188(c) of this chapter and 
the provisions of subpart II of part 96 of this chapter that apply only 
to units covered by Sec. 96.188(c) of this chapter.
    (q) The State's SIP revision shall contain control measures and 
demonstrate that they will result in compliance with the State's Ozone 
Season EGU NOX Budget, if applicable, and achieve the State's 
Ozone Season Non-EGU NOX Reduction Requirement, if 
applicable, for the appropriate periods. The amounts of the State's 
Ozone Season EGU NOX Budget and Ozone Season Non-EGU 
NOX Reduction Requirement shall be determined as follows:
    (1)(i) The Ozone Season EGU NOX Budget for the State is 
defined as the total amount of NOX emissions from all EGUs in 
that State for an ozone season, if the State meets the requirements of 
paragraph (a)(2) of this section by imposing control measures, at least 
in part, on EGUs. If the State imposes control measures under this 
section on only EGUs, the Ozone Season EGU NOX Budget for the 
State shall not exceed the amount, during the indicated periods, 
specified in paragraph (q)(2) of this section.
    (ii) The Ozone Season Non-EGU NOX Reduction Requirement, 
if applicable, is defined as the total amount of NOX emission 
reductions that the State demonstrates, in accordance with paragraph (s) 
of this section, it will achieve from non-EGUs during the appropriate 
period. If the State meets the requirements of paragraph (a)(2) of this 
section by imposing control measures on only non-EGUs, then the State's 
Ozone Season Non-EGU NOX Reduction Requirement shall equal or 
exceed, during the appropriate periods, the amount determined in 
accordance with paragraph (q)(3) of this section.
    (iii) If a State meets the requirements of paragraph (a)(2) of this 
section by imposing control measures on both EGUs and non-EGUs, then:
    (A) The Ozone Season Non-EGU NOX Reduction Requirement 
shall equal or exceed the difference between the amount specified in 
paragraph (q)(2) of this section for the appropriate period and the 
amount of the State's Ozone Season EGU NOX Budget specified 
in the SIP revision for the appropriate period; and
    (B) The Ozone Season EGU NOX Budget shall not exceed, 
during the indicated periods, the amount specified in paragraph (e)(2) 
of this section plus the amount of the Ozone Season Non-EGU 
NOX Reduction Requirement under paragraph (q)(1)(iii)(A) of 
this section for the appropriate period.
    (2) For a State that complies with the requirements of paragraph 
(a)(2) of this section by imposing control measures on only EGUs, the 
amount of the Ozone Season EGU NOX Budget, in tons of 
NOX per ozone season, shall be as follows, for the indicated 
State for the indicated period:

------------------------------------------------------------------------
                                                           Ozone season
                                           Ozone season   EGU NOX budget
                  State                   EGU NOX budget   for 2015 and
                                           for 2009-2014    thereafter
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................          32,182          26,818
Arkansas................................          11,515           9,596
Connecticut.............................           2,559           2,559
Delaware................................           2,226           1,855
District of Columbia....................             112              94
Florida.................................          47,912          39,926
Illinois................................          30,701          28,981
Indiana.................................          45,952          39,273
Iowa....................................          14,263          11,886
Kentucky................................          36,045          30,587
Louisiana...............................          17,085          14,238
Maryland................................          12,834          10,695
Massachusetts...........................           7,551           6,293
Michigan................................          28,971          24,142
Mississippi.............................           8,714           7,262
Missouri................................          26,678          22,231
New Jersey..............................           6,654           5,545
New York................................          20,632          17,193
North Carolina..........................          28,392          23,660
Ohio....................................          45,664          39,945
Pennsylvania............................          42,171          35,143
South Carolina..........................          15,249          12,707
Tennessee...............................          22,842          19,035
Virginia................................          15,994          13,328
West Virginia...........................          26,859          26,525
Wisconsin...............................          17,987          14,989
------------------------------------------------------------------------

    (3) For a State that complies with the requirements of paragraph 
(a)(2) of this section by imposing control measures on only non-EGUs, 
the amount of the Ozone Season Non-EGU NOX Reduction 
Requirement, in tons of NOX per ozone season, shall be 
determined, for the State for 2009 and thereafter, by subtracting the 
amount of the State's Ozone Season EGU NOX Budget for the 
appropriate year, specified in paragraph (e)(2) of this section, from 
the

[[Page 167]]

amount of the State's NOX baseline EGU emissions inventory 
projected for the ozone season in the appropriate year, specified in 
Table 7 of ``Regional and State SO2 and NOX 
Budgets'', March 2005 (available at: http://www.epa.gov/
cleanairinterstaterule).
    (4) Notwithstanding the State's obligation to comply with paragraph 
(q)(2) or (3) of this section, the State's SIP revision may allow 
sources required by the revision to implement NOX emission 
control measures to demonstrate compliance using NOX SIP Call 
allowances allocated under the NOX Budget Trading Program for 
any ozone season during 2003 through 2008 that have not been deducted by 
the Administrator under the NOX Budget Trading Program, if 
the SIP revision ensures that such allowances will not be available for 
such deduction under the NOX Budget Trading Program.
    (r) Each SIP revision must set forth control measures to meet the 
amounts specified in paragraph (q) of this section, as applicable, 
including the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;
    (ii) Procedures for handling violations; and
    (iii) A designation of agency responsibility for enforcement of 
implementation.
    (2)(i) If a State elects to impose control measures on EGUs, then 
those measures must impose an ozone season NOX mass emissions 
cap on all such sources in the State.
    (ii) If a State elects to impose control measures on fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then those measures must 
impose an ozone season NOX mass emissions cap on all such 
sources in the State.
    (iii) If a State elects to impose control measures on non-EGUs other 
than those described in paragraph (r)(2)(ii) of this section, then those 
measures must impose an ozone season NOX mass emissions cap 
on all such sources in the State or the State must demonstrate why such 
emissions cap is not practicable and adopt alternative requirements that 
ensure that the State will comply with its requirements under paragraph 
(q) of this section, as applicable, in 2009 and subsequent years.
    (s)(1) Each SIP revision that contains control measures covering 
non-EGUs as part or all of a State's obligation in meeting its 
requirement under paragraph (a)(2) of this section must demonstrate that 
such control measures are adequate to provide for the timely compliance 
with the State's Ozone Season Non-EGU NOX Reduction 
Requirement under paragraph (q) of this section and are not adopted or 
implemented by the State, as of May 12, 2005, and are not adopted or 
implemented by the federal government, as of the date of submission of 
the SIP revision by the State to EPA.
    (2) The demonstration under paragraph (s)(1) of this section must 
include the following, with respect to each source category of non-EGUs 
for which the SIP revision requires control measures:
    (i) A detailed historical baseline inventory of NOX mass 
emissions from the source category in a representative ozone season 
consisting, at the State's election, of the ozone season in 2002, 2003, 
2004, or 2005, or an average of 2 or more of those ozone seasons, absent 
the control measures specified in the SIP revision.
    (A) This inventory must represent estimates of actual emissions 
based on monitoring data in accordance with subpart H of part 75 of this 
chapter, if the source category is subject to monitoring requirements in 
accordance with subpart H of part 75 of this chapter.
    (B) In the absence of monitoring data in accordance with subpart H 
of part 75 of this chapter, actual emissions must be quantified, to the 
maximum extent practicable, with the same degree of assurance with which 
emissions are quantified for sources subject to subpart H of part 75 of 
this chapter and using source-specific or source-category-specific 
assumptions that ensure a source's or source category's actual emissions 
are not overestimated. If a State uses factors to estimate emissions, 
production or utilization, or effectiveness of controls or rules for a

[[Page 168]]

source category, such factors must be chosen to ensure that emissions 
are not overestimated.
    (C) For measures to reduce emissions from motor vehicles, emission 
estimates must be based on an emissions model that has been approved by 
EPA for use in SIP development and must be consistent with the planning 
assumptions regarding vehicle miles traveled and other factors current 
at the time of the SIP development.
    (D) For measures to reduce emissions from nonroad engines or 
vehicles, emission estimates methodologies must be approved by EPA.
    (ii) A detailed baseline inventory of NOX mass emissions 
from the source category in ozone seasons 2009 and 2015, absent the 
control measures specified in the SIP revision and reflecting changes in 
these emissions from the historical baseline ozone season to the ozone 
seasons 2009 and 2015, based on projected changes in the production 
input or output, population, vehicle miles traveled, economic activity, 
or other factors as applicable to this source category.
    (A) These inventories must account for implementation of any control 
measures that are adopted or implemented by the State, as of May 12, 
2005, or adopted or implemented by the federal government, as of the 
date of submission of the SIP revision by the State to EPA, and must 
exclude any control measures specified in the SIP revision to meet the 
NOX emissions reduction requirements of this section.
    (B) Economic and population forecasts must be as specific as 
possible to the applicable industry, State, and county of the source or 
source category and must be consistent with both national projections 
and relevant official planning assumptions including estimates of 
population and vehicle miles traveled developed through consultation 
between State and local transportation and air quality agencies. 
However, if these official planning assumptions are inconsistent with 
official U.S. Census projections of population or with energy 
consumption projections contained in the U.S. Department of Energy's 
most recent Annual Energy Outlook, then the SIP revision must make 
adjustments to correct the inconsistency or must demonstrate how the 
official planning assumptions are more accurate.
    (C) These inventories must account for any changes in production 
method, materials, fuels, or efficiency that are expected to occur 
between the historical baseline ozone season and ozone season 2009 or 
ozone season 2015, as appropriate.
    (iii) A projection of NOX mass emissions in ozone season 
2009 and ozone season 2015 from the source category assuming the same 
projected changes as under paragraph (s)(2)(ii) of this section and 
resulting from implementation of each of the control measures specified 
in the SIP revision.
    (A) These inventories must address the possibility that the State's 
new control measures may cause production or utilization, and emissions, 
to shift to unregulated or less stringently regulated sources in the 
source category in the same or another State, and these inventories must 
include any such amounts of emissions that may shift to such other 
sources.
    (B) The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected ozone season 2009 and ozone season 2015 NOX 
emissions that will be achieved from the implementation of the new 
control measures compared to the relevant baseline emissions inventory.
    (iv) The result of subtracting the amounts in paragraph (s)(2)(iii) 
of this section for ozone season 2009 and ozone season 2015, 
respectively, from the lower of the amounts in paragraph (s)(2)(i) or 
(s)(2)(ii) of this section for ozone season 2009 and ozone season 2015, 
respectively, may be credited towards the State's Ozone Season Non-EGU 
NOX Reduction Requirement in paragraph (q)(3) of this section 
for the appropriate period.
    (v) Each SIP revision must identify the sources of the data used in 
each estimate and each projection of emissions.
    (t) Each SIP revision must comply with Sec. 51.116 (regarding data 
availability).

[[Page 169]]

    (u) Each SIP revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the State's 
requirements under paragraph (q) of this section as follows:
    (1) The SIP revision must provide for legally enforceable procedures 
for requiring owners or operators of stationary sources to maintain 
records of, and periodically report to the State:
    (i) Information on the amount of NOX emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable portions 
of the control measures;
    (2) The SIP revision must comply with Sec. 51.212 (regarding 
testing, inspection, enforcement, and complaints);
    (3) If the SIP revision contains any transportation control 
measures, then the SIP revision must comply with Sec. 51.213 (regarding 
transportation control measures);
    (4)(i) If the SIP revision contains measures to control EGUs, then 
the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of subpart H of part 
75 of this chapter.
    (ii) If the SIP revision contains measures to control fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then the SIP revision must 
require such sources to comply with the monitoring, recordkeeping, and 
reporting provisions of subpart H of part 75 of this chapter.
    (iii) If the SIP revision contains measures to control any other 
non-EGUs that are not described in paragraph (u)(4)(ii) of this section, 
then the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of subpart H of part 
75 of this chapter, or the State must demonstrate why such requirements 
are not practicable and adopt alternative requirements that ensure that 
the required emissions reductions will be quantified, to the maximum 
extent practicable, with the same degree of assurance with which 
emissions are quantified for sources subject to subpart H of part 75 of 
this chapter.
    (v) Each SIP revision must show that the State has legal authority 
to carry out the SIP revision, including authority to:
    (1) Adopt emissions standards and limitations and any other measures 
necessary for attainment and maintenance of the State's relevant Ozone 
Season EGU NOX Budget or the Ozone Season Non-EGU 
NOX Reduction Requirement, as applicable, under paragraph (q) 
of this section;
    (2) Enforce applicable laws, regulations, and standards and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources; and
    (4)(i) Require owners or operators of stationary sources to install, 
maintain, and use emissions monitoring devices and to make periodic 
reports to the State on the nature and amounts of emissions from such 
stationary sources; and
    (ii) Make the data described in paragraph (v)(4)(i) of this section 
available to the public within a reasonable time after being reported 
and as correlated with any applicable emissions standards or 
limitations.
    (w)(1) The provisions of law or regulation that the State determines 
provide the authorities required under this section must be specifically 
identified, and copies of such laws or regulations must be submitted 
with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (v)(3) and (4) of this section may be delegated to the State 
under section 114 of the CAA.
    (x)(1) A SIP revision may assign legal authority to local agencies 
in accordance with Sec. 51.232.
    (2) Each SIP revision must comply with Sec. 51.240 (regarding 
general plan requirements).
    (y) Each SIP revision must comply with Sec. 51.280 (regarding 
resources).

[[Page 170]]

    (z) Each SIP revision must provide for State compliance with the 
reporting requirements in Sec. 51.125.
    (aa)(1) Notwithstanding any other provision of this section, if a 
State adopts regulations substantively identical to subparts AAAA 
through IIII of part 96 of this chapter (CAIR Ozone Season 
NOX Trading Program), incorporates such subparts by reference 
into its regulations, or adopts regulations that differ substantively 
from such subparts only as set forth in paragraph (aa)(2) of this 
section, then such emissions trading program in the State's SIP revision 
is automatically approved as meeting the requirements of paragraph (q) 
of this section, provided that the State has the legal authority to take 
such action and to implement its responsibilities under such 
regulations.
    (2) If a State adopts an emissions trading program that differs 
substantively from subparts AAAA through IIII of part 96 of this chapter 
only as follows, then the emissions trading program is approved as set 
forth in paragraph (aa)(1) of this section.
    (i) The State may expand the applicability provisions in Sec. 
96.304 to include all non-EGUs subject to the State's emissions trading 
program approved under Sec. 51.121(p).
    (ii) The State may decline to adopt the CAIR NOX Ozone 
Season opt-in provisions of:
    (A) Subpart IIII of this part and the provisions applicable only to 
CAIR NOX Ozone Season opt-in units in subparts AAAA through 
HHHH of this part;
    (B) Section 96.388(b) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(b); or
    (C) Section 96.388(c) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(c).
    (iii) The State may decline to adopt the allocation provisions set 
forth in subpart EEEE of part 96 of this chapter and may instead adopt 
any methodology for allocating CAIR NOX Ozone Season 
allowances to individual sources, as follows:
    (A) The State may provide for issuance of an amount of CAIR Ozone 
Season NOX allowances for an ozone season, in addition to the 
amount in the State's Ozone Season EGU NOX Budget for such 
ozone season, not exceeding the amount of NOX SIP Call 
allowances allocated for the ozone season under the NOX 
Budget Trading Program to non-EGUs that the applicability provisions in 
Sec. 96.304 are expanded to include under paragraph (aa)(2)(i) of this 
section;
    (B) The State's methodology must not allow the State to allocate 
CAIR Ozone Season NOX allowances for an ozone season in 
excess of the amount in the State's Ozone Season EGU NOX 
Budget for such ozone season plus any additional amount of CAIR Ozone 
Season NOX allowances issued under paragraph (aa)(2)(iii)(A) 
of this section for such ozone season;
    (C) The State's methodology must require that, for EGUs commencing 
operation before January 1, 2001, the State will determine, and notify 
the Administrator of, each unit's allocation of CAIR NOX 
allowances by October 31, 2006 for the ozone seasons 2009, 2010, and 
2011 and by October 31, 2008 and October 31 of each year thereafter for 
the ozone season in the 4th year after the year of the notification 
deadline; and
    (D) The State's methodology must require that, for EGUs commencing 
operation on or after January 1, 2001, the State will determine, and 
notify the Administrator of, each unit's allocation of CAIR Ozone Season 
NOX allowances by July 31 of the calendar year of the ozone 
season for which the CAIR Ozone Season NOX allowances are 
allocated.
    (3) A State that adopts an emissions trading program in accordance 
with paragraph (aa)(1) or (2) of this section is not required to adopt 
an emissions trading program in accordance with paragraph (o)(1) or (2) 
of this section or Sec. 51.153(o)(1) or (2).
    (4) If a State adopts an emissions trading program that differs 
substantively from subparts AAAA through IIII of part 96 of this 
chapter, other than as set forth in paragraph

[[Page 171]]

(aa)(2) of this section, then such emissions trading program is not 
automatically approved as set forth in paragraph (aa)(1) or (2) of this 
section and will be reviewed by the Administrator for approvability in 
accordance with the other provisions of this section, provided that the 
NOX allowances issued under such emissions trading program 
shall not, and the SIP revision shall state that such NOX 
allowances shall not, qualify as CAIR NOX allowances or CAIR 
Ozone Season NOX allowances under any emissions trading 
program approved under paragraphs (o)(1) or (2) or (aa)(1) or (2) of 
this section.
    (bb)(1)(i) The State may revise its SIP to provide that, for each 
ozone season during which a State implements control measures on EGUs or 
non-EGUs through an emissions trading program approved under paragraph 
(aa)(1) or (2) of this section, such EGUs and non-EGUs shall not be 
subject to the requirements of the State's SIP meeting the requirements 
of Sec. 51.121, if the State meets the requirement in paragraph 
(bb)(1)(ii) of this section.
    (ii) For a State under paragraph (bb)(1)(i) of this section, if the 
State's amount of tons specified in paragraph (q)(2) of this section 
exceeds the State's amount of NOX SIP Call allowances 
allocated for the ozone season in 2009 or in any year thereafter for the 
same types and sizes of units as those covered by the amount of tons 
specified in paragraph (q)(2) of this section, then the State must 
replace the former amount for such ozone season by the latter amount for 
such ozone season in applying paragraph (q) of this section.
    (2) Rhode Island may revise its SIP to provide that, for each ozone 
season during which Rhode Island implements control measures on EGUs and 
non-EGUs through an emissions trading program adopted in regulations 
that differ substantively from subparts AAAA through IIII of part 96 of 
this chapter as set forth in this paragraph, such EGUs and non-EGUs 
shall not be subject to the requirements of the State's SIP meeting the 
requirements of Sec. 51.121.
    (i) Rhode Island must expand the applicability provisions in Sec. 
96.304 to include all non-EGUs subject to Rhode Island's emissions 
trading program approved under Sec. 51.121(p).
    (ii) Rhode Island may decline to adopt the CAIR NOX Ozone 
Season opt-in provisions of:
    (A) Subpart IIII of this part and the provisions applicable only to 
CAIR NOX Ozone Season opt-in units in subparts AAAA through 
HHHH of this part;
    (B) Section 96.388(b) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(b); or
    (C) Section 96.388(c) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(c).
    (iii) Rhode Island may adopt the allocation provisions set forth in 
subpart EEEE of part 96 of this chapter, provided that Rhode Island must 
provide for issuance of an amount of CAIR Ozone Season NOX 
allowances for an ozone season not exceeding 936 tons for 2009 and 
thereafter;
    (iv) Rhode Island may adopt any methodology for allocating CAIR 
NOX Ozone Season allowances to individual sources, as 
follows:
    (A) Rhode Island's methodology must not allow Rhode Island to 
allocate CAIR Ozone Season NOX allowances for an ozone season 
in excess of 936 tons for 2009 and thereafter;
    (B) Rhode Island's methodology must require that, for EGUs 
commencing operation before January 1, 2001, Rhode Island will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX allowances by October 31, 2006 for the ozone seasons 
2009, 2010, and 2011 and by October 31, 2008 and October 31 of each year 
thereafter for the ozone season in the 4th year after the year of the 
notification deadline; and
    (C) Rhode Island's methodology must require that, for EGUs 
commencing operation on or after January 1, 2001, Rhode Island will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR Ozone Season NOX allowances by July 31 of the calendar 
year of the ozone season for which the CAIR Ozone Season NOX 
allowances are allocated.

[[Page 172]]

    (3) Notwithstanding a SIP revision by a State authorized under 
paragraph (bb)(1) of this section or by Rhode Island under paragraph 
(bb)(2) of this section, if the State's or Rhode Island's SIP that, 
without such SIP revision, imposes control measures on EGUs or non-EGUs 
under Sec. 51.121 is determined by the Administrator to meet the 
requirements of Sec. 51.121, such SIP shall be deemed to continue to 
meet the requirements of Sec. 51.121.
    (cc) The terms used in this section shall have the following 
meanings:
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to allowances, the 
determination of the amount of allowances to be initially credited to a 
source.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after which 
the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated heat recovery steam generator and steam 
turbine.
    Commence operation means to have begun any mechanical, chemical, or 
electronic process, including, with regard to a unit, start-up of a 
unit's combustion chamber.
    Electric generating unit or EGU means:
    (1)(i) Except as provided in paragraph (2) of this definition, a 
stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired 
combustion turbine serving at any time, since the later of November 15, 
1990 or the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale.
    (ii) If a stationary boiler or stationary combustion turbine that, 
under paragraph (1)(i) of this section, is not an electric generating 
unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become an electric generating unit as provided in 
paragraph (1)(i) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (2) A unit that meets the requirements set forth in paragraphs 
(2)(i)(A), (2)(ii)(A), or (2)(ii)(B) of this definition paragraph shall 
not be an electric generating unit:
    (i)(A) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition:
    (1) Qualifying as a cogeneration unit during the 12-month period 
starting on

[[Page 173]]

the date the unit first produces electricity and continuing to qualify 
as a cogeneration unit; and
    (2) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (B) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (2)(i)(A) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become an electric generating unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (2)(i)(A)(2) of this section.
    (ii)(A) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition commencing operation before January 1, 
1985:
    (1) Qualifying as a solid waste incineration unit; and
    (2) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis) and an average annual 
fuel consumption of non-fossil fuel for any 3 consecutive calendar years 
after 1990 exceeding 80 percent (on a Btu basis).
    (B) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition commencing operation on or after 
January 1, 1985:
    (1) Qualifying as a solid waste incineration unit; and
    (2) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (C) If a unit qualifies as a solid waste incineration unit and meets 
the requirements of paragraph (2)(ii)(A) or (B) of this section for at 
least 3 consecutive calendar years, but subsequently no longer meets all 
such requirements, the unit shall become an electric generating unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    Generator means a device that produces electricity.
    Maximum design heat input means:
    (1) Starting from the initial installation of a unit, the maximum 
amount of fuel per hour (in Btu/hr) that a unit is capable of combusting 
on a steady state basis as specified by the manufacturer of the unit;
    (2)(i) Except as provided in paragraph (2)(ii) of this definition, 
starting from the completion of any subsequent physical change in the 
unit resulting in an increase in the maximum amount of fuel per hour (in 
Btu/hr) that a unit is capable of combusting on a steady state basis, 
such increased maximum amount as specified by the person conducting the 
physical change; or
    (ii) For purposes of applying the definition of the term ``potential 
electrical output capacity,'' starting from the completion of any 
subsequent physical change in the unit resulting in a decrease in the 
maximum amount of fuel per hour (in Btu/hr) that a unit is capable of 
combusting on a steady state basis, such decreased maximum amount as 
specified by the person conducting the physical change.
    NAAQS means National Ambient Air Quality Standard.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a

[[Page 174]]

steady state basis and during continuous operation (when not restricted 
by seasonal or other deratings) as specified by the manufacturer of the 
generator or, starting from the completion of any subsequent physical 
change in the generator resulting in an increase in the maximum 
electrical generating output (in MWe) that the generator is capable of 
producing on a steady state basis and during continuous operation (when 
not restricted by seasonal or other deratings), such increased maximum 
amount as specified by the person conducting the physical change.
    Non-EGU means a source of NOX emissions that is not an 
EGU.
    NOX Budget Trading Program means a multi-state nitrogen 
oxides air pollution control and emission reduction program approved and 
administered by the Administrator in accordance with subparts A through 
I of this part and Sec. 51.121, as a means of mitigating interstate 
transport of ozone and nitrogen oxides.
    NOX SIP Call allowance means a limited authorization 
issued by the Administrator under the NOX Budget Trading 
Program to emit up to one ton of nitrogen oxides during the ozone season 
of the specified year or any year thereafter, provided that the 
provision in Sec. 51.121(b)(2)(ii)(E) shall not be used in applying 
this definition.
    Ozone season means the period, which begins May 1 and ends September 
30 of any year.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in electricity 
production.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself.
    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary, fossil-fuel-fired boiler or a stationary, 
fossil-fuel-fired combustion turbine.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process, excluding 
any heat contained in condensate return or makeup water;
    (2) Used in a heat application (e.g., space heating or domestic hot 
water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.
    (dd) New Hampshire may revise its SIP to implements control measures 
on EGUs and non-EGUs through an emissions trading program adopted in 
regulations that differ substantively from subparts AAAA through IIII of 
part 96 of this chapter as set forth in this paragraph.
    (1) New Hampshire must expand the applicability provisions in Sec. 
96.304 of this chapter to include all non-EGUs subject to New 
Hampshire's emissions trading program at New Hampshire

[[Page 175]]

Code of Administrative Rules, chapter Env-A 3200 (2004).
    (2) New Hampshire may decline to adopt the CAIR NOX Ozone 
Season opt-in provisions of:
    (i) Subpart IIII of this part and the provisions applicable only to 
CAIR NOX Ozone Season opt-in units in subparts AAAA through 
HHHH of this part;
    (ii) Section 96.388(b) of this chapter and the provisions of subpart 
IIII of this part applicable only to CAIR NOX Ozone Season 
opt-in units under Sec. 96.388(b); or
    (iii) Section 96.388(c) of this chapter and the provisions of 
subpart IIII of this part applicable only to CAIR NOX Ozone 
Season opt-in units under Sec. 96.388(c).
    (3) New Hampshire may adopt the allocation provisions set forth in 
subpart EEEE of part 96 of this chapter, provided that New Hampshire 
must provide for issuance of an amount of CAIR Ozone Season 
NOX allowances for an ozone season not exceeding 3,000 tons 
for 2009 and thereafter;
    (4) New Hampshire may adopt any methodology for allocating CAIR 
NOX Ozone Season allowances to individual sources, as 
follows:
    (i) New Hampshire's methodology must not allow New Hampshire to 
allocate CAIR Ozone Season NOX allowances for an ozone season 
in excess of 3,000 tons for 2009 and thereafter;
    (ii) New Hampshire's methodology must require that, for EGUs 
commencing operation before January 1, 2001, New Hampshire will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX allowances by October 31, 2006 for the ozone seasons 
2009, 2010, and 2011 and by October 31, 2008 and October 31 of each year 
thereafter for the ozone season in the 4th year after the year of the 
notification deadline; and
    (iii) New Hampshire's methodology must require that, for EGUs 
commencing operation on or after January 1, 2001, New Hampshire will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR Ozone Season NOX allowances by July 31 of the calendar 
year of the ozone season for which the CAIR Ozone Season NOX 
allowances are allocated.
    (ee) Notwithstanding any other provision of this section, a State 
may adopt, and include in a SIP revision submitted by March 31, 2007, 
regulations relating to the Federal CAIR NOX Ozone Season 
Trading Program under subparts AAAA through HHHH of part 97 of this 
chapter as follows:
    (1) The State adopt, as applicability provisions replacing the 
provisions in Sec. 97.304 of this chapter, provisions for applicability 
that are substantively identical to the provisions in Sec. 96.304 of 
this chapter expanded to include all non-EGUs subject to the State's 
emissions trading program approved under Sec. 51.121(p).
    (2) The State may adopt, as CAIR NOX Ozone Season 
allowance allocation provisions replacing the provisions in subpart EEEE 
of part 97 of this chapter:
    (i) Allocation provisions substantively identical to subpart EEEE of 
part 96 of this chapter, under which the permitting authority makes the 
allocations; or
    (ii) Any methodology for allocating CAIR NOX Ozone Season 
allowances to individual sources under which the permitting authority 
makes the allocations, provided that:
    (A) The State may provide for issuance of an amount of CAIR Ozone 
Season NOX allowances for an ozone season, in addition to the 
amount in the State's Ozone Season EGU NOX Budget for such 
ozone season, not exceeding the portion of the State's trading program 
budget, under the State's emissions trading program approved under Sec. 
51.121(p), attributed to the non-EGUs that the applicability provisions 
in Sec. 96.304 of this chapter are expanded to include under paragraph 
(ee)(1) of this section.
    (B) The State's methodology must not allow the State to allocate 
CAIR Ozone Season NOX allowances for an ozone season in 
excess of the amount in the State's Ozone Season EGU NOX 
Budget for such ozone season plus any additional amount of CAIR Ozone 
Season NOX allowances issued under paragraph (ee)(2)(ii)(A) 
of this section for such ozone season.

[[Page 176]]

    (C) The State's methodology must require that, for EGUs commencing 
operation before January 1, 2001, the permitting authority will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX Ozone Season allowances by April 30, 2007 for 2009, 
2010, and 2011 and by October 31, 2008 and October 31 of each year 
thereafter for the 4th year after the year of the notification deadline.
    (D) The State's methodology must require that, for EGUs commencing 
operation on or after January 1, 2001, the permitting authority will 
determine, and notify the Administrator of, each unit's allocation of 
CAIR NOX Ozone Season allowances by July 31 of the year for 
which the CAIR NOX Ozone Season allowances are allocated.
    (3) The State may adopt CAIR opt-in unit provisions as follows:
    (i) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX Ozone Season allowances for CAIR opt-in units, 
that are substantively identical to subpart IIII of part 96 of this 
chapter and the provisions of subparts AAAA through HHHH that are 
applicable to CAIR opt-in units or units for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied;
    (ii) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX Ozone Season allowances for CAIR opt-in units, 
that are substantively identical to subpart IIII of part 96 of this 
chapter and the provisions of subparts AAAA through HHHH that are 
applicable to CAIR opt-in units or units for which a CAIR opt-in permit 
application is submitted and not withdrawn and a CAIR opt-in permit is 
not yet issued or denied, except that the provisions exclude Sec. 
96.388(b) of this chapter and the provisions of subpart IIII of part 96 
of this chapter that apply only to units covered by Sec. 96.388(b) of 
this chapter; or
    (iii) Provisions for applications for CAIR opt-in units, including 
provisions for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR NOX allowances for CAIR opt-in units, that are 
substantively identical to subpart IIII of part 96 of this chapter and 
the provisions of subparts AAAA through HHHH that are applicable to CAIR 
opt-in units or units for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied, except that the provisions exclude Sec. 96.388(c) of this 
chapter and the provisions of subpart IIII of part 96 of this chapter 
that apply only to units covered by Sec. 96.388(c) of this chapter.

[70 FR 25319, May 12, 2005, as amended at 71 FR 25301, 25370, Apr. 28, 
2006]



Sec. 51.124  Findings and requirements for submission of State 
implementation plan revisions relating to emissions of sulfur dioxide 
pursuant to the Clean Air Interstate Rule.

    (a) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the 
Administrator determines that each State identified in paragraph (c) of 
this section must submit a SIP revision to comply with the requirements 
of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), 
through the adoption of adequate provisions prohibiting sources and 
other activities from emitting SO2 in amounts that will 
contribute significantly to nonattainment in, or interfere with 
maintenance by, one or more other States with respect to the fine 
particles (PM2.5) NAAQS.
    (b) For each State identified in paragraph (c) of this section, the 
SIP revision required under paragraph (a) of this section will contain 
adequate provisions, for purposes of complying with section 
110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if 
the SIP revision contains control measures that assure compliance with 
the applicable requirements of this section.
    (c) The following States are subject to the requirements of this 
section: Alabama, Delaware, Florida, Georgia,

[[Page 177]]

Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, 
Minnesota, Mississippi, Missouri, New Jersey, New York, North Carolina, 
Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West 
Virginia, Wisconsin, and the District of Columbia.
    (d)(1) The SIP revision under paragraph (a) of this section must be 
submitted to EPA by no later than September 11, 2006.
    (2) The requirements of appendix V to this part shall apply to the 
SIP revision under paragraph (a) of this section.
    (3) The State shall deliver 5 copies of the SIP revision under 
paragraph (a) of this section to the appropriate Regional Office, with a 
letter giving notice of such action.
    (e) The State's SIP revision shall contain control measures and 
demonstrate that they will result in compliance with the State's Annual 
EGU SO2 Budget, if applicable, and achieve the State's Annual 
Non-EGU SO2 Reduction Requirement, if applicable, for the 
appropriate periods. The amounts of the State's Annual EGU 
SO2 Budget and Annual Non-EGU SO2 Reduction 
Requirement shall be determined as follows:
    (1)(i) The Annual EGU SO2 Budget for the State is defined 
as the total amount of SO2 emissions from all EGUs in that 
State for a year, if the State meets the requirements of paragraph (a) 
of this section by imposing control measures, at least in part, on EGUs. 
If the State imposes control measures under this section on only EGUs, 
the Annual EGU SO2 Budget for the State shall not exceed the 
amount, during the indicated periods, specified in paragraph (e)(2) of 
this section.
    (ii) The Annual Non-EGU SO2 Reduction Requirement, if 
applicable, is defined as the total amount of SO2 emission 
reductions that the State demonstrates, in accordance with paragraph (g) 
of this section, it will achieve from non-EGUs during the appropriate 
period. If the State meets the requirements of paragraph (a) of this 
section by imposing control measures on only non-EGUs, then the State's 
Annual Non-EGU SO2 Reduction Requirement shall equal or 
exceed, during the appropriate periods, the amount determined in 
accordance with paragraph (e)(3) of this section.
    (iii) If a State meets the requirements of paragraph (a) of this 
section by imposing control measures on both EGUs and non-EGUs, then:
    (A) The Annual Non-EGU SO2 Reduction Requirement shall 
equal or exceed the difference between the amount specified in paragraph 
(e)(2) of this section for the appropriate period and the amount of the 
State's Annual EGU SO2 Budget specified in the SIP revision 
for the appropriate period; and
    (B) The Annual EGU SO2 Budget shall not exceed, during 
the indicated periods, the amount specified in paragraph (e)(2) of this 
section plus the amount of the Annual Non-EGU SO2 Reduction 
Requirement under paragraph (e)(1)(iii)(A) of this section for the 
appropriate period.
    (2) For a State that complies with the requirements of paragraph (a) 
of this section by imposing control measures on only EGUs, the amount of 
the Annual EGU SO2 Budget, in tons of SO2 per 
year, shall be as follows, for the indicated State for the indicated 
period:

------------------------------------------------------------------------
                                 Annual EGU SO2        Annual EGU SO2
            State             budget for 2010-2014   budget for 2015 and
                                     (tons)           thereafter (tons)
------------------------------------------------------------------------
Alabama.....................               157,582               110,307
Delaware....................                22,411                15,687
District of Columbia........                   708                   495
Florida.....................               253,450               177,415
Georgia.....................               213,057               149,140
Illinois....................               192,671               134,869
Indiana.....................               254,599               178,219
Iowa........................                64,095                44,866
Kentucky....................               188,773               132,141
Louisiana...................                59,948                41,963
Maryland....................                70,697                49,488
Michigan....................               178,605               125,024
Minnesota...................                49,987                34,991

[[Page 178]]

 
Mississippi.................                33,763                23,634
Missouri....................               137,214                96,050
New Jersey..................                32,392                22,674
New York....................               135,139                94,597
North Carolina..............               137,342                96,139
Ohio........................               333,520               233,464
Pennsylvania................               275,990               193,193
South Carolina..............                57,271                40,089
Tennessee...................               137,216                96,051
Texas.......................               320,946               224,662
Virginia....................                63,478                44,435
West Virginia...............               215,881               151,117
Wisconsin...................                87,264                61,085
------------------------------------------------------------------------

    (3) For a State that complies with the requirements of paragraph (a) 
of this section by imposing control measures on only non-EGUs, the 
amount of the Annual Non-EGU SO2 Reduction Requirement, in 
tons of SO2 per year, shall be determined, for the State for 
2010 and thereafter, by subtracting the amount of the State's Annual EGU 
SO2 Budget for the appropriate year, specified in paragraph 
(e)(2) of this section, from an amount equal to 2 times the State's 
Annual EGU SO2 Budget for 2010 through 2014, specified in 
paragraph (e)(2) of this section.
    (f) Each SIP revision must set forth control measures to meet the 
amounts specified in paragraph (e) of this section, as applicable, 
including the following:
    (1) A description of enforcement methods including, but not limited 
to:
    (i) Procedures for monitoring compliance with each of the selected 
control measures;
    (ii) Procedures for handling violations; and
    (iii) A designation of agency responsibility for enforcement of 
implementation.
    (2)(i) If a State elects to impose control measures on EGUs, then 
those measures must impose an annual SO2 mass emissions cap 
on all such sources in the State.
    (ii) If a State elects to impose control measures on fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then those measures must 
impose an annual SO2 mass emissions cap on all such sources 
in the State.
    (iii) If a State elects to impose control measures on non-EGUs other 
than those described in paragraph (f)(2)(ii) of this section, then those 
measures must impose an annual SO2 mass emissions cap on all 
such sources in the State, or the State must demonstrate why such 
emissions cap is not practicable, and adopt alternative requirements 
that ensure that the State will comply with its requirements under 
paragraph (e) of this section, as applicable, in 2010 and subsequent 
years.
    (g)(1) Each SIP revision that contains control measures covering 
non-EGUs as part or all of a State's obligation in meeting its 
requirement under paragraph (a) of this section must demonstrate that 
such control measures are adequate to provide for the timely compliance 
with the State's Annual Non-EGU SO2 Reduction Requirement 
under paragraph (e) of this section and are not adopted or implemented 
by the State, as of May 12, 2005, and are not adopted or implemented by 
the federal government, as of the date of submission of the SIP revision 
by the State to EPA.
    (2) The demonstration under paragraph (g)(1) of this section must 
include the following, with respect to each source category of non-EGUs 
for which the SIP revision requires control measures:
    (i) A detailed historical baseline inventory of SO2 mass 
emissions from the source category in a representative year consisting, 
at the State's election, of 2002, 2003, 2004, or 2005, or an average of 
2 or more of those years, absent the control measures specified in the 
SIP revision.

[[Page 179]]

    (A) This inventory must represent estimates of actual emissions 
based on monitoring data in accordance with part 75 of this chapter, if 
the source category is subject to part 75 monitoring requirements in 
accordance with part 75 of this chapter.
    (B) In the absence of monitoring data in accordance with part 75 of 
this chapter, actual emissions must be quantified, to the maximum extent 
practicable, with the same degree of assurance with which emissions are 
quantified for sources subject to part 75 of this chapter and using 
source-specific or source-category-specific assumptions that ensure a 
source's or source category's actual emissions are not overestimated. If 
a State uses factors to estimate emissions, production or utilization, 
or effectiveness of controls or rules for a source category, such 
factors must be chosen to ensure that emissions are not overestimated.
    (C) For measures to reduce emissions from motor vehicles, emission 
estimates must be based on an emissions model that has been approved by 
EPA for use in SIP development and must be consistent with the planning 
assumptions regarding vehicle miles traveled and other factors current 
at the time of the SIP development.
    (D) For measures to reduce emissions from nonroad engines or 
vehicles, emission estimates methodologies must be approved by EPA.
    (ii) A detailed baseline inventory of SO2 mass emissions 
from the source category in the years 2010 and 2015, absent the control 
measures specified in the SIP revision and reflecting changes in these 
emissions from the historical baseline year to the years 2010 and 2015, 
based on projected changes in the production input or output, 
population, vehicle miles traveled, economic activity, or other factors 
as applicable to this source category.
    (A) These inventories must account for implementation of any control 
measures that are adopted or implemented by the State, as of May 12, 
2005, or adopted or implemented by the federal government, as of the 
date of submission of the SIP revision by the State to EPA, and must 
exclude any control measures specified in the SIP revision to meet the 
SO2 emissions reduction requirements of this section.
    (B) Economic and population forecasts must be as specific as 
possible to the applicable industry, State, and county of the source or 
source category and must be consistent with both national projections 
and relevant official planning assumptions, including estimates of 
population and vehicle miles traveled developed through consultation 
between State and local transportation and air quality agencies. 
However, if these official planning assumptions are inconsistent with 
official U.S. Census projections of population or with energy 
consumption projections contained in the U.S. Department of Energy's 
most recent Annual Energy Outlook, then the SIP revision must make 
adjustments to correct the inconsistency or must demonstrate how the 
official planning assumptions are more accurate.
    (C) These inventories must account for any changes in production 
method, materials, fuels, or efficiency that are expected to occur 
between the historical baseline year and 2010 or 2015, as appropriate.
    (iii) A projection of SO2 mass emissions in 2010 and 2015 
from the source category assuming the same projected changes as under 
paragraph (g)(2)(ii) of this section and resulting from implementation 
of each of the control measures specified in the SIP revision.
    (A) These inventories must address the possibility that the State's 
new control measures may cause production or utilization, and emissions, 
to shift to unregulated or less stringently regulated sources in the 
source category in the same or another State, and these inventories must 
include any such amounts of emissions that may shift to such other 
sources.
    (B) The State must provide EPA with a summary of the computations, 
assumptions, and judgments used to determine the degree of reduction in 
projected 2010 and 2015 SO2 emissions that will be achieved 
from the implementation of the new control measures compared to the 
relevant baseline emissions inventory.
    (iv) The result of subtracting the amounts in paragraph (g)(2)(iii) 
of this section for 2010 and 2015, respectively,

[[Page 180]]

from the lower of the amounts in paragraph (g)(2)(i) or (g)(2)(ii) of 
this section for 2010 and 2015, respectively, may be credited towards 
the State's Annual Non-EGU SO2 Reduction Requirement in 
paragraph (e)(3) of this section for the appropriate period.
    (v) Each SIP revision must identify the sources of the data used in 
each estimate and each projection of emissions.
    (h) Each SIP revision must comply with Sec. 51.116 (regarding data 
availability).
    (i) Each SIP revision must provide for monitoring the status of 
compliance with any control measures adopted to meet the State's 
requirements under paragraph (e) of this section, as follows:
    (1) The SIP revision must provide for legally enforceable procedures 
for requiring owners or operators of stationary sources to maintain 
records of, and periodically report to the State:
    (i) Information on the amount of SO2 emissions from the 
stationary sources; and
    (ii) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable portions 
of the control measures;
    (2) The SIP revision must comply with Sec. 51.212 (regarding 
testing, inspection, enforcement, and complaints);
    (3) If the SIP revision contains any transportation control 
measures, then the SIP revision must comply with Sec. 51.213 (regarding 
transportation control measures);
    (4)(i) If the SIP revision contains measures to control EGUs, then 
the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of part 75 of this 
chapter.
    (ii) If the SIP revision contains measures to control fossil fuel-
fired non-EGUs that are boilers or combustion turbines with a maximum 
design heat input greater than 250 mmBtu/hr, then the SIP revision must 
require such sources to comply with the monitoring, recordkeeping, and 
reporting provisions of part 75 of this chapter.
    (iii) If the SIP revision contains measures to control any other 
non-EGUs that are not described in paragraph (i)(4)(ii) of this section, 
then the SIP revision must require such sources to comply with the 
monitoring, recordkeeping, and reporting provisions of part 75 of this 
chapter, or the State must demonstrate why such requirements are not 
practicable and adopt alternative requirements that ensure that the 
required emissions reductions will be quantified, to the maximum extent 
practicable, with the same degree of assurance with which emissions are 
quantified for sources subject to part 75 of this chapter.
    (j) Each SIP revision must show that the State has legal authority 
to carry out the SIP revision, including authority to:
    (1) Adopt emissions standards and limitations and any other measures 
necessary for attainment and maintenance of the State's relevant Annual 
EGU SO2 Budget or the Annual Non-EGU SO2 Reduction 
Requirement, as applicable, under paragraph (e) of this section;
    (2) Enforce applicable laws, regulations, and standards and seek 
injunctive relief;
    (3) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources; and
    (4)(i) Require owners or operators of stationary sources to install, 
maintain, and use emissions monitoring devices and to make periodic 
reports to the State on the nature and amounts of emissions from such 
stationary sources; and
    (ii) Make the data described in paragraph (j)(4)(i) of this section 
available to the public within a reasonable time after being reported 
and as correlated with any applicable emissions standards or 
limitations.
    (k)(1) The provisions of law or regulation that the State determines 
provide the authorities required under this section must be specifically 
identified, and copies of such laws or regulations must be submitted 
with the SIP revision.
    (2) Legal authority adequate to fulfill the requirements of 
paragraphs (j)(3)

[[Page 181]]

and (4) of this section may be delegated to the State under section 114 
of the CAA.
    (l)(1) A SIP revision may assign legal authority to local agencies 
in accordance with Sec. 51.232.
    (2) Each SIP revision must comply with Sec. 51.240 (regarding 
general plan requirements).
    (m) Each SIP revision must comply with Sec. 51.280 (regarding 
resources).
    (n) Each SIP revision must provide for State compliance with the 
reporting requirements in Sec. 51.125.
    (o)(1) Notwithstanding any other provision of this section, if a 
State adopts regulations substantively identical to subparts AAA through 
III of part 96 of this chapter (CAIR SO2 Trading Program), 
incorporates such subparts by reference into its regulations, or adopts 
regulations that differ substantively from such subparts only as set 
forth in paragraph (o)(2) of this section, then such emissions trading 
program in the State's SIP revision is automatically approved as meeting 
the requirements of paragraph (e) of this section, provided that the 
State has the legal authority to take such action and to implement its 
responsibilities under such regulations.
    (2) If a State adopts an emissions trading program that differs 
substantively from subparts AAA through III of part 96 of this chapter 
only as follows, then the emissions trading program is approved as set 
forth in paragraph (o)(1) of this section.
    (i) The State may decline to adopt the CAIR SO2 opt-in 
provisions of subpart III of this part and the provisions applicable 
only to CAIR SO2 opt-in units in subparts AAA through HHH of 
this part.
    (ii) The State may decline to adopt the CAIR SO2 opt-in 
provisions of Sec. 96.288(b) of this chapter and the provisions of 
subpart III of this part applicable only to CAIR SO2 opt-in 
units under Sec. 96.288(b).
    (iii) The State may decline to adopt the CAIR SO2 opt-in 
provisions of Sec. 96.288(c) of this chapter and the provisions of 
subpart II of this part applicable only to CAIR SO2 opt-in 
units under Sec. 96.288(c).
    (3) A State that adopts an emissions trading program in accordance 
with paragraph (o)(1) or (2) of this section is not required to adopt an 
emissions trading program in accordance with Sec. 96.123 (o)(1) or (2) 
or (aa)(1) or (2) of this chapter.
    (4) If a State adopts an emissions trading program that differs 
substantively from subparts AAA through III of part 96 of this chapter, 
other than as set forth in paragraph (o)(2) of this section, then such 
emissions trading program is not automatically approved as set forth in 
paragraph (o)(1) or (2) of this section and will be reviewed by the 
Administrator for approvability in accordance with the other provisions 
of this section, provided that the SO2 allowances issued 
under such emissions trading program shall not, and the SIP revision 
shall state that such SO2 allowances shall not, qualify as 
CAIR SO2 allowances under any emissions trading program 
approved under paragraph (o)(1) or (2) of this section.
    (p) If a State's SIP revision does not contain an emissions trading 
program approved under paragraph (o)(1) or (2) of this section but 
contains control measures on EGUs as part or all of a State's obligation 
in meeting its requirement under paragraph (a) of this section:
    (1) The SIP revision shall provide, for each year that the State has 
such obligation, for the permanent retirement of an amount of Acid Rain 
allowances allocated to sources in the State for that year and not 
deducted by the Administrator under the Acid Rain Program and any 
emissions trading program approved under paragraph (o)(1) or (2) of this 
section, equal to the difference between--
    (A) The total amount of Acid Rain allowances allocated under the 
Acid Rain Program to the sources in the State for that year; and
    (B) If the State's SIP revision contains only control measures on 
EGUs, the State's Annual EGU SO2 Budget for the appropriate 
period as specified in paragraph (e)(2) of this section or, if the 
State's SIP revision contains control measures on EGUs and non-EGUs, the 
State's Annual EGU SO2 Budget for the appropriate period as 
specified in the SIP revision.

[[Page 182]]

    (2) The SIP revision providing for permanent retirement of Acid Rain 
allowances under paragraph (p)(1) of this section must ensure that such 
allowances are not available for deduction by the Administrator under 
the Acid Rain Program and any emissions trading program approved under 
paragraph (o)(1) or (2) of this section.
    (q) The terms used in this section shall have the following 
meanings:
    Acid Rain allowance means a limited authorization issued by the 
Administrator under the Acid Rain Program to emit up to one ton of 
sulfur dioxide during the specified year or any year thereafter, except 
as otherwise provided by the Administrator.
    Acid Rain Program means a multi-State sulfur dioxide and nitrogen 
oxides air pollution control and emissions reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to allowances, the 
determination of the amount of allowances to be initially credited to a 
source.
    Boiler means an enclosed fossil- or other-fuel-fired combustion 
device used to produce heat and to transfer heat to recirculating water, 
steam, or other medium.
    Bottoming-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful thermal 
energy and at least some of the reject heat from the useful thermal 
energy application or process is then used for electricity production.
    Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et 
seq.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after which 
the unit first produces electricity--
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less then 42.5 percent of total energy input, if 
useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input.
    Combustion turbine means:
    (1) An enclosed device comprising a compressor, a combustor, and a 
turbine and in which the flue gas resulting from the combustion of fuel 
in the combustor passes through the turbine, rotating the turbine; and
    (2) If the enclosed device under paragraph (1) of this definition is 
combined cycle, any associated heat recovery steam generator and steam 
turbine.
    Commence operation means to have begun any mechanical, chemical, or 
electronic process, including, with regard to a unit, start-up of a 
unit's combustion chamber.
    Electric generating unit or EGU means:
    (1)(i) Except as provided in paragraph (2) of this definition, a 
stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired 
combustion turbine serving at any time, since the later of November 15, 
1990 or the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale.
    (ii) If a stationary boiler or stationary combustion turbine that, 
under paragraph (1)(i) of this section, is not an electric generating 
unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become an electric generating unit as provided in 
paragraph (1)(i) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.

[[Page 183]]

    (2) A unit that meets the requirements set forth in paragraphs 
(2)(i)(A), (2)(ii)(A), or (2)(ii)(B) of this definition paragraph shall 
not be an electric generating unit:
    (i)(A) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition:
    (1) Qualifying as a cogeneration unit during the 12-month period 
starting on the date the unit first produces electricity and continuing 
to qualify as a cogeneration unit; and
    (2) Not serving at any time, since the later of November 15, 1990 or 
the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (B) If a unit qualifies as a cogeneration unit during the 12-month 
period starting on the date the unit first produces electricity and 
meets the requirements of paragraphs (2)(i)(A) of this section for at 
least one calendar year, but subsequently no longer meets all such 
requirements, the unit shall become an electric generating unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (2)(i)(A)(2) of this section.
    (ii)(A) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition commencing operation before January 1, 
1985:
    (1) Qualifying as a solid waste incineration unit; and
    (2) With an average annual fuel consumption of non-fossil fuel for 
1985-1987 exceeding 80 percent (on a Btu basis) and an average annual 
fuel consumption of non-fossil fuel for any 3 consecutive calendar years 
after 1990 exceeding 80 percent (on a Btu basis).
    (B) Any unit that is an electric generating unit under paragraph 
(1)(i) or (ii) of this definition commencing operation on or after 
January 1, 1985:
    (1) Qualifying as a solid waste incineration unit; and
    (2) With an average annual fuel consumption of non-fossil fuel for 
the first 3 calendar years of operation exceeding 80 percent (on a Btu 
basis) and an average annual fuel consumption of non-fossil fuel for any 
3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu 
basis).
    (C) If a unit qualifies as a solid waste incineration unit and meets 
the requirements of paragraph (2)(ii)(A) or (B) of this section for at 
least 3 consecutive calendar years, but subsequently no longer meets all 
such requirements, the unit shall become an electric generating unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in any calendar year.
    Generator means a device that produces electricity.
    Maximum design heat input means:
    (1) Starting from the initial installation of a unit, the maximum 
amount of fuel per hour (in Btu/hr) that a unit is capable of combusting 
on a steady state basis as specified by the manufacturer of the unit;
    (2)(i) Except as provided in paragraph (2)(ii) of this definition, 
starting from the completion of any subsequent physical change in the 
unit resulting in an increase in the maximum amount of fuel per hour (in 
Btu/hr) that a unit is capable of combusting on a steady state basis, 
such increased maximum amount as specified by the person conducting the 
physical change; or
    (ii) For purposes of applying the definition of the term ``potential 
electrical output capacity,'' starting from the completion of any 
subsequent physical change in the unit resulting in a decrease in the 
maximum amount of fuel per hour (in Btu/hr) that a unit is capable of 
combusting on a steady state basis, such decreased maximum

[[Page 184]]

amount as specified by the person conducting the physical change.
    NAAQS means National Ambient Air Quality Standard.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe) that the 
generator is capable of producing on a steady state basis and during 
continuous operation (when not restricted by seasonal or other 
deratings) as specified by the manufacturer of the generator or, 
starting from the completion of any subsequent physical change in the 
generator resulting in an increase in the maximum electrical generating 
output (in MWe) that the generator is capable of producing on a steady 
state basis and during continuous operation (when not restricted by 
seasonal or other deratings), such increased maximum amount as specified 
by the person conducting the physical change.
    Non-EGU means a source of SO2 emissions that is not an 
EGU.
    Potential electrical output capacity means 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Sequential use of energy means:
    (1) For a topping-cycle cogeneration unit, the use of reject heat 
from electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle cogeneration unit, the use of reject heat 
from useful thermal energy application or process in electricity 
production.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of the 
Clean Air Act.
    Topping-cycle cogeneration unit means a cogeneration unit in which 
the energy input to the unit is first used to produce useful power, 
including electricity, and at least some of the reject heat from the 
electricity production is then used to provide useful thermal energy.
    Total energy input means, with regard to a cogeneration unit, total 
energy of all forms supplied to the cogeneration unit, excluding energy 
produced by the cogeneration unit itself.
    Total energy output means, with regard to a cogeneration unit, the 
sum of useful power and useful thermal energy produced by the 
cogeneration unit.
    Unit means a stationary, fossil-fuel-fired boiler or a stationary, 
fossil-fuel fired combustion turbine.
    Useful power means, with regard to a cogeneration unit, electricity 
or mechanical energy made available for use, excluding any such energy 
used in the power production process (which process includes, but is not 
limited to, any on-site processing or treatment of fuel combusted at the 
unit and any on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process, excluding 
any heat contained in condensate return or makeup water;
    (2) Used in a heat application (e.g., space heating or domestic hot 
water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.
    (r) Notwithstanding any other provision of this section, a State may 
adopt, and include in a SIP revision submitted by March 31, 2007, 
regulations relating to the Federal CAIR SO2 Trading Program 
under subparts AAA through HHH of part 97 of this chapter as follows. 
The State may adopt the following CAIR opt-in unit provisions:
    (1) Provisions for CAIR opt-in units, including provisions for 
applications for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR SO2 allowances for CAIR opt-in units, that are 
substantively identical to subpart III of part 96 of this chapter and 
the provisions of subparts AAA through HHH that are applicable to CAIR 
opt-in units or units for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied;
    (2) Provisions for CAIR opt-in units, including provisions for 
applications

[[Page 185]]

for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of 
units as CAIR opt-in units, and allocation and recordation of CAIR 
SO2 allowances for CAIR opt-in units, that are substantively 
identical to subpart III of part 96 of this chapter and the provisions 
of subparts AAA through HHH that are applicable to CAIR opt-in units or 
units for which a CAIR opt-in permit application is submitted and not 
withdrawn and a CAIR opt-in permit is not yet issued or denied, except 
that the provisions exclude Sec. 96.288(b) of this chapter and the 
provisions of subpart III of part 96 of this chapter that apply only to 
units covered by Sec. 96.288(b) of this chapter; or
    (3) Provisions for applications for CAIR opt-in units, including 
provisions for CAIR opt-in permits, approval of CAIR opt-in permits, 
treatment of units as CAIR opt-in units, and allocation and recordation 
of CAIR SO2 allowances for CAIR opt-in units, that are 
substantively identical to subpart III of part 96 of this chapter and 
the provisions of subparts AAA through HHH that are applicable to CAIR 
opt-in units or units for which a CAIR opt-in permit application is 
submitted and not withdrawn and a CAIR opt-in permit is not yet issued 
or denied, except that the provisions exclude Sec. 96.288(c) of this 
chapter and the provisions of subpart III of part 96 of this chapter 
that apply only to units covered by Sec. 96.288(c) of this chapter.

[70 FR 25328, May 12, 2005, as amended at 71 FR 25302, 25372, Apr. 28, 
2006]



Sec. 51.125  Emissions reporting requirements for SIP revisions relating 
to budgets for SO2 and NOX emissions.

    (a) For its transport SIP revision under Sec. 51.123 and/or 51.124, 
each State must submit to EPA SO2 and/or NOX 
emissions data as described in this section.
    (1) Alabama, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, 
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, 
Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, 
South Carolina, Tennessee, Texas, Virginia, West Virginia, Wisconsin, 
and the District of Columbia.
    (2) Alabama, Arkansas, Connecticut, Deleware, Florida, Illinois, 
Indinia, Iowa, Kentucky, Lousianna, Maryland, Massachusetts, Michigan, 
Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, 
Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, 
Wisconsin and the District of Columbia must report ozone season (May 1 
through September 30) emissions of NOX.
    (b) Each revision must provide for periodic reporting by the State 
of SO2 and/or NOX emissions data as specified in 
paragraph (a) of this section to demonstrate whether the State's 
emissions are consistent with the projections contained in its approved 
SIP submission.
    (1) Every-year reporting cycle. As applicable, each revision must 
provide for reporting of SO2 and NOX emissions 
data every year as follows:
    (i) The States identified in paragraph (a)(1) of this section must 
report to EPA annual emissions data every year from all SO2 
and NOX sources within the State for which the State 
specified control measures in its SIP submission under Sec. Sec. 51.123 
and/or 51.124.
    (ii) The States identified in paragraph (a)(2) of this section must 
report to EPA ozone season and summer daily emissions data every year 
from all NOX sources within the State for which the State 
specified control measures in its SIP submission under Sec. 51.123.
    (iii) If sources report SO2 and NOX emissions 
data to EPA in a given year pursuant to a trading program approved under 
Sec. 51.123(o) or Sec. 51.124(o) of this part or pursuant to the 
monitoring and reporting requirements of 40 CFR part 75, then the State 
need not provide annual reporting of these pollutants to EPA for such 
sources.
    (2) Three-year reporting cycle. As applicable, each plan must 
provide for triennial (i.e., every third year) reporting of 
SO2 and NOX emissions data from all sources within 
the State.
    (i) The States identified in paragraph (a)(1) of this section must 
report to EPA annual emissions data every third year from all 
SO2 and NOX sources within the State.
    (ii) The States identified in paragraph (a)(2) of this section must 
report to EPA ozone season and ozone daily

[[Page 186]]

emissions data every third year from all NOX sources within 
the State.
    (3) The data availability requirements in Sec. 51.116 must be 
followed for all data submitted to meet the requirements of paragraphs 
(b)(1) and (2) of this section.
    (c) The data reported in paragraph (b) of this section must meet the 
requirements of subpart A of this part.
    (d) Approval of annual and ozone season calculation by EPA. Each 
State must submit for EPA approval an example of the calculation 
procedure used to calculate annual and ozone season emissions along with 
sufficient information for EPA to verify the calculated value of annual 
and ozone season emissions.
    (e) Reporting schedules. (1) Reports are to begin with data for 
emissions occurring in the year 2008, which is the first year of the 3-
year cycle.
    (2) After 2008, 3-year cycle reports are to be submitted every third 
year and every-year cycle reports are to be submitted each year that a 
triennial report is not required.
    (3) States must submit data for a required year no later than 17 
months after the end of the calendar year for which the data are 
collected.
    (f) Data reporting procedures are given in subpart A of this part. 
When submitting a formal NOX budget emissions report and 
associated data, States shall notify the appropriate EPA Regional 
Office.
    (g) Definitions. (1) As used in this section, ``ozone season'' is 
defined as follows:
    Ozone season.--The five month period from May 1 through September 
30.
    (2) Other words and terms shall have the meanings set forth in 
appendix A of subpart A of this part.

[70 FR 25333, May 12, 2005, as amended at 71 FR 25302, Apr. 28, 2006]



        Subpart H_Prevention of Air Pollution Emergency Episodes

    Source: 51 FR 40668, Nov. 7, 1986, unless otherwise noted.



Sec. 51.150  Classification of regions for episode plans.

    (a) This section continues the classification system for episode 
plans. Each region is classified separately with respect to each of the 
following pollutants: Sulfur oxides, particulate matter, carbon 
monoxide, nitrogen dioxide, and ozone.
    (b) Priority I Regions means any area with greater ambient 
concentrations than the following:
    (1) Sulfur dioxide--100 [micro]g/m\3\ (0.04 ppm) annual arithmetic 
mean; 455 [micro]g/m\3\ (0.17 ppm) 24-hour maximum.
    (2) Particulate matter--95 [micro]g/m\3\ annual geometric mean; 325 
[micro]g/m\3\ 24-hour maximum.
    (3) Carbon monoxide--55 mg/m\3\ (48 ppm) 1-hour maximum; 14 mg/m\3\ 
(12 ppm) 8-hour maximum.
    (4) Nitrogen dioxide--100 [micro]g/m\3\ (0.06 ppm) annual arithmetic 
mean.
    (5) Ozone--195 [micro]g/m\3\ (0.10 ppm) 1-hour maximum.
    (c) Priority IA Region means any area which is Priority I primarily 
because of emissions from a single point source.
    (d) Priority II Region means any area which is not a Priority I 
region and has ambient concentrations between the following:
    (1) Sulfur Dioxides--60-100 [micro]g/m\3\ (0.02-0.04 ppm) annual 
arithmetic mean; 260-445 [micro]g/m\3\ (0.10-0.17 ppm) 24-hour maximum; 
any concentration above 1,300 [micro]g/m\3\ (0.50 ppm) three-hour 
average.
    (2) Particulate matter--60-95 [micro]g/m\3\ annual geometric mean; 
150-325 [micro]g/m\3\ 24-hour maximum.
    (e) In the absence of adequate monitoring data, appropriate models 
must be used to classify an area under paragraph (b) of this section, 
consistent with the requirements contained in Sec. 51.112(a).
    (f) Areas which do not meet the above criteria are classified 
Priority III.

[51 FR 40668, Nov. 7, 1986, as amended at 58 FR 38822, July 20, 1993]



Sec. 51.151  Significant harm levels.

    Each plan for a Priority I region must include a contingency plan 
which must, as a mimimum, provide for taking action necessary to prevent 
ambient pollutant concentrations at any location in such region from 
reaching the following levels:

Sulfur dioxide--2.620 [micro]g/m\3\ (1.0 ppm) 24-hour average.

[[Page 187]]

PM10--600 micrograms/cubic meter; 24-hour average.
Carbon monoxide--57.5 mg/m\3\ (50 ppm) 8-hour average; 86.3 mg/m\3\ (75 
ppm) 4-hour average; 144 mg/m\3\ (125 ppm) 1-hour average.
Ozone--1,200 ug/m\3\ (0.6 ppm) 2-hour average.
Nitrogen dioxide--3.750 ug/m\3\ (2.0 ppm) 1-hour average; 938 ug/m\3\ 
(0.5 ppm) 24-hour average.

[51 FR 40668, Nov. 7, 1986, as amended at 52 FR 24713, July 1, 1987]



Sec. 51.152  Contingency plans.

    (a) Each contingency plan must--
    (1) Specify two or more stages of episode criteria such as those set 
forth in appendix L to this part, or their equivalent;
    (2) Provide for public announcement whenever any episode stage has 
been determined to exist; and
    (3) Specify adequate emission control actions to be taken at each 
episode stage. (Examples of emission control actions are set forth in 
appendix L.)
    (b) Each contingency plan for a Priority I region must provide for 
the following:
    (1) Prompt acquisition of forecasts of atmospheric stagnation 
conditions and of updates of such forecasts as frequently as they are 
issued by the National Weather Service.
    (2) Inspection of sources to ascertain compliance with applicable 
emission control action requirements.
    (3) Communications procedures for transmitting status reports and 
orders as to emission control actions to be taken during an episode 
stage, including procedures for contact with public officials, major 
emission sources, public health, safety, and emergency agencies and news 
media.
    (c) Each plan for a Priority IA and II region must include a 
contingency plan that meets, as a minimum, the requirements of 
paragraphs (b)(1) and (b)(2) of this section. Areas classified Priority 
III do not need to develop episode plans.
    (d) Notwithstanding the requirements of paragraphs (b) and (c) of 
this section, the Administrator may, at his discretion--
    (1) Exempt from the requirements of this section those portions of 
Priority I, IA, or II regions which have been designated as attainment 
or unclassifiable for national primary and secondary standards under 
section 107 of the Act; or
    (2) Limit the requirements pertaining to emission control actions in 
Priority I regions to--
    (i) Urbanized areas as identified in the most recent United States 
Census, and
    (ii) Major emitting facilities, as defined by section 169(1) of the 
Act, outside the urbanized areas.



Sec. 51.153  Reevaluation of episode plans.

    (a) States should periodically reevaluate priority classifications 
of all Regions or portion of Regions within their borders. The 
reevaluation must consider the three most recent years of air quality 
data. If the evaluation indicates a change to a higher priority 
classification, appropriate changes in the episode plan must be made as 
expeditiously as practicable.
    (b) [Reserved]



            Subpart I_Review of New Sources and Modifications

    Source: 51 FR 40669, Nov. 7, 1986, unless otherwise noted.



Sec. 51.160  Legally enforceable procedures.

    (a) Each plan must set forth legally enforceable procedures that 
enable the State or local agency to determine whether the construction 
or modification of a facility, building, structure or installation, or 
combination of these will result in--
    (1) A violation of applicable portions of the control strategy; or
    (2) Interference with attainment or maintenance of a national 
standard in the State in which the proposed source (or modification) is 
located or in a neighboring State.
    (b) Such procedures must include means by which the State or local 
agency responsible for final decisionmaking on an application for 
approval to construct or modify will prevent such construction or 
modification if--
    (1) It will result in a violation of applicable portions of the 
control strategy; or
    (2) It will interfere with the attainment or maintenance of a 
national standard.

[[Page 188]]

    (c) The procedures must provide for the submission, by the owner or 
operator of the building, facility, structure, or installation to be 
constructed or modified, of such information on--
    (1) The nature and amounts of emissions to be emitted by it or 
emitted by associated mobile sources;
    (2) The location, design, construction, and operation of such 
facility, building, structure, or installation as may be necessary to 
permit the State or local agency to make the determination referred to 
in paragraph (a) of this section.
    (d) The procedures must provide that approval of any construction or 
modification must not affect the responsibility to the owner or operator 
to comply with applicable portions of the control strategy.
    (e) The procedures must identify types and sizes of facilities, 
buildings, structures, or installations which will be subject to review 
under this section. The plan must discuss the basis for determining 
which facilities will be subject to review.
    (f) The procedures must discuss the air quality data and the 
dispersion or other air quality modeling used to meet the requirements 
of this subpart.
    (1) All applications of air quality modeling involved in this 
subpart shall be based on the applicable models, data bases, and other 
requirements specified in appendix W of this part (Guideline on Air 
Quality Models).
    (2) Where an air quality model specified in appendix W of this part 
(Guideline on Air Quality Models) is inappropriate, the model may be 
modified or another model substituted. Such a modification or 
substitution of a model may be made on a case-by-case basis or, where 
appropriate, on a generic basis for a specific State program. Written 
approval of the Administrator must be obtained for any modification or 
substitution. In addition, use of a modified or substituted model must 
be subject to notice and opportunity for public comment under procedures 
set forth in Sec. 51.102.

[51 FR 40669, Nov. 7, 1986, as amended at 58 FR 38822, July 20, 1993; 60 
FR 40468, Aug. 9, 1995; 61 FR 41840, Aug. 12, 1996]



Sec. 51.161  Public availability of information.

    (a) The legally enforceable procedures in Sec. 51.160 must also 
require the State or local agency to provide opportunity for public 
comment on information submitted by owners and operators. The public 
information must include the agency's analysis of the effect of 
construction or modification on ambient air quality, including the 
agency's proposed approval or disapproval.
    (b) For purposes of paragraph (a) of this section, opportunity for 
public comment shall include, as a minimum--
    (1) Availability for public inspection in at least one location in 
the area affected of the information submitted by the owner or operator 
and of the State or local agency's analysis of the effect on air 
quality;
    (2) A 30-day period for submittal of public comment; and
    (3) A notice by prominent advertisement in the area affected of the 
location of the source information and analysis specified in paragraph 
(b)(1) of this section.
    (c) Where the 30-day comment period required in paragraph (b) of 
this section would conflict with existing requirements for acting on 
requests for permission to construct or modify, the State may submit for 
approval a comment period which is consistent with such existing 
requirements.
    (d) A copy of the notice required by paragraph (b) of this section 
must also be sent to the Administrator through the appropriate Regional 
Office, and to all other State and local air pollution control agencies 
having jurisdiction in the region in which such new or modified 
installation will be located. The notice also must be sent to any other 
agency in the region having responsibility for implementing the 
procedures required under this subpart. For lead, a copy of the notice 
is required for all point sources. The definition of point for lead is 
given in Sec. 51.100(k)(2).



Sec. 51.162  Identification of responsible agency.

    Each plan must identify the State or local agency which will be 
responsible for meeting the requirements of this

[[Page 189]]

subpart in each area of the State. Where such responsibility rests with 
an agency other than an air pollution control agency, such agency will 
consult with the appropriate State or local air pollution control agency 
in carrying out the provisions of this subpart.



Sec. 51.163  Administrative procedures.

    The plan must include the administrative procedures, which will be 
followed in making the determination specified in paragraph (a) of Sec. 
51.160.



Sec. 51.164  Stack height procedures.

    Such procedures must provide that the degree of emission limitation 
required of any source for control of any air pollutant must not be 
affected by so much of any source's stack height that exceeds good 
engineering practice or by any other dispersion technique, except as 
provided in Sec. 51.118(b). Such procedures must provide that before a 
State issues a permit to a source based on a good engineering practice 
stack height that exceeds the height allowed by Sec. 51.100(ii) (1) or 
(2), the State must notify the public of the availability of the 
demonstration study and must provide opportunity for public hearing on 
it. This section does not require such procedures to restrict in any 
manner the actual stack height of any source.



Sec. 51.165  Permit requirements.

    (a) State Implementation Plan and Tribal Implementation Plan 
provisions satisfying sections 172(c)(5) and 173 of the Act shall meet 
the following conditions:
    (1) All such plans shall use the specific definitions. Deviations 
from the following wording will be approved only if the State 
specifically demonstrates that the submitted definition is more 
stringent, or at least as stringent, in all respects as the 
corresponding definition below:
    (i) Stationary source means any building, structure, facility, or 
installation which emits or may emit a regulated NSR pollutant.
    (ii) Building, structure, facility, or installation means all of the 
pollutant-emitting activities which belong to the same industrial 
grouping, are located on one or more contiguous or adjacent properties, 
and are under the control of the same person (or persons under common 
control) except the activities of any vessel. Pollutant-emitting 
activities shall be considered as part of the same industrial grouping 
if they belong to the same Major Group (i.e., which have the same two-
digit code) as described in the Standard Industrial Classification 
Manual, 1972, as amended by the 1977 Supplement (U.S. Government 
Printing Office stock numbers 4101-0065 and 003-005-00176-0, 
respectively).
    (iii) Potential to emit means the maximum capacity of a stationary 
source to emit a pollutant under its physical and operational design. 
Any physical or operational limitation on the capacity of the source to 
emit a pollutant, including air pollution control equipment and 
restrictions on hours of operation or on the type or amount of material 
combusted, stored, or processed, shall be treated as part of its design 
only if the limitation or the effect it would have on emissions is 
federally enforceable. Secondary emissions do not count in determining 
the potential to emit of a stationary source.
    (iv)(A) Major stationary source means:
    (1) Any stationary source of air pollutants that emits, or has the 
potential to emit, 100 tons per year or more of any regulated NSR 
pollutant, except that lower emissions thresholds shall apply in areas 
subject to subpart 2, subpart 3, or subpart 4 of part D, title I of the 
Act, according to paragraphs (a)(1)(iv)(A)(1)(i) through (vi) of this 
section.
    (i) 50 tons per year of volatile organic compounds in any serious 
ozone nonattainment area.
    (ii) 50 tons per year of volatile organic compounds in an area 
within an ozone transport region, except for any severe or extreme ozone 
nonattainment area.
    (iii) 25 tons per year of volatile organic compounds in any severe 
ozone nonattainment area.
    (iv) 10 tons per year of volatile organic compounds in any extreme 
ozone nonattainment area.
    (v) 50 tons per year of carbon monoxide in any serious nonattainment 
area for carbon monoxide, where stationary sources contribute 
significantly to carbon monoxide levels in the

[[Page 190]]

area (as determined under rules issued by the Administrator).
    (vi) 70 tons per year of PM-10 in any serious nonattainment area for 
PM-10;
    (2) For the purposes of applying the requirements of paragraph 
(a)(8) of this section to stationary sources of nitrogen oxides located 
in an ozone nonattainment area or in an ozone transport region, any 
stationary source which emits, or has the potential to emit, 100 tons 
per year or more of nitrogen oxides emissions, except that the emission 
thresholds in paragraphs (a)(1)(iv)(A)(2)(i) through (vi) of this 
section shall apply in areas subject to subpart 2 of part D, title I of 
the Act.
    (i) 100 tons per year or more of nitrogen oxides in any ozone 
nonattainment area classified as marginal or moderate.
    (ii) 100 tons per year or more of nitrogen oxides in any ozone 
nonattainment area classified as a transitional, submarginal, or 
incomplete or no data area, when such area is located in an ozone 
transport region.
    (iii) 100 tons per year or more of nitrogen oxides in any area 
designated under section 107(d) of the Act as attainment or 
unclassifiable for ozone that is located in an ozone transport region.
    (iv) 50 tons per year or more of nitrogen oxides in any serious 
nonattainment area for ozone.
    (v) 25 tons per year or more of nitrogen oxides in any severe 
nonattainment area for ozone.
    (vi) 10 tons per year or more of nitrogen oxides in any extreme 
nonattainment area for ozone; or
    (3) Any physical change that would occur at a stationary source not 
qualifying under paragraphs (a)(1)(iv)(A)(1) or (2) of this section as a 
major stationary source, if the change would constitute a major 
stationary source by itself.
    (B) A major stationary source that is major for volatile organic 
compounds shall be considered major for ozone
    (C) The fugitive emissions of a stationary source shall not be 
included in determining for any of the purposes of this paragraph 
whether it is a major stationary source, unless the source belongs to 
one of the following categories of stationary sources:
    (1) Coal cleaning plants (with thermal dryers);
    (2) Kraft pulp mills;
    (3) Portland cement plants;
    (4) Primary zinc smelters;
    (5) Iron and steel mills;
    (6) Primary aluminum ore reduction plants;
    (7) Primary copper smelters;
    (8) Municipal incinerators capable of charging more than 250 tons of 
refuse per day;
    (9) Hydrofluoric, sulfuric, or nitric acid plants;
    (10) Petroleum refineries;
    (11) Lime plants;
    (12) Phosphate rock processing plants;
    (13) Coke oven batteries;
    (14) Sulfur recovery plants;
    (15) Carbon black plants (furnace process);
    (16) Primary lead smelters;
    (17) Fuel conversion plants;
    (18) Sintering plants;
    (19) Secondary metal production plants;
    (20) Chemical process plants;
    (21) Fossil-fuel boilers (or combination thereof) totaling more than 
250 million British thermal units per hour heat input;
    (22) Petroleum storage and transfer units with a total storage 
capacity exceeding 300,000 barrels;
    (23) Taconite ore processing plants;
    (24) Glass fiber processing plants;
    (25) Charcoal production plants;
    (26) Fossil fuel-fired steam electric plants of more than 250 
million British thermal units per hour heat input; and
    (27) Any other stationary source category which, as of August 7, 
1980, is being regulated under section 111 or 112 of the Act.
    (v)(A) Major modification means any physical change in or change in 
the method of operation of a major stationary source that would result 
in:
    (1) A significant emissions increase of a regulated NSR pollutant 
(as defined in paragraph (a)(1)(xxxvii) of this section); and
    (2) A significant net emissions increase of that pollutant from the 
major stationary source.
    (B) Any significant emissions increase (as defined in paragraph 
(a)(1)(xxvii) of this section) from any

[[Page 191]]

emissions units or net emissions increase (as defined in paragraph 
(a)(1)(vi) of this section) at a major stationary source that is 
significant for volatile organic compounds shall be considered 
significant for ozone.
    (C) A physical change or change in the method of operation shall not 
include:
    (1) Routine maintenance, repair and replacement. Routine 
maintenance, repair and replacement shall include, but not be limited 
to, any activity(s) that meets the requirements of the equipment 
replacement provisions contained in paragraph (h) of this section;
    Note to paragraph (a)(1)(v)(C)(1):
    On December 24, 2003, the second sentence of this paragraph 
(a)(1)(v)(C)(1) is stayed indefinitely by court order. The stayed 
provisions will become effective immediately if the court terminates the 
stay. At that time, EPA will publish a document in the Federal Register 
advising the public of the termination of the stay.
    (2) Use of an alternative fuel or raw material by reason of an order 
under sections 2 (a) and (b) of the Energy Supply and Environmental 
Coordination Act of 1974 (or any superseding legislation) or by reason 
of a natural gas curtailment plan pursuant to the Federal Power Act;
    (3) Use of an alternative fuel by reason of an order or rule section 
125 of the Act;
    (4) Use of an alternative fuel at a steam generating unit to the 
extent that the fuel is generated from municipal solid waste;
    (5) Use of an alternative fuel or raw material by a stationary 
source which;
    (i) The source was capable of accommodating before December 21, 
1976, unless such change would be prohibited under any federally 
enforceable permit condition which was established after December 12, 
1976 pursuant to 40 CFR 52.21 or under regulations approved pursuant to 
40 CFR subpart I or Sec. 51.166, or
    (ii) The source is approved to use under any permit issued under 
regulations approved pursuant to this section;
    (6) An increase in the hours of operation or in the production rate, 
unless such change is prohibited under any federally enforceable permit 
condition which was established after December 21, 1976 pursuant to 40 
CFR 52.21 or regulations approved pursuant to 40 CFR part 51 subpart I 
or 40 CFR 51.166.
    (7) Any change in ownership at a stationary source.
    (8) The addition, replacement, or use of a PCP, as defined in 
paragraph (a)(1)(xxv) of this section, at an existing emissions unit 
meeting the requirements of paragraph (e) of this section. A replacement 
control technology must provide more effective emissions control than 
that of the replaced control technology to qualify for this exclusion.
    (9) The installation, operation, cessation, or removal of a 
temporary clean coal technology demonstration project, provided that the 
project complies with:
    (i) The State Implementation Plan for the State in which the project 
is located, and
    (ii) Other requirements necessary to attain and maintain the 
national ambient air quality standard during the project and after it is 
terminated.
    (D) This definition shall not apply with respect to a particular 
regulated NSR pollutant when the major stationary source is complying 
with the requirements under paragraph (f) of this section for a PAL for 
that pollutant. Instead, the definition at paragraph (f)(2)(viii) of 
this section shall apply.
    (E) For the purpose of applying the requirements of (a)(8) of this 
section to modifications at major stationary sources of nitrogen oxides 
located in ozone nonattainment areas or in ozone transport regions, 
whether or not subject to subpart 2, part D, title I of the Act, any 
significant net emissions increase of nitrogen oxides is considered 
significant for ozone.
    (F) Any physical change in, or change in the method of operation of, 
a major stationary source of volatile organic compounds that results in 
any increase in emissions of volatile organic compounds from any 
discrete operation, emissions unit, or other pollutant emitting activity 
at the source shall be considered a significant net emissions increase 
and a major modification for ozone, if the major stationary source is 
located in an extreme

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ozone nonattainment area that is subject to subpart 2, part D, title I 
of the Act.
    (vi)(A) Net emissions increase means, with respect to any regulated 
NSR pollutant emitted by a major stationary source, the amount by which 
the sum of the following exceeds zero:
    (1) The increase in emissions from a particular physical change or 
change in the method of operation at a stationary source as calculated 
pursuant to paragraph (a)(2)(ii) of this section; and
    (2) Any other increases and decreases in actual emissions at the 
major stationary source that are contemporaneous with the particular 
change and are otherwise creditable. Baseline actual emissions for 
calculating increases and decreases under this paragraph 
(a)(1)(vi)(A)(2) shall be determined as provided in paragraph 
(a)(1)(xxxv) of this section, except that paragraphs (a)(1)(xxxv)(A)(3) 
and (a)(1)(xxxv)(B)(4) of this section shall not apply.
    (B) An increase or decrease in actual emissions is contemporaneous 
with the increase from the particular change only if it occurs before 
the date that the increase from the particular change occurs;
    (C) An increase or decrease in actual emissions is creditable only 
if:
    (1) It occurs within a reasonable period to be specified by the 
reviewing authority; and
    (2) The reviewing authority has not relied on it in issuing a permit 
for the source under regulations approved pursuant to this section, 
which permit is in effect when the increase in actual emissions from the 
particular change occurs; and
    (3) The increase or decrease in emissions did not occur at a Clean 
Unit, except as provided in paragraphs (c)(8) and (d)(10) of this 
section.
    (D) An increase in actual emissions is creditable only to the extent 
that the new level of actual emissions exceeds the old level.
    (E) A decrease in actual emissions is creditable only to the extent 
that:
    (1) The old level of actual emission or the old level of allowable 
emissions whichever is lower, exceeds the new level of actual emissions;
    (2) It is enforceable as a practical matter at and after the time 
that actual construction on the particular change begins; and
    (3) The reviewing authority has not relied on it in issuing any 
permit under regulations approved pursuant to 40 CFR part 51 subpart I 
or the State has not relied on it in demonstrating attainment or 
reasonable further progress;
    (4) It has approximately the same qualitative significance for 
public health and welfare as that attributed to the increase from the 
particular change; and
    (5) The decrease in actual emissions did not result from the 
installation of add-on control technology or application of pollution 
prevention practices that were relied on in designating an emissions 
unit as a Clean Unit under 40 CFR 52.21(y) or under regulations approved 
pursuant to paragraph (d) of this section or Sec. 51.166(u). That is, 
once an emissions unit has been designated as a Clean Unit, the owner or 
operator cannot later use the emissions reduction from the air pollution 
control measures that the Clean Unit designation is based on in 
calculating the net emissions increase for another emissions unit (i.e., 
must not use that reduction in a ``netting analysis'' for another 
emissions unit). However, any new emissions reductions that were not 
relied upon in a PCP excluded pursuant to paragraph (e) of this section 
or for a Clean Unit designation are creditable to the extent they meet 
the requirements in paragraphs (e)(6)(iv) of this section for the PCP 
and paragraphs (c)(8) or (d)(10) of this section for a Clean Unit.
    (F) An increase that results from a physical change at a source 
occurs when the emissions unit on which construction occurred becomes 
operational and begins to emit a particular pollutant. Any replacement 
unit that requires shakedown becomes operational only after a reasonable 
shakedown period, not to exceed 180 days.
    (G) Paragraph (a)(1)(xii)(B) of this section shall not apply for 
determining creditable increases and decreases or after a change.
    (vii) Emissions unit means any part of a stationary source that 
emits or

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would have the potential to emit any regulated NSR pollutant and 
includes an electric steam generating unit as defined in paragraph 
(a)(1)(xx) of this section. For purposes of this section, there are two 
types of emissions units as described in paragraphs (a)(1)(vii)(A) and 
(B) of this section.
    (A) A new emissions unit is any emissions unit which is (or will be) 
newly constructed and which has existed for less than 2 years from the 
date such emissions unit first operated.
    (B) An existing emissions unit is any emissions unit that does not 
meet the requirements in paragraph (a)(1)(vii)(A) of this section. A 
replacement unit, as defined in paragraph (a)(1)(xxi) of this section, 
is an existing emissions unit.
    (viii) Secondary emissons means emissions which would occur as a 
result of the construction or operation of a major stationary source or 
major modification, but do not come from the major stationary source or 
major modification itself. For the purpose of this section, secondary 
emissions must be specific, well defined, quantifiable, and impact the 
same general area as the stationary source or modification which causes 
the secondary emissions. Secondary emissions include emissions from any 
offsite support facility which would not be constructed or increase its 
emissions except as a result of the construction of operation of the 
major stationary source of major modification. Secondary emissions do 
not include any emissions which come directly from a mobile source such 
as emissions from the tailpipe of a motor vehicle, from a train, or from 
a vessel.
    (ix) Fugitive emissions means those emissions which could not 
reasonably pass through a stack, chimney, vent or other functionally 
equivalent opening.
    (x)(A) Significant means, in reference to a net emissions increase 
or the potential of a source to emit any of the following pollutants, a 
rate of emissions that would equal or exceed any of the following rates:

                         Pollutant Emission Rate

Carbon monoxide: 100 tons per year (tpy)
Nitrogen oxides: 40 tpy
Sulfur dioxide: 40 tpy
Ozone: 40 tpy of volatile organic compounds or NOX
Lead: 0.6 tpy
PM-10: 15 tpy PM-10

    (B) Notwithstanding the significant emissions rate for ozone in 
paragraph (a)(1)(x)(A) of this section, significant means, in reference 
to an emissions increase or a net emissions increase, any increase in 
actual emissions of volatile organic compounds that would result from 
any physical change in, or change in the method of operation of, a major 
stationary source locating in a serious or severe ozone nonattainment 
area that is subject to subpart 2, part D, title I of the Act, if such 
emissions increase of volatile organic compounds exceeds 25 tons per 
year.
    (C) For the purposes of applying the requirements of paragraph 
(a)(8) of this section to modifications at major stationary sources of 
nitrogen oxides located in an ozone nonattainment area or in an ozone 
transport region, the significant emission rates and other requirements 
for volatile organic compounds in paragraphs (a)(1)(x)(A), (B), and (E) 
of this section shall apply to nitrogen oxides emissions.
    (D) Notwithstanding the significant emissions rate for carbon 
monoxide under paragraph (a)(1)(x)(A) of this section, significant 
means, in reference to an emissions increase or a net emissions 
increase, any increase in actual emissions of carbon monoxide that would 
result from any physical change in, or change in the method of operation 
of, a major stationary source in a serious nonattainment area for carbon 
monoxide if such increase equals or exceeds 50 tons per year, provided 
the Administrator has determined that stationary sources contribute 
significantly to carbon monoxide levels in that area.
    (E) Notwithstanding the significant emissions rates for ozone under 
paragraphs (a)(1)(x)(A) and (B) of this section, any increase in actual 
emissions of volatile organic compounds from any emissions unit at a 
major stationary source of volatile organic compounds located in an 
extreme ozone nonattainment area that is subject to subpart 2, part D, 
title I of the Act shall be considered a significant net emissions 
increase.

    (xi) Allowable emissions means the emissions rate of a stationary 
source

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calculated using the maximum rated capacity of the source (unless the 
source is subject to federally enforceable limits which restrict the 
operating rate, or hours of operation, or both) and the most stringent 
of the following:
    (A) The applicable standards set forth in 40 CFR part 60 or 61;
    (B) Any applicable State Implementation Plan emissions limitation 
including those with a future compliance date; or
    (C) The emissions rate specified as a federally enforceable permit 
condition, including those with a future compliance date.
    (xii)(A) Actual emissions means the actual rate of emissions of a 
regulated NSR pollutant from an emissions unit, as determined in 
accordance with paragraphs (a)(1)(xii)(B) through (D) of this section, 
except that this definition shall not apply for calculating whether a 
significant emissions increase has occurred, or for establishing a PAL 
under paragraph (f) of this section. Instead, paragraphs (a)(1)(xxviii) 
and (xxxv) of this section shall apply for those purposes.
    (B) In general, actual emissions as of a particular date shall equal 
the average rate, in tons per year, at which the unit actually emitted 
the pollutant during a consecutive 24-month period which precedes the 
particular date and which is representative of normal source operation. 
The reviewing authority shall allow the use of a different time period 
upon a determination that it is more representative of normal source 
operation. Actual emissions shall be calculated using the unit's actual 
operating hours, production rates, and types of materials processed, 
stored, or combusted during the selected time period.
    (C) The reviewing authority may presume that source-specific 
allowable emissions for the unit are equivalent to the actual emissions 
of the unit.
    (D) For any emissions unit that has not begun normal operations on 
the particular date, actual emissions shall equal the potential to emit 
of the unit on that date.
    (xiii) Lowest achievable emission rate (LAER) means, for any source, 
the more stringent rate of emissions based on the following:
    (A) The most stringent emissions limitation which is contained in 
the implementation plan of any State for such class or category of 
stationary source, unless the owner or operator of the proposed 
stationary source demonstrates that such limitations are not achievable; 
or
    (B) The most stringent emissions limitation which is achieved in 
practice by such class or category of stationary sources. This 
limitation, when applied to a modification, means the lowest achievable 
emissions rate for the new or modified emissions units within or 
stationary source. In no event shall the application of the term permit 
a proposed new or modified stationary source to emit any pollutant in 
excess of the amount allowable under an applicable new source standard 
of performance.
    (xiv) Federally enforceable means all limitations and conditions 
which are enforceable by the Administrator, including those requirements 
developed pursuant to 40 CFR parts 60 and 61, requirements within any 
applicable State implementation plan, any permit requirements 
established pursuant to 40 CFR 52.21 or under regulations approved 
pursuant to 40 CFR part 51, subpart I, including operating permits 
issued under an EPA-approved program that is incorporated into the State 
implementation plan and expressly requires adherence to any permit 
issued under such program.
    (xv) Begin actual construction means in general, initiation of 
physical on-site construction activities on an emissions unit which are 
of a permanent nature. Such activities include, but are not limited to, 
installation of building supports and foundations, laying of underground 
pipework, and construction of permanent storage structures. With respect 
to a change in method of operating this term refers to those on-site 
activities other than preparatory activities which mark the initiation 
of the change.
    (xvi) Commence as applied to construction of a major stationary 
source or major modification means that the owner or operator has all 
necessary

[[Page 195]]

preconstruction approvals or permits and either has:
    (A) Begun, or caused to begin, a continuous program of actual on-
site construction of the source, to be completed within a reasonable 
time; or
    (B) Entered into binding agreements or contractual obligations, 
which cannot be canceled or modified without substantial loss to the 
owner or operator, to undertake a program of actual construction of the 
source to be completed within a reasonable time.
    (xvii) Necessary preconstruction approvals or permits means those 
Federal air quality control laws and regulations and those air quality 
control laws and regulations which are part of the applicable State 
Implementation Plan.
    (xviii) Construction means any physical change or change in the 
method of operation (including fabrication, erection, installation, 
demolition, or modification of an emissions unit) that would result in a 
change in emissions.
    (xix)Volatile organic compounds (VOC) is as defined in Sec. 
51.100(s) of this part.
    (xx) Electric utility steam generating unit means any steam electric 
generating unit that is constructed for the purpose of supplying more 
than one-third of its potential electric output capacity and more than 
25 MW electrical output to any utility power distribution system for 
sale. Any steam supplied to a steam distribution system for the purpose 
of providing steam to a steam-electric generator that would produce 
electrical energy for sale is also considered in determining the 
electrical energy output capacity of the affected facility.
    (xxi) Replacement unit means an emissions unit for which all the 
criteria listed in paragraphs (a)(1)(xxi)(A) through (D) of this section 
are met. No creditable emission reductions shall be generated from 
shutting down the existing emissions unit that is replaced.
    (A) The emissions unit is a reconstructed unit within the meaning of 
Sec. 60.15(b)(1) of this chapter, or the emissions unit completely 
takes the place of an existing emissions unit.
    (B) The emissions unit is identical to or functionally equivalent to 
the replaced emissions unit.
    (C) The replacement does not alter the basic design parameters (as 
discussed in paragraph (h)(2) of this section) of the process unit.
    (D) The replaced emissions unit is permanently removed from the 
major stationary source, otherwise permanently disabled, or permanently 
barred from operation by a permit that is enforceable as a practical 
matter. If the replaced emissions unit is brought back into operation, 
it shall constitute a new emissions unit.
    (xxii) Temporary clean coal technology demonstration project means a 
clean coal technology demonstration project that is operated for a 
period of 5 years or less, and which complies with the State 
Implementation Plan for the State in which the project is located and 
other requirements necessary to attain and maintain the national ambient 
air quality standards during the project and after it is terminated.
    (xxiii) Clean coal technology means any technology, including 
technologies applied at the precombustion, combustion, or post 
combustion stage, at a new or existing facility which will achieve 
significant reductions in air emissions of sulfur dioxide or oxides of 
nitrogen associated with the utilization of coal in the generation of 
electricity, or process steam which was not in widespread use as of 
November 15, 1990.
    (xxiv) Clean coal technology demonstration project means a project 
using funds appropriated under the heading ``Department of Energy-Clean 
Coal Technology,'' up to a total amount of $2,500,000,000 for commercial 
demonstration of clean coal technology, or similar projects funded 
through appropriations for the Environmental Protection Agency. The 
Federal contribution for a qualifying project shall be at least 20 
percent of the total cost of the demonstration project.
    (xxv) Pollution control project (PCP) means any activity, set of 
work practices or project (including pollution prevention as defined 
under paragraph (a)(1)(xxvi) of this section) undertaken at an existing 
emissions unit that reduces emissions of air pollutants from such unit. 
Such qualifying activities or projects can include the replacement or 
upgrade of an existing emissions control technology with a more 
effective unit. Other changes that may

[[Page 196]]

occur at the source are not considered part of the PCP if they are not 
necessary to reduce emissions through the PCP. Projects listed in 
paragraphs (a)(1)(xxv)(A) through (F) of this section are presumed to be 
environmentally beneficial pursuant to paragraph (e)(2)(i) of this 
section. Projects not listed in these paragraphs may qualify for a case-
specific PCP exclusion pursuant to the requirements of paragraphs (e)(2) 
and (e)(5) of this section.
    (A) Conventional or advanced flue gas desulfurization or sorbent 
injection for control of SO2.
    (B) Electrostatic precipitators, baghouses, high efficiency 
multiclones, or scrubbers for control of particulate matter or other 
pollutants.
    (C) Flue gas recirculation, low-NOX burners or 
combustors, selective non-catalytic reduction, selective catalytic 
reduction, low emission combustion (for IC engines), and oxidation/
absorption catalyst for control of NOX.
    (D) Regenerative thermal oxidizers, catalytic oxidizers, condensers, 
thermal incinerators, hydrocarbon combustion flares, biofiltration, 
absorbers and adsorbers, and floating roofs for storage vessels for 
control of volatile organic compounds or hazardous air pollutants. For 
the purpose of this section, ``hydrocarbon combustion flare'' means 
either a flare used to comply with an applicable NSPS or MACT standard 
(including uses of flares during startup, shutdown, or malfunction 
permitted under such a standard), or a flare that serves to control 
emissions of waste streams comprised predominately of hydrocarbons and 
containing no more than 230 mg/dscm hydrogen sulfide.
    (E) Activities or projects undertaken to accommodate switching (or 
partially switching) to an inherently less polluting fuel, to be limited 
to the following fuel switches:
    (1) Switching from a heavier grade of fuel oil to a lighter fuel 
oil, or any grade of oil to 0.05 percent sulfur diesel (i.e., from a 
higher sulfur content 2 fuel or from 6 fuel, to CA 
0.05 percent sulfur 2 diesel);
    (2) Switching from coal, oil, or any solid fuel to natural gas, 
propane, or gasified coal;
    (3) Switching from coal to wood, excluding construction or 
demolition waste, chemical or pesticide treated wood, and other forms of 
``unclean'' wood;
    (4) Switching from coal to 2 fuel oil (0.5 percent maximum 
sulfur content); and
    (5) Switching from high sulfur coal to low sulfur coal (maximum 1.2 
percent sulfur content).
    (F) Activities or projects undertaken to accommodate switching from 
the use of one ozone depleting substance (ODS) to the use of a substance 
with a lower or zero ozone depletion potential (ODP), including changes 
to equipment needed to accommodate the activity or project, that meet 
the requirements of paragraphs (a)(1)(xxv)(F)(1) and (2) of this 
section.
    (1) The productive capacity of the equipment is not increased as a 
result of the activity or project.
    (2) The projected usage of the new substance is lower, on an ODP-
weighted basis, than the baseline usage of the replaced ODS. To make 
this determination, follow the procedure in paragraphs 
(a)(1)(xxv)(F)(2)(i) through (iv) of this section.
    (i) Determine the ODP of the substances by consulting 40 CFR part 
82, subpart A, appendices A and B.
    (ii) Calculate the replaced ODP-weighted amount by multiplying the 
baseline actual usage (using the annualized average of any 24 
consecutive months of usage within the past 10 years) by the ODP of the 
replaced ODS.
    (iii) Calculate the projected ODP-weighted amount by multiplying the 
projected future annual usage of the new substance by its ODP.
    (iv) If the value calculated in paragraph (a)(1)(xxv)(F)(2)(ii) of 
this section is more than the value calculated in paragraph 
(a)(1)(xxv)(F)(2)(iii) of this section, then the projected use of the 
new substance is lower, on an ODP-weighted basis, than the baseline 
usage of the replaced ODS.
    (xxvi) Pollution prevention means any activity that through process 
changes, product reformulation or redesign, or substitution of less 
polluting raw materials, eliminates or reduces the release of air 
pollutants (including fugitive emissions) and other pollutants to

[[Page 197]]

the environment prior to recycling, treatment, or disposal; it does not 
mean recycling (other than certain ``in-process recycling'' practices), 
energy recovery, treatment, or disposal.
    (xxvii) Significant emissions increase means, for a regulated NSR 
pollutant, an increase in emissions that is significant (as defined in 
paragraph (a)(1)(x) of this section) for that pollutant.
    (xxviii)(A) Projected actual emissions means, the maximum annual 
rate, in tons per year, at which an existing emissions unit is projected 
to emit a regulated NSR pollutant in any one of the 5 years (12-month 
period) following the date the unit resumes regular operation after the 
project, or in any one of the 10 years following that date, if the 
project involves increasing the emissions unit's design capacity or its 
potential to emit of that regulated NSR pollutant and full utilization 
of the unit would result in a significant emissions increase or a 
significant net emissions increase at the major stationary source.
    (B) In determining the projected actual emissions under paragraph 
(a)(1)(xxviii)(A) of this section before beginning actual construction, 
the owner or operator of the major stationary source:
    (1) Shall consider all relevant information, including but not 
limited to, historical operational data, the company's own 
representations, the company's expected business activity and the 
company's highest projections of business activity, the company's 
filings with the State or Federal regulatory authorities, and compliance 
plans under the approved plan; and
    (2) Shall include fugitive emissions to the extent quantifiable, and 
emissions associated with startups, shutdowns, and malfunctions; and
    (3) Shall exclude, in calculating any increase in emissions that 
results from the particular project, that portion of the unit's 
emissions following the project that an existing unit could have 
accommodated during the consecutive 24-month period used to establish 
the baseline actual emissions under paragraph (a)(1)(xxxv) of this 
section and that are also unrelated to the particular project, including 
any increased utilization due to product demand growth; or,
    (4) In lieu of using the method set out in paragraphs 
(a)(1)(xxviii)(B)(1) through (3) of this section, may elect to use the 
emissions unit's potential to emit, in tons per year, as defined under 
paragraph (a)(1)(iii) of this section.
    (xxix) Clean Unit means any emissions unit that has been issued a 
major NSR permit that requires compliance with BACT or LAER, that is 
complying with such BACT/LAER requirements, and qualifies as a Clean 
Unit pursuant to regulations approved by the Administrator in accordance 
with paragraph (c) of this section; or any emissions unit that has been 
designated by a reviewing authority as a Clean Unit, based on the 
criteria in paragraphs (d)(3)(i) through (iv) of this section, using a 
plan-approved permitting process; or any emissions unit that has been 
designated as a Clean Unit by the Administrator in accordance with Sec. 
52.21(y)(3)(i) through (iv) of this chapter.
    (xxx) Nonattainment major new source review (NSR) program means a 
major source preconstruction permit program that has been approved by 
the Administrator and incorporated into the plan to implement the 
requirements of this section, or a program that implements part 51, 
appendix S, Sections I through VI of this chapter. Any permit issued 
under such a program is a major NSR permit.
    (xxxi) Continuous emissions monitoring system (CEMS) means all of 
the equipment that may be required to meet the data acquisition and 
availability requirements of this section, to sample, condition (if 
applicable), analyze, and provide a record of emissions on a continuous 
basis.
    (xxxii) Predictive emissions monitoring system (PEMS) means all of 
the equipment necessary to monitor process and control device 
operational parameters (for example, control device secondary voltages 
and electric currents) and other information (for example, gas flow 
rate, O2 or CO2 concentrations), and calculate and 
record the mass emissions rate (for example, lb/hr) on a continuous 
basis.
    (xxxiii) Continuous parameter monitoring system (CPMS) means all of 
the

[[Page 198]]

equipment necessary to meet the data acquisition and availability 
requirements of this section, to monitor process and control device 
operational parameters (for example, control device secondary voltages 
and electric currents) and other information (for example, gas flow 
rate, O2 or CO2 concentrations), and to record 
average operational parameter value(s) on a continuous basis.
    (xxxiv) Continuous emissions rate monitoring system (CERMS) means 
the total equipment required for the determination and recording of the 
pollutant mass emissions rate (in terms of mass per unit of time).
    (xxxv) Baseline actual emissions means the rate of emissions, in 
tons per year, of a regulated NSR pollutant, as determined in accordance 
with paragraphs (a)(1)(xxxv)(A) through (D) of this section.
    (A) For any existing electric utility steam generating unit, 
baseline actual emissions means the average rate, in tons per year, at 
which the unit actually emitted the pollutant during any consecutive 24-
month period selected by the owner or operator within the 5-year period 
immediately preceding when the owner or operator begins actual 
construction of the project. The reviewing authority shall allow the use 
of a different time period upon a determination that it is more 
representative of normal source operation.
    (1) The average rate shall include fugitive emissions to the extent 
quantifiable, and emissions associated with startups, shutdowns, and 
malfunctions.
    (2) The average rate shall be adjusted downward to exclude any non-
compliant emissions that occurred while the source was operating above 
any emission limitation that was legally enforceable during the 
consecutive 24-month period.
    (3) For a regulated NSR pollutant, when a project involves multiple 
emissions units, only one consecutive 24-month period must be used to 
determine the baseline actual emissions for the emissions units being 
changed. A different consecutive 24-month period can be used for each 
regulated NSR pollutant.
    (4) The average rate shall not be based on any consecutive 24-month 
period for which there is inadequate information for determining annual 
emissions, in tons per year, and for adjusting this amount if required 
by paragraph (a)(1)(xxxv)(A)(2) of this section.
    (B) For an existing emissions unit (other than an electric utility 
steam generating unit), baseline actual emissions means the average 
rate, in tons per year, at which the emissions unit actually emitted the 
pollutant during any consecutive 24-month period selected by the owner 
or operator within the 10-year period immediately preceding either the 
date the owner or operator begins actual construction of the project, or 
the date a complete permit application is received by the reviewing 
authority for a permit required either under this section or under a 
plan approved by the Administrator, whichever is earlier, except that 
the 10-year period shall not include any period earlier than November 
15, 1990.
    (1) The average rate shall include fugitive emissions to the extent 
quantifiable, and emissions associated with startups, shutdowns, and 
malfunctions.
    (2) The average rate shall be adjusted downward to exclude any non-
compliant emissions that occurred while the source was operating above 
an emission limitation that was legally enforceable during the 
consecutive 24-month period.
    (3) The average rate shall be adjusted downward to exclude any 
emissions that would have exceeded an emission limitation with which the 
major stationary source must currently comply, had such major stationary 
source been required to comply with such limitations during the 
consecutive 24-month period. However, if an emission limitation is part 
of a maximum achievable control technology standard that the 
Administrator proposed or promulgated under part 63 of this chapter, the 
baseline actual emissions need only be adjusted if the State has taken 
credit for such emissions reductions in an attainment demonstration or 
maintenance plan consistent with the requirements of paragraph 
(a)(3)(ii)(G) of this section.
    (4) For a regulated NSR pollutant, when a project involves multiple 
emissions units, only one consecutive 24-

[[Page 199]]

month period must be used to determine the baseline actual emissions for 
the emissions units being changed. A different consecutive 24-month 
period can be used For each regulated NSR pollutant.
    (5) The average rate shall not be based on any consecutive 24-month 
period for which there is inadequate information for determining annual 
emissions, in tons per year, and for adjusting this amount if required 
by paragraphs (a)(1)(xxxv)(B)(2) and (3) of this section.
    (C) For a new emissions unit, the baseline actual emissions for 
purposes of determining the emissions increase that will result from the 
initial construction and operation of such unit shall equal zero; and 
thereafter, for all other purposes, shall equal the unit's potential to 
emit.
    (D) For a PAL for a major stationary source, the baseline actual 
emissions shall be calculated for existing electric utility steam 
generating units in accordance with the procedures contained in 
paragraph (a)(1)(xxxv)(A) of this section, for other existing emissions 
units in accordance with the procedures contained in paragraph 
(a)(1)(xxxv)(B) of this section, and for a new emissions unit in 
accordance with the procedures contained in paragraph (a)(1)(xxxv)(C) of 
this section.
    (xxxvi) [Reserved]
    (xxxvii) Regulated NSR pollutant, for purposes of this section, 
means the following:
    (A) Nitrogen oxides or any volatile organic compounds;
    (B) Any pollutant for which a national ambient air quality standard 
has been promulgated; or
    (C) Any pollutant that is a constituent or precursor of a general 
pollutant listed under paragraphs (a)(1)(xxxvii)(A) or (B) of this 
section, provided that a constituent or precursor pollutant may only be 
regulated under NSR as part of regulation of the general pollutant.
    (xxxviii) Reviewing authority means the State air pollution control 
agency, local agency, other State agency, Indian tribe, or other agency 
authorized by the Administrator to carry out a permit program under this 
section and Sec. 51.166, or the Administrator in the case of EPA-
implemented permit programs under Sec. 52.21.
    (xxxix) Project means a physical change in, or change in the method 
of operation of, an existing major stationary source.
    (xl) Best available control technology (BACT) means an emissions 
limitation (including a visible emissions standard) based on the maximum 
degree of reduction for each regulated NSR pollutant which would be 
emitted from any proposed major stationary source or major modification 
which the reviewing authority, on a case-by-case basis, taking into 
account energy, environmental, and economic impacts and other costs, 
determines is achievable for such source or modification through 
application of production processes or available methods, systems, and 
techniques, including fuel cleaning or treatment or innovative fuel 
combustion techniques for control of such pollutant. In no event shall 
application of best available control technology result in emissions of 
any pollutant which would exceed the emissions allowed by any applicable 
standard under 40 CFR part 60 or 61. If the reviewing authority 
determines that technological or economic limitations on the application 
of measurement methodology to a particular emissions unit would make the 
imposition of an emissions standard infeasible, a design, equipment, 
work practice, operational standard, or combination thereof, may be 
prescribed instead to satisfy the requirement for the application of 
BACT. Such standard shall, to the degree possible, set forth the 
emissions reduction achievable by implementation of such design, 
equipment, work practice or operation, and shall provide for compliance 
by means which achieve equivalent results.
    (xli) Prevention of Significant Deterioration (PSD) permit means any 
permit that is issued under a major source preconstruction permit 
program that has been approved by the Administrator and incorporated 
into the plan to implement the requirements of Sec. 51.166 of this 
chapter, or under the program in Sec. 52.21 of this chapter.
    (xlii) Federal Land Manager means, with respect to any lands in the 
United States, the Secretary of the department with authority over such 
lands.

[[Page 200]]

    (xliii)(A) In general, process unit means any collection of 
structures and/or equipment that processes, assembles, applies, blends, 
or otherwise uses material inputs to produce or store an intermediate or 
a completed product. A single stationary source may contain more than 
one process unit, and a process unit may contain more than one emissions 
unit.
    (B) Pollution control equipment is not part of the process unit, 
unless it serves a dual function as both process and control equipment. 
Administrative and warehousing facilities are not part of the process 
unit.
    (C) For replacement cost purposes, components shared between two or 
more process units are proportionately allocated based on capacity.
    (D) The following list identifies the process units at specific 
categories of stationary sources.
    (1) For a steam electric generating facility, the process unit 
consists of those portions of the plant that contribute directly to the 
production of electricity. For example, at a pulverized coal-fired 
facility, the process unit would generally be the combination of those 
systems from the coal receiving equipment through the emission stack 
(excluding post-combustion pollution controls), including the coal 
handling equipment, pulverizers or coal crushers, feedwater heaters, ash 
handling, boiler, burners, turbine-generator set, condenser, cooling 
tower, water treatment system, air preheaters, and operating control 
systems. Each separate generating unit is a separate process unit.
    (2) For a petroleum refinery, there are several categories of 
process units: those that separate and/or distill petroleum feedstocks; 
those that change molecular structures; petroleum treating processes; 
auxiliary facilities, such as steam generators and hydrogen production 
units; and those that load, unload, blend or store intermediate or 
completed products.
    (3) For an incinerator, the process unit would consist of components 
from the feed pit or refuse pit to the stack, including conveyors, 
combustion devices, heat exchangers and steam generators, quench tanks, 
and fans.
    Note to paragraph (a)(1)(xliii): By a court order on December 24, 
2003, this paragraph (a)(1)(xliii) is stayed indefinitely. The stayed 
provisions will become effective immediately if the court terminates the 
stay. At that time, EPA will publish a document in the Federal Register 
advising the public of the termination of the stay.
    (xliv) Functionally equivalent component means a component that 
serves the same purpose as the replaced component.
    Note to paragraph (a)(1)(xliv): By a court order on December 24, 
2003, this paragraph (a)(1)(xliv) is stayed indefinitely. The stayed 
provisions will become effective immediately if the court terminates the 
stay. At that time, EPA will publish a document in the Federal Register 
advising the public of the termination of the stay.
    (xlv) Fixed capital cost means the capital needed to provide all the 
depreciable components. ``Depreciable components'' refers to all 
components of fixed capital cost and is calculated by subtracting land 
and working capital from the total capital investment, as defined in 
paragraph (a)(1)(xlvi) of this section.
    Note to paragraph (a)(1)(xlv): By a court order on December 24, 
2003, this paragraph (a)(1)(xlv) is stayed indefinitely. The stayed 
provisions will become effective immediately if the court terminates the 
stay. At that time, EPA will publish a document in the Federal Register 
advising the public of the termination of the stay.
    (xlvi) Total capital investment means the sum of the following: All 
costs required to purchase needed process equipment (purchased equipment 
costs); the costs of labor and materials for installing that equipment 
(direct installation costs); the costs of site preparation and 
buildings; other costs such as engineering, construction and field 
expenses, fees to contractors, startup and performance tests, and 
contingencies (indirect installation costs); land for the process 
equipment; and working capital for the process equipment.
    Note to paragraph (a)(1)(xlvi): By a court order on December 24, 
2003, this paragraph (a)(1)(xlvi) is stayed indefinitely. The stayed 
provisions will become effective immediately if the court terminates the 
stay. At that time, EPA will publish a document in the Federal Register 
advising the public of the termination of the stay.

[[Page 201]]

    (2) Applicability procedures. (i) Each plan shall adopt a 
preconstruction review program to satisfy the requirements of sections 
172(c)(5) and 173 of the Act for any area designated nonattainment for 
any national ambient air quality standard under subpart C of 40 CFR part 
81. Such a program shall apply to any new major stationary source or 
major modification that is major for the pollutant for which the area is 
designated nonattainment under section 107(d)(1)(A)(i) of the Act, if 
the stationary source or modification would locate anywhere in the 
designated nonattainment area.
    (ii) Each plan shall use the specific provisions of paragraphs 
(a)(2)(ii)(A) through (F) of this section. Deviations from these 
provisions will be approved only if the State specifically demonstrates 
that the submitted provisions are more stringent than or at least as 
stringent in all respects as the corresponding provisions in paragraphs 
(a)(2)(ii)(A) through (F) of this section.
    (A) Except as otherwise provided in paragraphs (a)(2)(iii) and (iv) 
of this section, and consistent with the definition of major 
modification contained in paragraph (a)(1)(v)(A) of this section, a 
project is a major modification for a regulated NSR pollutant if it 
causes two types of emissions increases--a significant emissions 
increase (as defined in paragraph (a)(1)(xxvii) of this section), and a 
significant net emissions increase (as defined in paragraphs (a)(1)(vi) 
and (x) of this section). The project is not a major modification if it 
does not cause a significant emissions increase. If the project causes a 
significant emissions increase, then the project is a major modification 
only if it also results in a significant net emissions increase.
    (B) The procedure for calculating (before beginning actual 
construction) whether a significant emissions increase (i.e., the first 
step of the process) will occur depends upon the type of emissions units 
being modified, according to paragraphs (a)(2)(ii)(C) through (F) of 
this section. The procedure for calculating (before beginning actual 
construction) whether a significant net emissions increase will occur at 
the major stationary source (i.e., the second step of the process) is 
contained in the definition in paragraph (a)(1)(vi) of this section. 
Regardless of any such preconstruction projections, a major modification 
results if the project causes a significant emissions increase and a 
significant net emissions increase.
    (C) Actual-to-projected-actual applicability test for projects that 
only involve existing emissions units. A significant emissions increase 
of a regulated NSR pollutant is projected to occur if the sum of the 
difference between the projected actual emissions (as defined in 
paragraph (a)(1)(xxviii) of this section) and the baseline actual 
emissions (as defined in paragraphs (a)(1)(xxxv)(A) and (B) of this 
section, as applicable), for each existing emissions unit, equals or 
exceeds the significant amount for that pollutant (as defined in 
paragraph (a)(1)(x) of this section).
    (D) Actual-to-potential test for projects that only involve 
construction of a new emissions unit(s). A significant emissions 
increase of a regulated NSR pollutant is projected to occur if the sum 
of the difference between the potential to emit (as defined in paragraph 
(a)(1)(iii) of this section) from each new emissions unit following 
completion of the project and the baseline actual emissions (as defined 
in paragraph (a)(1)(xxxv)(C) of this section) of these units before the 
project equals or exceeds the significant amount for that pollutant (as 
defined in paragraph (a)(1)(x) of this section).
    (E) Emission test for projects that involve Clean Units. For a 
project that will be constructed and operated at a Clean Unit without 
causing the emissions unit to lose its Clean Unit designation, no 
emissions increase is deemed to occur.
    (F) Hybrid test for projects that involve multiple types of 
emissions units. A significant emissions increase of a regulated NSR 
pollutant is projected to occur if the sum of the emissions increases 
for each emissions unit, using the method specified in paragraphs 
(a)(2)(ii)(C) through (E) of this section as applicable with respect to 
each

[[Page 202]]

emissions unit, for each type of emissions unit equals or exceeds the 
significant amount for that pollutant (as defined in paragraph (a)(1)(x) 
of this section). For example, if a project involves both an existing 
emissions unit and a Clean Unit, the projected increase is determined by 
summing the values determined using the method specified in paragraph 
(a)(2)(ii)(C) of this section for the existing unit and using the method 
specified in paragraph (a)(2)(ii)(E) of this section for the Clean Unit.
    (iii) The plan shall require that for any major stationary source 
for a PAL for a regulated NSR pollutant, the major stationary source 
shall comply with requirements under paragraph (f) of this section.
    (iv) The plan shall require that an owner or operator undertaking a 
PCP (as defined in paragraph (a)(1)(xxv) of this section) shall comply 
with the requirements under paragraph (e) of this section.
    (3)(i) Each plan shall provide that for sources and modifications 
subject to any preconstruction review program adopted pursuant to this 
subsection the baseline for determining credit for emissions reductions 
is the emissions limit under the applicable State Implementation Plan in 
effect at the time the application to construct is filed, except that 
the offset baseline shall be the actual emissions of the source from 
which offset credit is obtained where;
    (A) The demonstration of reasonable further progress and attainment 
of ambient air quality standards is based upon the actual emissions of 
sources located within a designated nonattainment area for which the 
preconstruction review program was adopted; or
    (B) The applicable State Implementation Plan does not contain an 
emissions limitation for that source or source category.
    (ii) The plan shall further provide that:
    (A) Where the emissions limit under the applicable State 
Implementation Plan allows greater emissions than the potential to emit 
of the source, emissions offset credit will be allowed only for control 
below this potential;
    (B) For an existing fuel combustion source, credit shall be based on 
the allowable emissions under the applicable State Implementation Plan 
for the type of fuel being burned at the time the application to 
construct is filed. If the existing source commits to switch to a 
cleaner fuel at some future date, emissions offset credit based on the 
allowable (or actual) emissions for the fuels involved is not 
acceptable, unless the permit is conditioned to require the use of a 
specified alternative control measure which would achieve the same 
degree of emissions reduction should the source switch back to a dirtier 
fuel at some later date. The reviewing authority should ensure that 
adequate long-term supplies of the new fuel are available before 
granting emissions offset credit for fuel switches,
    (C)(1) Emissions reductions achieved by shutting down an existing 
emission unit or curtailing production or operating hours may be 
generally credited for offsets if they meet the requirements in 
paragraphs (a)(3)(ii)(C)(1)(i) through (ii) of this section.
    (i) Such reductions are surplus, permanent, quantifiable, and 
federally enforceable.
    (ii) The shutdown or curtailment occurred after the last day of the 
base year for the SIP planning process. For purposes of this paragraph, 
a reviewing authority may choose to consider a prior shutdown or 
curtailment to have occurred after the last day of the base year if the 
projected emissions inventory used to develop the attainment 
demonstration explicitly includes the emissions from such previously 
shutdown or curtailed emission units. However, in no event may credit be 
given for shutdowns that occurred before August 7, 1977.
    (2) Emissions reductions achieved by shutting down an existing 
emissions unit or curtailing production or operating hours and that do 
not meet the requirements in paragraph (a)(3)(ii)(C)(1)(ii) of this 
section may be generally credited only if:
    (i) The shutdown or curtailment occurred on or after the date the 
construction permit application is filed; or
    (ii) The applicant can establish that the proposed new emissions 
unit is a

[[Page 203]]

replacement for the shutdown or curtailed emissions unit, and the 
emissions reductions achieved by the shutdown or curtailment met the 
requirements of paragraph (a)(3)(ii)(C)(1)(i) of this section.
    (D) No emissions credit may be allowed for replacing one hydrocarbon 
compound with another of lesser reactivity, except for those compounds 
listed in Table 1 of EPA's ``Recommended Policy on Control of Volatile 
Organic Compounds'' (42 FR 35314, July 8, 1977; (This document is also 
available from Mr. Ted Creekmore, Office of Air Quality Planning and 
Standards, (MD-15) Research Triangle Park, NC 27711.))
    (E) All emission reductions claimed as offset credit shall be 
federally enforceable;
    (F) Procedures relating to the permissible location of offsetting 
emissions shall be followed which are at least as stringent as those set 
out in 40 CFR part 51 appendix S section IV.D.
    (G) Credit for an emissions reduction can be claimed to the extent 
that the reviewing authority has not relied on it in issuing any permit 
under regulations approved pursuant to 40 CFR part 51 subpart I or the 
State has not relied on it in demonstration attainment or reasonable 
further progress.
    (H) Decreases in actual emissions resulting from the installation of 
add-on control technology or application of pollution prevention 
measures that were relied upon in designating an emissions unit as a 
Clean Unit or a project as a PCP cannot be used as offsets.
    (I) Decreases in actual emissions occurring at a Clean Unit cannot 
be used as offsets, except as provided in paragraphs (c)(8) and (d)(10) 
of this section. Similarly, decreases in actual emissions occurring at a 
PCP cannot be used as offsets, except as provided in paragraph 
(e)(6)(iv) of this section.
    (J) The total tonnage of increased emissions, in tons per year, 
resulting from a major modification that must be offset in accordance 
with section 173 of the Act shall be determined by summing the 
difference between the allowable emissions after the modification (as 
defined by paragraph (a)(1)(xi) of this section) and the actual 
emissions before the modification (as defined in paragraph (a)(1)(xii) 
of this section) for each emissions unit.
    (4) Each plan may provide that the provisions of this paragraph do 
not apply to a source or modification that would be a major stationary 
source or major modification only if fugitive emission to the extent 
quantifiable are considered in calculating the potential to emit of the 
stationary source or modification and the source does not belong to any 
of the following categories:
    (i) Coal cleaning plants (with thermal dryers);
    (ii) Kraft pulp mills;
    (iii) Portland cement plants;
    (iv) Primary zinc smelters;
    (v) Iron and steel mills;
    (vi) Primary aluminum ore reduction plants;
    (vii) Primary copper smelters;
    (viii) Municipal incinerators capable of charging more than 250 tons 
of refuse per day;
    (ix) Hydrofluoric, sulfuric, or citric acid plants;
    (x) Petroleum refineries;
    (xi) Lime plants;
    (xii) Phosphate rock processing plants;
    (xiii) Coke oven batteries;
    (xiv) Sulfur recovery plants;
    (xv) Carbon black plants (furnace process);
    (xvi) Primary lead smelters;
    (xvii) Fuel conversion plants;
    (xviii) Sintering plants;
    (xix) Secondary metal production plants;
    (xx) Chemical process plants;
    (xxi) Fossil-fuel boilers (or combination thereof) totaling more 
than 250 million British thermal units per hour heat input;
    (xxii) Petroleum storage and transfer units with a total storage 
capacity exceeding 300,000 barrels;
    (xxiii) Taconite ore processing plants;
    (xxiv) Glass fiber processing plants;
    (xxv) Charcoal production plants;
    (xxvi) Fossil fuel-fired steam electric plants of more than 250 
million British thermal units per hour heat input;
    (xxvii) Any other stationary source category which, as of August 7, 
1980, is being regulated under section 111 or 112 of the Act.

[[Page 204]]

    (5) Each plan shall include enforceable procedures to provide that:
    (i) Approval to construct shall not relieve any owner or operator of 
the responsibility to comply fully with applicable provision of the plan 
and any other requirements under local, State or Federal law.
    (ii) At such time that a particular source or modification becomes a 
major stationary source or major modification solely by virtue of a 
relaxation in any enforcement limitation which was established after 
August 7, 1980, on the capacity of the source or modification otherwise 
to emit a pollutant, such as a restriction on hours of operation, then 
the requirements of regulations approved pursuant to this section shall 
apply to the source or modification as though construction had not yet 
commenced on the source or modification;
    (6) Each plan shall provide that the following specific provisions 
apply to projects at existing emissions units at a major stationary 
source (other than projects at a Clean Unit or at a source with a PAL) 
in circumstances where there is a reasonable possibility that a project 
that is not a part of a major modification may result in a significant 
emissions increase and the owner or operator elects to use the method 
specified in paragraphs (a)(1)(xxviii)(B)(1) through (3) of this section 
for calculating projected actual emissions. Deviations from these 
provisions will be approved only if the State specifically demonstrates 
that the submitted provisions are more stringent than or at least as 
stringent in all respects as the corresponding provisions in paragraphs 
(a)(6)(i) through (v) of this section.
    (i) Before beginning actual construction of the project, the owner 
or operator shall document and maintain a record of the following 
information:
    (A) A description of the project;
    (B) Identification of the emissions unit(s) whose emissions of a 
regulated NSR pollutant could be affected by the project; and
    (C) A description of the applicability test used to determine that 
the project is not a major modification for any regulated NSR pollutant, 
including the baseline actual emissions, the projected actual emissions, 
the amount of emissions excluded under paragraph (a)(1)(xxviii)(B)(3) of 
this section and an explanation for why such amount was excluded, and 
any netting calculations, if applicable.
    (ii) If the emissions unit is an existing electric utility steam 
generating unit, before beginning actual construction, the owner or 
operator shall provide a copy of the information set out in paragraph 
(a)(6)(i) of this section to the reviewing authority. Nothing in this 
paragraph (a)(6)(ii) shall be construed to require the owner or operator 
of such a unit to obtain any determination from the reviewing authority 
before beginning actual construction.
    (iii) The owner or operator shall monitor the emissions of any 
regulated NSR pollutant that could increase as a result of the project 
and that is emitted by any emissions units identified in paragraph 
(a)(6)(i)(B) of this section; and calculate and maintain a record of the 
annual emissions, in tons per year on a calendar year basis, for a 
period of 5 years following resumption of regular operations after the 
change, or for a period of 10 years following resumption of regular 
operations after the change if the project increases the design capacity 
or potential to emit of that regulated NSR pollutant at such emissions 
unit.
    (iv) If the unit is an existing electric utility steam generating 
unit, the owner or operator shall submit a report to the reviewing 
authority within 60 days after the end of each year during which records 
must be generated under paragraph (a)(6)(iii) of this section setting 
out the unit's annual emissions during the year that preceded submission 
of the report.
    (v) If the unit is an existing unit other than an electric utility 
steam generating unit, the owner or operator shall submit a report to 
the reviewing authority if the annual emissions, in tons per year, from 
the project identified in paragraph (a)(6)(i) of this section, exceed 
the baseline actual emissions (as documented and maintained pursuant to 
paragraph (a)(6)(i)(C) of this section, by a significant amount (as 
defined in paragraph (a)(1)(x) of this section) for that regulated NSR 
pollutant, and if such emissions differ from

[[Page 205]]

the preconstruction projection as documented and maintained pursuant to 
paragraph (a)(6)(i)(C) of this section. Such report shall be submitted 
to the reviewing authority within 60 days after the end of such year. 
The report shall contain the following:
    (A) The name, address and telephone number of the major stationary 
source;
    (B) The annual emissions as calculated pursuant to paragraph 
(a)(6)(iii) of this section; and
    (C) Any other information that the owner or operator wishes to 
include in the report (e.g., an explanation as to why the emissions 
differ from the preconstruction projection).
    (7) Each plan shall provide that the owner or operator of the source 
shall make the information required to be documented and maintained 
pursuant to paragraph (a)(6) of this section available for review upon a 
request for inspection by the reviewing authority or the general public 
pursuant to the requirements contained in Sec. 70.4(b)(3)(viii) of this 
chapter.
    (8) The plan shall provide that the requirements of this section 
applicable to major stationary sources and major modifications of 
volatile organic compounds shall apply to nitrogen oxides emissions from 
major stationary sources and major modifications of nitrogen oxides in 
an ozone transport region or in any ozone nonattainment area, except in 
ozone nonattainment areas or in portions of an ozone transport region 
where the Administrator has granted a NOX waiver applying the 
standards set forth under section 182(f) of the Act and the waiver 
continues to apply.
    (9)(i) The plan shall require that in meeting the emissions offset 
requirements of paragraph (a)(3) of this section for ozone nonattainment 
areas that are subject to subpart 2, part D, title I of the Act, the 
ratio of total actual emissions reductions of VOC to the emissions 
increase of VOC shall be as follows:
    (A) In any marginal nonattainment area for ozone--at least 1.1:1;
    (B) In any moderate nonattainment area for ozone--at least 1.15:1;
    (C) In any serious nonattainment area for ozone--at least 1.2:1;
    (D) In any severe nonattainment area for ozone--at least 1.3:1 
(except that the ratio may be at least 1.2:1 if the approved plan also 
requires all existing major sources in such nonattainment area to use 
BACT for the control of VOC); and
    (E) In any extreme nonattainment area for ozone--at least 1.5:1 
(except that the ratio may be at least 1.2:1 if the approved plan also 
requires all existing major sources in such nonattainment area to use 
BACT for the control of VOC); and
    (ii) Notwithstanding the requirements of paragraph (a)(9)(i) of this 
section for meeting the requirements of paragraph (a)(3) of this 
section, the ratio of total actual emissions reductions of VOC to the 
emissions increase of VOC shall be at least 1.15:1 for all areas within 
an ozone transport region that is subject to subpart 2, part D, title I 
of the Act, except for serious, severe, and extreme ozone nonattainment 
areas that are subject to subpart 2, part D, title I of the Act.
    (iii) The plan shall require that in meeting the emissions offset 
requirements of paragraph (a)(3) of this section for ozone nonattainment 
areas that are subject to subpart 1, part D, title I of the Act (but are 
not subject to subpart 2, part D, title I of the Act, including 8-hour 
ozone nonattainment areas subject to 40 CFR 51.902(b)), the ratio of 
total actual emissions reductions of VOC to the emissions increase of 
VOC shall be at least 1:1.
    (10) The plan shall require that the requirements of this section 
applicable to major stationary sources and major modifications of PM-10 
shall also apply to major stationary sources and major modifications of 
PM-10 precursors, except where the Administrator determines that such 
sources do not contribute significantly to PM-10 levels that exceed the 
PM-10 ambient standards in the area.
    (b)(1) Each plan shall include a preconstruction review permit 
program or its equivalent to satisfy the requirements of section 
110(a)(2)(D)(i) of the Act for any new major stationary source or major 
modification as defined in paragraphs (a)(1) (iv) and (v) of this 
section. Such a program shall

[[Page 206]]

apply to any such source or modification that would locate in any area 
designated as attainment or unclassifiable for any national ambient air 
quality standard pursuant to section 107 of the Act, when it would cause 
or contribute to a violation of any national ambient air quality 
standard.
    (2) A major source or major modification will be considered to cause 
or contribute to a violation of a national ambient air quality standard 
when such source or modification would, at a minimum, exceed the 
following significance levels at any locality that does not or would not 
meet the applicable national standard:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                Averaging time (hours)
             Pollutant                       Annual         --------------------------------------------------------------------------------------------
                                                                       24                      8                      3                      1
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2................................  1.0 [micro]g/m\3\.....  5 [micro]g/m\3\.......  .....................  25 [micro]g/m\3\.....
PM10...............................  1.0 [micro]g/m\3\.....  5 [micro]g/m\3\.......
NO2................................  1.0 [micro]g/m\3\.....
CO.................................  ......................  ......................  0.5 mg/m\3\..........  .....................  2 mg/m\3\
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (3) Such a program may include a provision which allows a proposed 
major source or major modification subject to paragraph (b) of this 
section to reduce the impact of its emissions upon air quality by 
obtaining sufficient emission reductions to, at a minimum, compensate 
for its adverse ambient impact where the major source or major 
modification would otherwise cause or contribute to a violation of any 
national ambient air quality standard. The plan shall require that, in 
the absence of such emission reductions, the State or local agency shall 
deny the proposed construction.
    (4) The requirements of paragraph (b) of this section shall not 
apply to a major stationary source or major modification with respect to 
a particular pollutant if the owner or operator demonstrates that, as to 
that pollutant, the source or modification is located in an area 
designated as nonattainment pursuant to section 107 of the Act.
    (c) Clean Unit Test for emissions units that are subject to LAER. 
The plan shall provide an owner or operator of a major stationary source 
the option of using the Clean Unit Test to determine whether emissions 
increases at a Clean Unit are part of a project that is a major 
modification according to the provisions in paragraphs (c)(1) through 
(9) of this section.
    (1) Applicability. The provisions of this paragraph (c) apply to any 
emissions unit for which the reviewing authority has issued a major NSR 
permit within the past 10 years.
    (2) General provisions for Clean Units. The provisions in paragraphs 
(c)(2)(i) through (v) of this section apply to a Clean Unit.
    (i) Any project for which the owner or operator begins actual 
construction after the effective date of the Clean Unit designation (as 
determined in accordance with paragraph (c)(4) of this section) and 
before the expiration date (as determined in accordance with paragraph 
(c)(5) of this section) will be considered to have occurred while the 
emissions unit was a Clean Unit.
    (ii) If a project at a Clean Unit does not cause the need for a 
change in the emission limitations or work practice requirements in the 
permit for the unit that were adopted in conjunction with LAER and the 
project would not alter any physical or operational characteristics that 
formed the basis for the LAER determination as specified in paragraph 
(c)(6)(iv) of this section, the emissions unit remains a Clean Unit.
    (iii) If a project causes the need for a change in the emission 
limitations or work practice requirements in the permit for the unit 
that were adopted in conjunction with LAER or the project would alter 
any physical or operational characteristics that formed the basis for 
the LAER determination as specified in paragraph (c)(6)(iv) of this 
section, then the emissions unit loses its designation as a Clean Unit 
upon issuance of the necessary permit revisions (unless the unit 
requalifies as a Clean Unit pursuant to paragraph (c)(3)(iii) of this 
section). If the owner or operator begins actual construction

[[Page 207]]

on the project without first applying to revise the emissions unit's 
permit, the Clean Unit designation ends immediately prior to the time 
when actual construction begins.
    (iv) A project that causes an emissions unit to lose its designation 
as a Clean Unit is subject to the applicability requirements of 
paragraphs (a)(2)(ii)(A) through (D) and paragraph (a)(2)(ii)(F) of this 
section as if the emissions unit is not a Clean Unit.
    (v) Certain Emissions Units with PSD permits. For emissions units 
that meet the requirements of paragraphs (c)(2)(v)(A) and (B) of this 
section, the BACT level of emissions reductions and/or work practice 
requirements shall satisfy the requirement for LAER in meeting the 
requirements for Clean Units under paragraphs (c)(3) through (8) of this 
section. For these emissions units, all requirements for the LAER 
determination under paragraphs (c)(2)(ii) and (iii) of this section 
shall also apply to the BACT permit terms and conditions. In addition, 
the requirements of paragraph (c)(7)(i)(B) of this section do not apply 
to emissions units that qualify for Clean Unit status under this 
paragraph (c)(2)(v).
    (A) The emissions unit must have received a PSD permit within the 
last 10 years and such permit must require the emissions unit to comply 
with BACT.
    (B) The emissions unit must be located in an area that was 
redesignated as nonattainment for the relevant pollutant(s) after 
issuance of the PSD permit and before the effective date of the Clean 
Unit Test provisions in the area.
    (3) Qualifying or re-qualifying to use the Clean Unit applicability 
test. An emissions unit automatically qualifies as a Clean Unit when the 
unit meets the criteria in paragraphs (c)(3)(i) and (ii) of this 
section. After the original Clean Unit designation expires in accordance 
with paragraph (c)(5) of this section or is lost pursuant to paragraph 
(c)(2)(iii) of this section, such emissions unit may re-qualify as a 
Clean Unit under either paragraph (c)(3)(iii) of this section, or under 
the Clean Unit provisions in paragraph (d) of this section. To re-
qualify as a Clean Unit under paragraph (c)(3)(iii) of this section, the 
emissions unit must obtain a new major NSR permit issued through the 
applicable nonattainment major NSR program and meet all the criteria in 
paragraph (c)(3)(iii) of this section. Clean Unit designation applies 
individually for each pollutant emitted by the emissions unit.
    (i) Permitting requirement. The emissions unit must have received a 
major NSR permit within the past 10 years. The owner or operator must 
maintain and be able to provide information that would demonstrate that 
this permitting requirement is met.
    (ii) Qualifying air pollution control technologies. Air pollutant 
emissions from the emissions unit must be reduced through the use of an 
air pollution control technology (which includes pollution prevention as 
defined under paragraph (a)(1)(xxvi) of this section or work practices) 
that meets both the following requirements in paragraphs (c)(3)(ii)(A) 
and (B) of this section.
    (A) The control technology achieves the LAER level of emissions 
reductions as determined through issuance of a major NSR permit within 
the past 10 years. However, the emissions unit is not eligible for Clean 
Unit designation if the LAER determination resulted in no requirement to 
reduce emissions below the level of a standard, uncontrolled, new 
emissions unit of the same type.
    (B) The owner or operator made an investment to install the control 
technology. For the purpose of this determination, an investment 
includes expenses to research the application of a pollution prevention 
technique to the emissions unit or expenses to apply a pollution 
prevention technique to an emissions unit.
    (iii) Re-qualifying for the Clean Unit designation. The emissions 
unit must obtain a new major NSR permit that requires compliance with 
the current-day LAER, and the emissions unit must meet the requirements 
in paragraphs (c)(3)(i) and (c)(3)(ii) of this section.
    (4) Effective date of the Clean Unit designation. The effective date 
of an emissions unit's Clean Unit designation (that is, the date on 
which the owner or operator may begin to use the Clean Unit Test to 
determine whether a project at the emissions unit is a major

[[Page 208]]

modification) is determined according to the applicable paragraph 
(c)(4)(i) or (c)(4)(ii) of this section.
    (i) Original Clean Unit designation, and emissions units that re-
qualify as Clean Units by implementing a new control technology to meet 
current-day LAER. The effective date is the date the emissions unit's 
air pollution control technology is placed into service, or 3 years 
after the issuance date of the major NSR permit, whichever is earlier, 
but no sooner than the date that provisions for the Clean Unit 
applicability test are approved by the Administrator for incorporation 
into the plan and become effective for the State in which the unit is 
located.
    (ii) Emissions units that re-qualify for the Clean Unit designation 
using an existing control technology. The effective date is the date the 
new, major NSR permit is issued.
    (5) Clean Unit expiration. An emissions unit's Clean Unit 
designation expires (that is, the date on which the owner or operator 
may no longer use the Clean Unit Test to determine whether a project 
affecting the emissions unit is, or is part of, a major modification) 
according to the applicable paragraph (c)(5)(i) or (ii) of this section.
    (i) Original Clean Unit designation, and emissions units that re-
qualify by implementing new control technology to meet current-day LAER. 
For any emissions unit that automatically qualifies as a Clean Unit 
under paragraphs (c)(3)(i) and (ii) of this section, the Clean Unit 
designation expires 10 years after the effective date, or the date the 
equipment went into service, whichever is earlier; or, it expires at any 
time the owner or operator fails to comply with the provisions for 
maintaining Clean Unit designation in paragraph (c)(7) of this section.
    (ii) Emissions units that re-qualify for the Clean Unit designation 
using an existing control technology. For any emissions unit that re-
qualifies as a Clean Unit under paragraph (c)(3)(iii) of this section, 
the Clean Unit designation expires 10 years after the effective date; 
or, it expires any time the owner or operator fails to comply with the 
provisions for maintaining the Clean Unit Designation in paragraph 
(c)(7) of this section.
    (6) Required title V permit content for a Clean Unit. After the 
effective date of the Clean Unit designation, and in accordance with the 
provisions of the applicable title V permit program under part 70 or 
part 71 of this chapter, but no later than when the title V permit is 
renewed, the title V permit for the major stationary source must include 
the following terms and conditions in paragraphs (c)(6)(i) through (vi) 
of this section related to the Clean Unit.
    (i) A statement indicating that the emissions unit qualifies as a 
Clean Unit and identifying the pollutant(s) for which this Clean Unit 
designation applies.
    (ii) The effective date of the Clean Unit designation. If this date 
is not known when the Clean Unit designation is initially recorded in 
the title V permit (e.g., because the air pollution control technology 
is not yet in service), the permit must describe the event that will 
determine the effective date (e.g., the date the control technology is 
placed into service). Once the effective date is determined, the owner 
or operator must notify the reviewing authority of the exact date. This 
specific effective date must be added to the source's title V permit at 
the first opportunity, such as a modification, revision, reopening, or 
renewal of the title V permit for any reason, whichever comes first, but 
in no case later than the next renewal.
    (iii) The expiration date of the Clean Unit designation. If this 
date is not known when the Clean Unit designation is initially recorded 
into the title V permit (e.g., because the air pollution control 
technology is not yet in service), then the permit must describe the 
event that will determine the expiration date (e.g., the date the 
control technology is placed into service). Once the expiration date is 
determined, the owner or operator must notify the reviewing authority of 
the exact date. The expiration date must be added to the source's title 
V permit at the first opportunity, such as a modification, revision, 
reopening, or renewal of the title V permit for any reason, whichever 
comes first, but in no case later than the next renewal.

[[Page 209]]

    (iv) All emission limitations and work practice requirements adopted 
in conjunction with the LAER, and any physical or operational 
characteristics that formed the basis for the LAER determination (e.g., 
possibly the emissions unit's capacity or throughput).
    (v) Monitoring, recordkeeping, and reporting requirements as 
necessary to demonstrate that the emissions unit continues to meet the 
criteria for maintaining the Clean Unit designation. (See paragraph 
(c)(7) of this section.)
    (vi) Terms reflecting the owner or operator's duties to maintain the 
Clean Unit designation and the consequences of failing to do so, as 
presented in paragraph (c)(7) of this section.
    (7) Maintaining the Clean Unit designation. To maintain the Clean 
Unit designation, the owner or operator must conform to all the 
restrictions listed in paragraphs (c)(7)(i) through (iii) of this 
section. This paragraph (c)(7) applies independently to each pollutant 
for which the emissions unit has the Clean Unit designation. That is, 
failing to conform to the restrictions for one pollutant affects Clean 
Unit designation only for that pollutant.
    (i) The Clean Unit must comply with the emission limitation(s) and/
or work practice requirements adopted in conjunction with the LAER that 
is recorded in the major NSR permit, and subsequently reflected in the 
title V permit.
    (A) The owner or operator may not make a physical change in or 
change in the method of operation of the Clean Unit that causes the 
emissions unit to function in a manner that is inconsistent with the 
physical or operational characteristics that formed the basis for the 
LAER determination (e.g., possibly the emissions unit's capacity or 
throughput).
    (B) The Clean Unit may not emit above a level that has been offset.
    (ii) The Clean Unit must comply with any terms and conditions in the 
title V permit related to the unit's Clean Unit designation.
    (iii) The Clean Unit must continue to control emissions using the 
specific air pollution control technology that was the basis for its 
Clean Unit designation. If the emissions unit or control technology is 
replaced, then the Clean Unit designation ends.
    (8) Offsets and netting at Clean Units. Emissions changes that occur 
at a Clean Unit must not be included in calculating a significant net 
emissions increase (that is, must not be used in a ``netting 
analysis''), or be used for generating offsets unless such use occurs 
before the effective date of the Clean Unit designation, or after the 
Clean Unit designation expires; or, unless the emissions unit reduces 
emissions below the level that qualified the unit as a Clean Unit. 
However, if the Clean Unit reduces emissions below the level that 
qualified the unit as a Clean Unit, then, the owner or operator may 
generate a credit for the difference between the level that qualified 
the unit as a Clean Unit and the new emission limitation if such 
reductions are surplus, quantifiable, and permanent. For purposes of 
generating offsets, the reductions must also be federally enforceable. 
For purposes of determining creditable net emissions increases and 
decreases, the reductions must also be enforceable as a practical 
matter.
    (9) Effect of redesignation on the Clean Unit designation. The Clean 
Unit designation of an emissions unit is not affected by redesignation 
of the attainment status of the area in which it is located. That is, if 
a Clean Unit is located in an attainment area and the area is 
redesignated to nonattainment, its Clean Unit designation is not 
affected. Similarly, redesignation from nonattainment to attainment does 
not affect the Clean Unit designation. However, if an existing Clean 
Unit designation expires, it must re-qualify under the requirements that 
are currently applicable in the area.
    (d) Clean Unit provisions for emissions units that achieve an 
emission limitation comparable to LAER. The plan shall provide an owner 
or operator of a major stationary source the option of using the Clean 
Unit Test to determine whether emissions increases at a Clean Unit are 
part of a project that is a major modification according to the 
provisions in paragraphs (d)(1) through (11) of this section.
    (1) Applicability. The provisions of this paragraph (d) apply to 
emissions units which do not qualify as Clean

[[Page 210]]

Units under paragraph (c) of this section, but which are achieving a 
level of emissions control comparable to LAER, as determined by the 
reviewing authority in accordance with this paragraph (d).
    (2) General provisions for Clean Units. The provisions in paragraphs 
(d)(2)(i) through (iv) of this section apply to a Clean Unit (designated 
under this paragraph (d)).
    (i) Any project for which the owner or operator begins actual 
construction after the effective date of the Clean Unit designation (as 
determined in accordance with paragraph (d)(5) of this section) and 
before the expiration date (as determined in accordance with paragraph 
(d)(6) of this section) will be considered to have occurred while the 
emissions unit was a Clean Unit.
    (ii) If a project at a Clean Unit does not cause the need for a 
change in the emission limitations or work practice requirements in the 
permit for the unit that have been determined (pursuant to paragraph 
(d)(4) of this section) to be comparable to LAER, and the project would 
not alter any physical or operational characteristics that formed the 
basis for determining that the emissions unit's control technology 
achieves a level of emissions control comparable to LAER as specified in 
paragraph (d)(8)(iv) of this section, the emissions unit remains a Clean 
Unit.
    (iii) If a project causes the need for a change in the emission 
limitations or work practice requirements in the permit for the unit 
that have been determined (pursuant to paragraph (d)(4) of this section) 
to be comparable to LAER, or the project would alter any physical or 
operational characteristics that formed the basis for determining that 
the emissions unit's control technology achieves a level of emissions 
control comparable to LAER as specified in paragraph (d)(8)(iv) of this 
section, then the emissions unit loses its designation as a Clean Unit 
upon issuance of the necessary permit revisions (unless the unit re-
qualifies as a Clean Unit pursuant to paragraph (d)(3)(iv) of this 
section). If the owner or operator begins actual construction on the 
project without first applying to revise the emissions unit's permit, 
the Clean Unit designation ends immediately prior to the time when 
actual construction begins.
    (iv) A project that causes an emissions unit to lose its designation 
as a Clean Unit is subject to the applicability requirements of 
paragraphs (a)(2)(ii)(A) through (D) and paragraph (a)(2)(ii)(F) of this 
section as if the emissions unit were never a Clean Unit.
    (3) Qualifying or re-qualifying to use the Clean Unit applicability 
test. An emissions unit qualifies as a Clean Unit when the unit meets 
the criteria in paragraphs (d)(3)(i) through (iii) of this section. 
After the original Clean Unit designation expires in accordance with 
paragraph (d)(6) of this section or is lost pursuant to paragraph 
(d)(2)(iii) of this section, such emissions unit may re-qualify as a 
Clean Unit under either paragraph (d)(3)(iv) of this section, or under 
the Clean Unit provisions in paragraph (c) of this section. To re-
qualify as a Clean Unit under paragraph (d)(3)(iv) of this section, the 
emissions unit must obtain a new permit issued pursuant to the 
requirements in paragraphs (d)(7) and (8) of this section and meet all 
the criteria in paragraph (d)(3)(iv) of this section. The reviewing 
authority will make a separate Clean Unit designation for each pollutant 
emitted by the emissions unit for which the emissions unit qualifies as 
a Clean Unit.
    (i) Qualifying air pollution control technologies. Air pollutant 
emissions from the emissions unit must be reduced through the use of air 
pollution control technology (which includes pollution prevention as 
defined under paragraph (a)(1)(xxvi) of this section or work practices) 
that meets both the following requirements in paragraphs (d)(3)(i)(A) 
and (B) of this section.
    (A) The owner or operator has demonstrated that the emissions unit's 
control technology is comparable to LAER according to the requirements 
of paragraph (d)(4) of this section. However, the emissions unit is not 
eligible for the Clean Unit designation if its emissions are not reduced 
below the level of a standard, uncontrolled emissions unit of the same 
type (e.g., if the LAER determinations to which it is

[[Page 211]]

compared have resulted in a determination that no control measures are 
required).
    (B) The owner or operator made an investment to install the control 
technology. For the purpose of this determination, an investment 
includes expenses to research the application of a pollution prevention 
technique to the emissions unit or to retool the unit to apply a 
pollution prevention technique.
    (ii) Impact of emissions from the unit. The reviewing authority must 
determine that the allowable emissions from the emissions unit will not 
cause or contribute to a violation of any national ambient air quality 
standard or PSD increment, or adversely impact an air quality related 
value (such as visibility) that has been identified for a Federal Class 
I area by a Federal Land Manager and for which information is available 
to the general public.
    (iii) Date of installation. An emissions unit may qualify as a Clean 
Unit even if the control technology, on which the Clean Unit designation 
is based, was installed before the effective date of plan requirements 
to implement the requirements of this paragraph (d)(3)(iii). However, 
for such emissions units, the owner or operator must apply for the Clean 
Unit designation within 2 years after the plan requirements become 
effective. For technologies installed after the plan requirements become 
effective, the owner or operator must apply for the Clean Unit 
designation at the time the control technology is installed.
    (iv) Re-qualifying as a Clean Unit. The emissions unit must obtain a 
new permit (pursuant to requirements in paragraphs (d)(7) and (8) of 
this section) that demonstrates that the emissions unit's control 
technology is achieving a level of emission control comparable to 
current-day LAER, and the emissions unit must meet the requirements in 
paragraphs (d)(3)(i)(A) and (d)(3)(ii) of this section.
    (4) Demonstrating control effectiveness comparable to LAER. The 
owner or operator may demonstrate that the emissions unit's control 
technology is comparable to LAER for purposes of paragraph (d)(3)(i) of 
this section according to either paragraph (d)(4)(i) or (ii) of this 
section. Paragraph (d)(4)(iii) of this section specifies the time for 
making this comparison.
    (i) Comparison to previous LAER determinations. The administrator 
maintains an on-line data base of previous determinations of RACT, BACT, 
and LAER in the RACT/BACT/LAER Clearinghouse (RBLC). The emissions 
unit's control technology is presumed to be comparable to LAER if it 
achieves an emission limitation that is at least as stringent as any one 
of the five best-performing similar sources for which a LAER 
determination has been made within the preceding 5 years, and for which 
information has been entered into the RBLC. The reviewing authority 
shall also compare this presumption to any additional LAER 
determinations of which it is aware, and shall consider any information 
on achieved-in-practice pollution control technologies provided during 
the public comment period, to determine whether any presumptive 
determination that the control technology is comparable to LAER is 
correct.
    (ii) The substantially-as-effective test. The owner or operator may 
demonstrate that the emissions unit's control technology is 
substantially as effective as LAER. In addition, any other person may 
present evidence related to whether the control technology is 
substantially as effective as LAER during the public participation 
process required under paragraph (d)(7) of this section. The reviewing 
authority shall consider such evidence on a case-by-case basis and 
determine whether the emissions unit's air pollution control technology 
is substantially as effective as LAER.
    (iii) Time of comparison--(A) Emissions units with control 
technologies that are installed before the effective date of plan 
requirements implementing this paragraph. The owner or operator of an 
emissions unit whose control technology is installed before the 
effective date of plan requirements implementing this paragraph (d) may, 
at its option, either demonstrate that the emission limitation achieved 
by the emissions unit's control technology is comparable to the LAER 
requirements that applied at the time the control technology was 
installed, or demonstrate that the emission limitation

[[Page 212]]

achieved by the emissions unit's control technology is comparable to 
current-day LAER requirements. The expiration date of the Clean Unit 
designation will depend on which option the owner or operator uses, as 
specified in paragraph (d)(6) of this section.
    (B) Emissions units with control technologies that are installed 
after the effective date of plan requirements implementing this 
paragraph. The owner or operator must demonstrate that the emission 
limitation achieved by the emissions unit's control technology is 
comparable to current-day LAER requirements.
    (5) Effective date of the Clean Unit designation. The effective date 
of an emissions unit's Clean Unit designation (that is, the date on 
which the owner or operator may begin to use the Clean Unit Test to 
determine whether a project involving the emissions unit is a major 
modification) is the date that the permit required by paragraph (d)(7) 
of this section is issued or the date that the emissions unit's air 
pollution control technology is placed into service, whichever is later.
    (6) Clean Unit expiration. If the owner or operator demonstrates 
that the emission limitation achieved by the emissions unit's control 
technology is comparable to the LAER requirements that applied at the 
time the control technology was installed, then the Clean Unit 
designation expires 10 years from the date that the control technology 
was installed. For all other emissions units, the Clean Unit designation 
expires 10 years from the effective date of the Clean Unit designation, 
as determined according to paragraph (d)(5) of this section. In 
addition, for all emissions units, the Clean Unit designation expires 
any time the owner or operator fails to comply with the provisions for 
maintaining the Clean Unit designation in paragraph (d)(9) of this 
section.
    (7) Procedures for designating emissions units as Clean Units. The 
reviewing authority shall designate an emissions unit a Clean Unit only 
by issuing a permit through a permitting program that has been approved 
by the Administrator and that conforms with the requirements of 
Sec. Sec. 51.160 through 51.164 of this chapter including requirements 
for public notice of the proposed Clean Unit designation and opportunity 
for public comment. Such permit must also meet the requirements in 
paragraph (d)(8).
    (8) Required permit content. The permit required by paragraph (d)(7) 
of this section shall include the terms and conditions set forth in 
paragraphs (d)(8)(i) through (vi) of this section. Such terms and 
conditions shall be incorporated into the major stationary source's 
title V permit in accordance with the provisions of the applicable title 
V permit program under part 70 or part 71 of this chapter, but no later 
than when the title V permit is renewed.
    (i) A statement indicating that the emissions unit qualifies as a 
Clean Unit and identifying the pollutant(s) for which this designation 
applies.
    (ii) The effective date of the Clean Unit designation. If this date 
is not known when the reviewing authority issues the permit (e.g., 
because the air pollution control technology is not yet in service), 
then the permit must describe the event that will determine the 
effective date (e.g., the date the control technology is placed into 
service). Once the effective date is known, then the owner or operator 
must notify the reviewing authority of the exact date. This specific 
effective date must be added to the source's title V permit at the first 
opportunity, such as a modification, revision, reopening, or renewal of 
the title V permit for any reason, whichever comes first, but in no case 
later than the next renewal.
    (iii) The expiration date of the Clean Unit designation. If this 
date is not known when the reviewing authority issues the permit (e.g., 
because the air pollution control technology is not yet in service), 
then the permit must describe the event that will determine the 
expiration date (e.g., the date the control technology is placed into 
service). Once the expiration date is known, then the owner or operator 
must notify the reviewing authority of the exact date. The expiration 
date must be added to the source's title V permit at the first 
opportunity, such as a modification, revision, reopening, or renewal of 
the title V permit for any

[[Page 213]]

reason, whichever comes first, but in no case later than the next 
renewal.
    (iv) All emission limitations and work practice requirements adopted 
in conjunction with emission limitations necessary to assure that the 
control technology continues to achieve an emission limitation 
comparable to LAER, and any physical or operational characteristics that 
formed the basis for determining that the emissions unit's control 
technology achieves a level of emissions control comparable to LAER 
(e.g., possibly the emissions unit's capacity or throughput).
    (v) Monitoring, recordkeeping, and reporting requirements as 
necessary to demonstrate that the emissions unit continues to meet the 
criteria for maintaining its Clean Unit designation. (See paragraph 
(d)(9) of this section.)
    (vi) Terms reflecting the owner or operator's duties to maintain the 
Clean Unit designation and the consequences of failing to do so, as 
presented in paragraph (d)(9) of this section.
    (9) Maintaining Clean Unit designation. To maintain Clean Unit 
designation, the owner or operator must conform to all the restrictions 
listed in paragraphs (d)(9)(i) through (v) of this section. This 
paragraph (d)(9) applies independently to each pollutant for which the 
reviewing authority has designated the emissions unit a Clean Unit. That 
is, failing to conform to the restrictions for one pollutant affects the 
Clean Unit designation only for that pollutant.
    (i) The Clean Unit must comply with the emission limitation(s) and/
or work practice requirements adopted to ensure that the control 
technology continues to achieve emission control comparable to LAER.
    (ii) The owner or operator may not make a physical change in or 
change in the method of operation of the Clean Unit that causes the 
emissions unit to function in a manner that is inconsistent with the 
physical or operational characteristics that formed the basis for the 
determination that the control technology is achieving a level of 
emission control that is comparable to LAER (e.g., possibly the 
emissions unit's capacity or throughput).
    (iii) The Clean Unit may not emit above a level that has been 
offset.
    (iv) The Clean Unit must comply with any terms and conditions in the 
title V permit related to the unit's Clean Unit designation.
    (v) The Clean Unit must continue to control emissions using the 
specific air pollution control technology that was the basis for its 
Clean Unit designation. If the emissions unit or control technology is 
replaced, then the Clean Unit designation ends.
    (10) Offsets and Netting at Clean Units. Emissions changes that 
occur at a Clean Unit must not be included in calculating a significant 
net emissions increase (that is, must not be used in a ``netting 
analysis''), or be used for generating offsets unless such use occurs 
before the effective date of plan requirements adopted to implement this 
paragraph (d) or after the Clean Unit designation expires; or, unless 
the emissions unit reduces emissions below the level that qualified the 
unit as a Clean Unit. However, if the Clean Unit reduces emissions below 
the level that qualified the unit as a Clean Unit, then the owner or 
operator may generate a credit for the difference between the level that 
qualified the unit as a Clean Unit and the emissions unit's new emission 
limitation if such reductions are surplus, quantifiable, and permanent. 
For purposes of generating offsets, the reductions must also be 
federally enforceable. For purposes of determining creditable net 
emissions increases and decreases, the reductions must also be 
enforceable as a practical matter.
    (11) Effect of redesignation on the Clean Unit designation. The 
Clean Unit designation of an emissions unit is not affected by 
redesignation of the attainment status of the area in which it is 
located. That is, if a Clean Unit is located in an attainment area and 
the area is redesignated to nonattainment, its Clean Unit designation is 
not affected. Similarly, redesignation from nonattainment to attainment 
does not affect the Clean Unit designation. However, if a Clean Unit's 
designation expires or is lost pursuant to paragraphs (c)(2)(iii) and 
(d)(2)(iii) of this section, it must re-qualify under the requirements 
that are currently applicable.

[[Page 214]]

    (e) PCP exclusion procedural requirements. Each plan shall include 
provisions for PCPs equivalent to those contained in paragraphs (e)(1) 
through (6) of this section.
    (1) Before an owner or operator begins actual construction of a PCP, 
the owner or operator must either submit a notice to the reviewing 
authority if the project is listed in paragraphs (a)(1)(xxv)(A) through 
(F) of this section, or if the project is not listed in paragraphs 
(a)(1)(xxv)(A) through (F) of this section, then the owner or operator 
must submit a permit application and obtain approval to use the PCP 
exclusion from the reviewing authority consistent with the requirements 
in paragraph (e)(5) of this section. Regardless of whether the owner or 
operator submits a notice or a permit application, the project must meet 
the requirements in paragraph (e)(2) of this section, and the notice or 
permit application must contain the information required in paragraph 
(e)(3) of this section.
    (2) Any project that relies on the PCP exclusion must meet the 
requirements in paragraphs (e)(2)(i) and (ii) of this section.
    (i) Environmentally beneficial analysis. The environmental benefit 
from the emission reductions of pollutants regulated under the Act must 
outweigh the environmental detriment of emissions increases in 
pollutants regulated under the Act. A statement that a technology from 
paragraphs (a)(1)(xxv)(A) through (F) of this section is being used 
shall be presumed to satisfy this requirement.
    (ii) Air quality analysis. The emissions increases from the project 
will not cause or contribute to a violation of any national ambient air 
quality standard or PSD increment, or adversely impact an air quality 
related value (such as visibility) that has been identified for a 
Federal Class I area by a Federal Land Manager and for which information 
is available to the general public.
    (3) Content of notice or permit application. In the notice or permit 
application sent to the reviewing authority, the owner or operator must 
include, at a minimum, the information listed in paragraphs (e)(3)(i) 
through (v) of this section.
    (i) A description of the project.
    (ii) The potential emissions increases and decreases of any 
pollutant regulated under the Act and the projected emissions increases 
and decreases using the methodology in paragraph (a)(2)(ii) of this 
section, that will result from the project, and a copy of the 
environmentally beneficial analysis required by paragraph (e)(2)(i) of 
this section.
    (iii) A description of monitoring and recordkeeping, and all other 
methods, to be used on an ongoing basis to demonstrate that the project 
is environmentally beneficial. Methods should be sufficient to meet the 
requirements in part 70 and part 71.
    (iv) A certification that the project will be designed and operated 
in a manner that is consistent with proper industry and engineering 
practices, in a manner that is consistent with the environmentally 
beneficial analysis and air quality analysis required by paragraphs 
(e)(2)(i) and (ii) of this section, with information submitted in the 
notice or permit application, and in such a way as to minimize, within 
the physical configuration and operational standards usually associated 
with the emissions control device or strategy, emissions of collateral 
pollutants.
    (v) Demonstration that the PCP will not have an adverse air quality 
impact (e.g., modeling, screening level modeling results, or a statement 
that the collateral emissions increase is included within the parameters 
used in the most recent modeling exercise) as required by paragraph 
(e)(2)(ii) of this section. An air quality impact analysis is not 
required for any pollutant which will not experience a significant 
emissions increase as a result of the project.
    (4) Notice process for listed projects. For projects listed in 
paragraphs (a)(1)(xxv)(A) through (F) of this section, the owner or 
operator may begin actual construction of the project immediately after 
notice is sent to the reviewing authority (unless otherwise prohibited 
under requirements of the applicable plan). The owner or operator shall 
respond to any requests by its reviewing authority for additional 
information that the reviewing authority determines is necessary to 
evaluate the

[[Page 215]]

suitability of the project for the PCP exclusion.
    (5) Permit process for unlisted projects. Before an owner or 
operator may begin actual construction of a PCP project that is not 
listed in paragraphs (a)(1)(xxv)(A) through (F) of this section, the 
project must be approved by the reviewing authority and recorded in a 
plan-approved permit or title V permit using procedures that are 
consistent with Sec. Sec. 51.160 and 51.161 of this chapter. This 
includes the requirement that the reviewing authority provide the public 
with notice of the proposed approval, with access to the environmentally 
beneficial analysis and the air quality analysis, and provide at least a 
30-day period for the public and the Administrator to submit comments. 
The reviewing authority must address all material comments received by 
the end of the comment period before taking final action on the permit.
    (6) Operational requirements. Upon installation of the PCP, the 
owner or operator must comply with the requirements of paragraphs 
(e)(6)(i) through (iii) of this section.
    (i) General duty. The owner or operator must operate the PCP in a 
manner consistent with proper industry and engineering practices, in a 
manner that is consistent with the environmentally beneficial analysis 
and air quality analysis required by paragraphs (e)(2)(i) and (ii) of 
this section, with information submitted in the notice or permit 
application required by paragraph (e)(3) of this section, and in such a 
way as to minimize, within the physical configuration and operational 
standards usually associated with the emissions control device or 
strategy, emissions of collateral pollutants.
    (ii) Recordkeeping. The owner or operator must maintain copies on 
site of the environmentally beneficial analysis, the air quality impacts 
analysis, and monitoring and other emission records to prove that the 
PCP operated consistent with the general duty requirements in paragraph 
(e)(6)(i) of this section.
    (iii) Permit requirements. The owner or operator must comply with 
any provisions in the plan-approved permit or title V permit related to 
use and approval of the PCP exclusion.
    (iv) Generation of emission reduction credits. Emission reductions 
created by a PCP shall not be included in calculating a significant net 
emissions increase, or be used for generating offsets, unless the 
emissions unit further reduces emissions after qualifying for the PCP 
exclusion (e.g., taking an operational restriction on the hours of 
operation). The owner or operator may generate a credit for the 
difference between the level of reduction which was used to qualify for 
the PCP exclusion and the new emission limitation if such reductions are 
surplus, quantifiable, and permanent. For purposes of generating 
offsets, the reductions must also be federally enforceable. For purposes 
of determining creditable net emissions increases and decreases, the 
reductions must also be enforceable as a practical matter.
    (f) Actuals PALs. The plan shall provide for PALs according to the 
provisions in paragraphs (f)(1) through (15) of this section.
    (1) Applicability. (i) The reviewing authority may approve the use 
of an actuals PAL for any existing major stationary source (except as 
provided in paragraph (f)(1)(ii) of this section) if the PAL meets the 
requirements in paragraphs (f)(1) through (15) of this section. The term 
``PAL'' shall mean ``actuals PAL'' throughout paragraph (f) of this 
section.
    (ii) The reviewing authority shall not allow an actuals PAL for VOC 
or NOX for any major stationary source located in an extreme 
ozone nonattainment area.
    (iii) Any physical change in or change in the method of operation of 
a major stationary source that maintains its total source-wide emissions 
below the PAL level, meets the requirements in paragraphs (f)(1) through 
(15) of this section, and complies with the PAL permit:
    (A) Is not a major modification for the PAL pollutant;
    (B) Does not have to be approved through the plan's nonattainment 
major NSR program; and
    (C) Is not subject to the provisions in paragraph (a)(5)(ii) of this 
section (restrictions on relaxing enforceable

[[Page 216]]

emission limitations that the major stationary source used to avoid 
applicability of the nonattainment major NSR program).
    (iv) Except as provided under paragraph (f)(1)(iii)(C) of this 
section, a major stationary source shall continue to comply with all 
applicable Federal or State requirements, emission limitations, and work 
practice requirements that were established prior to the effective date 
of the PAL.
    (2) Definitions. The plan shall use the definitions in paragraphs 
(f)(2)(i) through (xi) of this section for the purpose of developing and 
implementing regulations that authorize the use of actuals PALs 
consistent with paragraphs (f)(1) through (15) of this section. When a 
term is not defined in these paragraphs, it shall have the meaning given 
in paragraph (a)(1) of this section or in the Act.
    (i) Actuals PAL for a major stationary source means a PAL based on 
the baseline actual emissions (as defined in paragraph (a)(1)(xxxv) of 
this section) of all emissions units (as defined in paragraph 
(a)(1)(vii) of this section) at the source, that emit or have the 
potential to emit the PAL pollutant.
    (ii) Allowable emissions means ``allowable emissions'' as defined in 
paragraph (a)(1)(xi) of this section, except as this definition is 
modified according to paragraphs (f)(2)(ii)(A) through (B) of this 
section.
    (A) The allowable emissions for any emissions unit shall be 
calculated considering any emission limitations that are enforceable as 
a practical matter on the emissions unit's potential to emit.
    (B) An emissions unit's potential to emit shall be determined using 
the definition in paragraph (a)(1)(iii) of this section, except that the 
words ``or enforceable as a practical matter'' should be added after 
``federally enforceable.''
    (iii) Small emissions unit means an emissions unit that emits or has 
the potential to emit the PAL pollutant in an amount less than the 
significant level for that PAL pollutant, as defined in paragraph 
(a)(1)(x) of this section or in the Act, whichever is lower.
    (iv) Major emissions unit means:
    (A) Any emissions unit that emits or has the potential to emit 100 
tons per year or more of the PAL pollutant in an attainment area; or
    (B) Any emissions unit that emits or has the potential to emit the 
PAL pollutant in an amount that is equal to or greater than the major 
source threshold for the PAL pollutant as defined by the Act for 
nonattainment areas. For example, in accordance with the definition of 
major stationary source in section 182(c) of the Act, an emissions unit 
would be a major emissions unit for VOC if the emissions unit is located 
in a serious ozone nonattainment area and it emits or has the potential 
to emit 50 or more tons of VOC per year.
    (v) Plantwide applicability limitation (PAL) means an emission 
limitation expressed in tons per year, for a pollutant at a major 
stationary source, that is enforceable as a practical matter and 
established source-wide in accordance with paragraphs (f)(1) through 
(f)(15) of this section.
    (vi) PAL effective date generally means the date of issuance of the 
PAL permit. However, the PAL effective date for an increased PAL is the 
date any emissions unit which is part of the PAL major modification 
becomes operational and begins to emit the PAL pollutant.
    (vii) PAL effective period means the period beginning with the PAL 
effective date and ending 10 years later.
    (viii) PAL major modification means, notwithstanding paragraphs 
(a)(1)(v) and (vi) of this section (the definitions for major 
modification and net emissions increase), any physical change in or 
change in the method of operation of the PAL source that causes it to 
emit the PAL pollutant at a level equal to or greater than the PAL.
    (ix) PAL permit means the major NSR permit, the minor NSR permit, or 
the State operating permit under a program that is approved into the 
plan, or the title V permit issued by the reviewing authority that 
establishes a PAL for a major stationary source.
    (x) PAL pollutant means the pollutant for which a PAL is established 
at a major stationary source.
    (xi) Significant emissions unit means an emissions unit that emits 
or has the potential to emit a PAL pollutant in an amount that is equal 
to or greater than the significant level (as defined in

[[Page 217]]

paragraph (a)(1)(x) of this section or in the Act, whichever is lower) 
for that PAL pollutant, but less than the amount that would qualify the 
unit as a major emissions unit as defined in paragraph (f)(2)(iv) of 
this section.
    (3) Permit application requirements. As part of a permit application 
requesting a PAL, the owner or operator of a major stationary source 
shall submit the following information to the reviewing authority for 
approval:
    (i) A list of all emissions units at the source designated as small, 
significant or major based on their potential to emit. In addition, the 
owner or operator of the source shall indicate which, if any, Federal or 
State applicable requirements, emission limitations or work practices 
apply to each unit.
    (ii) Calculations of the baseline actual emissions (with supporting 
documentation). Baseline actual emissions are to include emissions 
associated not only with operation of the unit, but also emissions 
associated with startup, shutdown and malfunction.
    (iii) The calculation procedures that the major stationary source 
owner or operator proposes to use to convert the monitoring system data 
to monthly emissions and annual emissions based on a 12-month rolling 
total for each month as required by paragraph (f)(13)(i) of this 
section.
    (4) General requirements for establishing PALs. (i) The plan allows 
the reviewing authority to establish a PAL at a major stationary source, 
provided that at a minimum, the requirements in paragraphs (f)(4)(i)(A) 
through (G) of this section are met.
    (A) The PAL shall impose an annual emission limitation in tons per 
year, that is enforceable as a practical matter, for the entire major 
stationary source. For each month during the PAL effective period after 
the first 12 months of establishing a PAL, the major stationary source 
owner or operator shall show that the sum of the monthly emissions from 
each emissions unit under the PAL for the previous 12 consecutive months 
is less than the PAL (a 12-month average, rolled monthly). For each 
month during the first 11 months from the PAL effective date, the major 
stationary source owner or operator shall show that the sum of the 
preceding monthly emissions from the PAL effective date for each 
emissions unit under the PAL is less than the PAL.
    (B) The PAL shall be established in a PAL permit that meets the 
public participation requirements in paragraph (f)(5) of this section.
    (C) The PAL permit shall contain all the requirements of paragraph 
(f)(7) of this section.
    (D) The PAL shall include fugitive emissions, to the extent 
quantifiable, from all emissions units that emit or have the potential 
to emit the PAL pollutant at the major stationary source.
    (E) Each PAL shall regulate emissions of only one pollutant.
    (F) Each PAL shall have a PAL effective period of 10 years.
    (G) The owner or operator of the major stationary source with a PAL 
shall comply with the monitoring, recordkeeping, and reporting 
requirements provided in paragraphs (f)(12) through (14) of this section 
for each emissions unit under the PAL through the PAL effective period.
    (ii) At no time (during or after the PAL effective period) are 
emissions reductions of a PAL pollutant, which occur during the PAL 
effective period, creditable as decreases for purposes of offsets under 
paragraph (a)(3)(ii) of this section unless the level of the PAL is 
reduced by the amount of such emissions reductions and such reductions 
would be creditable in the absence of the PAL.
    (5) Public participation requirement for PALs. PALs for existing 
major stationary sources shall be established, renewed, or increased 
through a procedure that is consistent with Sec. Sec. 51.160 and 51.161 
of this chapter. This includes the requirement that the reviewing 
authority provide the public with notice of the proposed approval of a 
PAL permit and at least a 30-day period for submittal of public comment. 
The reviewing authority must address all material comments before taking 
final action on the permit.
    (6) Setting the 10-year actuals PAL level. (i) Except as provided in 
paragraph (f)(6)(ii) of this section, the plan shall provide that the 
actuals PAL level for a major stationary source

[[Page 218]]

shall be established as the sum of the baseline actual emissions (as 
defined in paragraph (a)(1)(xxxv) of this section) of the PAL pollutant 
for each emissions unit at the source; plus an amount equal to the 
applicable significant level for the PAL pollutant under paragraph 
(a)(1)(x) of this section or under the Act, whichever is lower. When 
establishing the actuals PAL level, for a PAL pollutant, only one 
consecutive 24-month period must be used to determine the baseline 
actual emissions for all existing emissions units. However, a different 
consecutive 24-month period may be used for each different PAL 
pollutant. Emissions associated with units that were permanently shut 
down after this 24-month period must be subtracted from the PAL level. 
The reviewing authority shall specify a reduced PAL level(s) (in tons/
yr) in the PAL permit to become effective on the future compliance 
date(s) of any applicable Federal or State regulatory requirement(s) 
that the reviewing authority is aware of prior to issuance of the PAL 
permit. For instance, if the source owner or operator will be required 
to reduce emissions from industrial boilers in half from baseline 
emissions of 60 ppm NOX to a new rule limit of 30 ppm, then 
the permit shall contain a future effective PAL level that is equal to 
the current PAL level reduced by half of the original baseline emissions 
of such unit(s).
    (ii) For newly constructed units (which do not include modifications 
to existing units) on which actual construction began after the 24-month 
period, in lieu of adding the baseline actual emissions as specified in 
paragraph (f)(6)(i) of this section, the emissions must be added to the 
PAL level in an amount equal to the potential to emit of the units.
    (7) Contents of the PAL permit. The plan shall require that the PAL 
permit contain, at a minimum, the information in paragraphs (f)(7)(i) 
through (x) of this section.
    (i) The PAL pollutant and the applicable source-wide emission 
limitation in tons per year.
    (ii) The PAL permit effective date and the expiration date of the 
PAL (PAL effective period).
    (iii) Specification in the PAL permit that if a major stationary 
source owner or operator applies to renew a PAL in accordance with 
paragraph (f)(10) of this section before the end of the PAL effective 
period, then the PAL shall not expire at the end of the PAL effective 
period. It shall remain in effect until a revised PAL permit is issued 
by the reviewing authority.
    (iv) A requirement that emission calculations for compliance 
purposes include emissions from startups, shutdowns and malfunctions.
    (v) A requirement that, once the PAL expires, the major stationary 
source is subject to the requirements of paragraph (f)(9) of this 
section.
    (vi) The calculation procedures that the major stationary source 
owner or operator shall use to convert the monitoring system data to 
monthly emissions and annual emissions based on a 12-month rolling total 
for each month as required by paragraph (f)(13)(i) of this section.
    (vii) A requirement that the major stationary source owner or 
operator monitor all emissions units in accordance with the provisions 
under paragraph (f)(12) of this section.
    (viii) A requirement to retain the records required under paragraph 
(f)(13) of this section on site. Such records may be retained in an 
electronic format.
    (ix) A requirement to submit the reports required under paragraph 
(f)(14) of this section by the required deadlines.
    (x) Any other requirements that the reviewing authority deems 
necessary to implement and enforce the PAL.
    (8) PAL effective period and reopening of the PAL permit. The plan 
shall require the information in paragraphs (f)(8)(i) and (ii) of this 
section.
    (i) PAL effective period. The reviewing authority shall specify a 
PAL effective period of 10 years.
    (ii) Reopening of the PAL permit. (A) During the PAL effective 
period, the plan shall require the reviewing authority to reopen the PAL 
permit to:
    (1) Correct typographical/calculation errors made in setting the PAL 
or reflect a more accurate determination of emissions used to establish 
the PAL.

[[Page 219]]

    (2) Reduce the PAL if the owner or operator of the major stationary 
source creates creditable emissions reductions for use as offsets under 
paragraph (a)(3)(ii) of this section.
    (3) Revise the PAL to reflect an increase in the PAL as provided 
under paragraph (f)(11) of this section.
    (B) The plan shall provide the reviewing authority discretion to 
reopen the PAL permit for the following:
    (1) Reduce the PAL to reflect newly applicable Federal requirements 
(for example, NSPS) with compliance dates after the PAL effective date.
    (2) Reduce the PAL consistent with any other requirement, that is 
enforceable as a practical matter, and that the State may impose on the 
major stationary source under the plan.
    (3) Reduce the PAL if the reviewing authority determines that a 
reduction is necessary to avoid causing or contributing to a NAAQS or 
PSD increment violation, or to an adverse impact on an air quality 
related value that has been identified for a Federal Class I area by a 
Federal Land Manager and for which information is available to the 
general public.
    (C) Except for the permit reopening in paragraph (f)(8)(ii)(A)(1) of 
this section for the correction of typographical/calculation errors that 
do not increase the PAL level, all other reopenings shall be carried out 
in accordance with the public participation requirements of paragraph 
(f)(5) of this section.
    (9) Expiration of a PAL. Any PAL which is not renewed in accordance 
with the procedures in paragraph (f)(10) of this section shall expire at 
the end of the PAL effective period, and the requirements in paragraphs 
(f)(9)(i) through (v) of this section shall apply.
    (i) Each emissions unit (or each group of emissions units) that 
existed under the PAL shall comply with an allowable emission limitation 
under a revised permit established according to the procedures in 
paragraphs (f)(9)(i)(A) through (B) of this section.
    (A) Within the time frame specified for PAL renewals in paragraph 
(f)(10)(ii) of this section, the major stationary source shall submit a 
proposed allowable emission limitation for each emissions unit (or each 
group of emissions units, if such a distribution is more appropriate as 
decided by the reviewing authority) by distributing the PAL allowable 
emissions for the major stationary source among each of the emissions 
units that existed under the PAL. If the PAL had not yet been adjusted 
for an applicable requirement that became effective during the PAL 
effective period, as required under paragraph (f)(10)(v) of this 
section, such distribution shall be made as if the PAL had been 
adjusted.
    (B) The reviewing authority shall decide whether and how the PAL 
allowable emissions will be distributed and issue a revised permit 
incorporating allowable limits for each emissions unit, or each group of 
emissions units, as the reviewing authority determines is appropriate.
    (ii) Each emissions unit(s) shall comply with the allowable emission 
limitation on a 12-month rolling basis. The reviewing authority may 
approve the use of monitoring systems (source testing, emission factors, 
etc.) other than CEMS, CERMS, PEMS or CPMS to demonstrate compliance 
with the allowable emission limitation.
    (iii) Until the reviewing authority issues the revised permit 
incorporating allowable limits for each emissions unit, or each group of 
emissions units, as required under paragraph (f)(9)(i)(A) of this 
section, the source shall continue to comply with a source-wide, multi-
unit emissions cap equivalent to the level of the PAL emission 
limitation.
    (iv) Any physical change or change in the method of operation at the 
major stationary source will be subject to the nonattainment major NSR 
requirements if such change meets the definition of major modification 
in paragraph (a)(1)(v) of this section.
    (v) The major stationary source owner or operator shall continue to 
comply with any State or Federal applicable requirements (BACT, RACT, 
NSPS, etc.) that may have applied either during the PAL effective period 
or prior to the PAL effective period except for those emission 
limitations that had been established pursuant to paragraph (a)(5)(ii) 
of this section, but

[[Page 220]]

were eliminated by the PAL in accordance with the provisions in 
paragraph (f)(1)(iii)(C) of this section.
    (10) Renewal of a PAL. (i) The reviewing authority shall follow the 
procedures specified in paragraph (f)(5) of this section in approving 
any request to renew a PAL for a major stationary source, and shall 
provide both the proposed PAL level and a written rationale for the 
proposed PAL level to the public for review and comment. During such 
public review, any person may propose a PAL level for the source for 
consideration by the reviewing authority.
    (ii) Application deadline. The plan shall require that a major 
stationary source owner or operator shall submit a timely application to 
the reviewing authority to request renewal of a PAL. A timely 
application is one that is submitted at least 6 months prior to, but not 
earlier than 18 months from, the date of permit expiration. This 
deadline for application submittal is to ensure that the permit will not 
expire before the permit is renewed. If the owner or operator of a major 
stationary source submits a complete application to renew the PAL within 
this time period, then the PAL shall continue to be effective until the 
revised permit with the renewed PAL is issued.
    (iii) Application requirements. The application to renew a PAL 
permit shall contain the information required in paragraphs 
(f)(10)(iii)(A) through (D) of this section.
    (A) The information required in paragraphs (f)(3)(i) through (iii) 
of this section.
    (B) A proposed PAL level.
    (C) The sum of the potential to emit of all emissions units under 
the PAL (with supporting documentation).
    (D) Any other information the owner or operator wishes the reviewing 
authority to consider in determining the appropriate level for renewing 
the PAL.
    (iv) PAL adjustment. In determining whether and how to adjust the 
PAL, the reviewing authority shall consider the options outlined in 
paragraphs (f)(10)(iv)(A) and (B) of this section. However, in no case 
may any such adjustment fail to comply with paragraph (f)(10)(iv)(C) of 
this section.
    (A) If the emissions level calculated in accordance with paragraph 
(f)(6) of this section is equal to or greater than 80 percent of the PAL 
level, the reviewing authority may renew the PAL at the same level 
without considering the factors set forth in paragraph (f)(10)(iv)(B) of 
this section; or
    (B) The reviewing authority may set the PAL at a level that it 
determines to be more representative of the source's baseline actual 
emissions, or that it determines to be appropriate considering air 
quality needs, advances in control technology, anticipated economic 
growth in the area, desire to reward or encourage the source's voluntary 
emissions reductions, or other factors as specifically identified by the 
reviewing authority in its written rationale.
    (C) Notwithstanding paragraphs (f)(10)(iv)(A) and (B) of this 
section,
    (1) If the potential to emit of the major stationary source is less 
than the PAL, the reviewing authority shall adjust the PAL to a level no 
greater than the potential to emit of the source; and
    (2) The reviewing authority shall not approve a renewed PAL level 
higher than the current PAL, unless the major stationary source has 
complied with the provisions of paragraph (f)(11) of this section 
(increasing a PAL).
    (v) If the compliance date for a State or Federal requirement that 
applies to the PAL source occurs during the PAL effective period, and if 
the reviewing authority has not already adjusted for such requirement, 
the PAL shall be adjusted at the time of PAL permit renewal or title V 
permit renewal, whichever occurs first.
    (11) Increasing a PAL during the PAL effective period. (i) The plan 
shall require that the reviewing authority may increase a PAL emission 
limitation only if the major stationary source complies with the 
provisions in paragraphs (f)(11)(i)(A) through (D) of this section.
    (A) The owner or operator of the major stationary source shall 
submit a complete application to request an increase in the PAL limit 
for a PAL major modification. Such application shall identify the 
emissions unit(s)

[[Page 221]]

contributing to the increase in emissions so as to cause the major 
stationary source's emissions to equal or exceed its PAL.
    (B) As part of this application, the major stationary source owner 
or operator shall demonstrate that the sum of the baseline actual 
emissions of the small emissions units, plus the sum of the baseline 
actual emissions of the significant and major emissions units assuming 
application of BACT equivalent controls, plus the sum of the allowable 
emissions of the new or modified emissions unit(s) exceeds the PAL. The 
level of control that would result from BACT equivalent controls on each 
significant or major emissions unit shall be determined by conducting a 
new BACT analysis at the time the application is submitted, unless the 
emissions unit is currently required to comply with a BACT or LAER 
requirement that was established within the preceding 10 years. In such 
a case, the assumed control level for that emissions unit shall be equal 
to the level of BACT or LAER with which that emissions unit must 
currently comply.
    (C) The owner or operator obtains a major NSR permit for all 
emissions unit(s) identified in paragraph (f)(11)(i)(A) of this section, 
regardless of the magnitude of the emissions increase resulting from 
them (that is, no significant levels apply). These emissions unit(s) 
shall comply with any emissions requirements resulting from the 
nonattainment major NSR program process (for example, LAER), even though 
they have also become subject to the PAL or continue to be subject to 
the PAL.
    (D) The PAL permit shall require that the increased PAL level shall 
be effective on the day any emissions unit that is part of the PAL major 
modification becomes operational and begins to emit the PAL pollutant.
    (ii) The reviewing authority shall calculate the new PAL as the sum 
of the allowable emissions for each modified or new emissions unit, plus 
the sum of the baseline actual emissions of the significant and major 
emissions units (assuming application of BACT equivalent controls as 
determined in accordance with paragraph (f)(11)(i)(B)), plus the sum of 
the baseline actual emissions of the small emissions units.
    (iii) The PAL permit shall be revised to reflect the increased PAL 
level pursuant to the public notice requirements of paragraph (f)(5) of 
this section.
    (12) Monitoring requirements for PALs--(i) General requirements. (A) 
Each PAL permit must contain enforceable requirements for the monitoring 
system that accurately determines plantwide emissions of the PAL 
pollutant in terms of mass per unit of time. Any monitoring system 
authorized for use in the PAL permit must be based on sound science and 
meet generally acceptable scientific procedures for data quality and 
manipulation. Additionally, the information generated by such system 
must meet minimum legal requirements for admissibility in a judicial 
proceeding to enforce the PAL permit.
    (B) The PAL monitoring system must employ one or more of the four 
general monitoring approaches meeting the minimum requirements set forth 
in paragraphs (f)(12)(ii)(A) through (D) of this section and must be 
approved by the reviewing authority.
    (C) Notwithstanding paragraph (f)(12)(i)(B) of this section, you may 
also employ an alternative monitoring approach that meets paragraph 
(f)(12)(i)(A) of this section if approved by the reviewing authority.
    (D) Failure to use a monitoring system that meets the requirements 
of this section renders the PAL invalid.
    (ii) Minimum Performance Requirements for Approved Monitoring 
Approaches. The following are acceptable general monitoring approaches 
when conducted in accordance with the minimum requirements in paragraphs 
(f)(12)(iii) through (ix) of this section:
    (A) Mass balance calculations for activities using coatings or 
solvents;
    (B) CEMS;
    (C) CPMS or PEMS; and
    (D) Emission Factors.
    (iii) Mass Balance Calculations. An owner or operator using mass 
balance calculations to monitor PAL pollutant emissions from activities 
using coating or solvents shall meet the following requirements:

[[Page 222]]

    (A) Provide a demonstrated means of validating the published content 
of the PAL pollutant that is contained in or created by all materials 
used in or at the emissions unit;
    (B) Assume that the emissions unit emits all of the PAL pollutant 
that is contained in or created by any raw material or fuel used in or 
at the emissions unit, if it cannot otherwise be accounted for in the 
process; and
    (C) Where the vendor of a material or fuel, which is used in or at 
the emissions unit, publishes a range of pollutant content from such 
material, the owner or operator must use the highest value of the range 
to calculate the PAL pollutant emissions unless the reviewing authority 
determines there is site-specific data or a site-specific monitoring 
program to support another content within the range.
    (iv) CEMS. An owner or operator using CEMS to monitor PAL pollutant 
emissions shall meet the following requirements:
    (A) CEMS must comply with applicable Performance Specifications 
found in 40 CFR part 60, appendix B; and
    (B) CEMS must sample, analyze and record data at least every 15 
minutes while the emissions unit is operating.
    (v) CPMS or PEMS. An owner or operator using CPMS or PEMS to monitor 
PAL pollutant emissions shall meet the following requirements:
    (A) The CPMS or the PEMS must be based on current site-specific data 
demonstrating a correlation between the monitored parameter(s) and the 
PAL pollutant emissions across the range of operation of the emissions 
unit; and
    (B) Each CPMS or PEMS must sample, analyze, and record data at least 
every 15 minutes, or at another less frequent interval approved by the 
reviewing authority, while the emissions unit is operating.
    (vi) Emission factors. An owner or operator using emission factors 
to monitor PAL pollutant emissions shall meet the following 
requirements:
    (A) All emission factors shall be adjusted, if appropriate, to 
account for the degree of uncertainty or limitations in the factors' 
development;
    (B) The emissions unit shall operate within the designated range of 
use for the emission factor, if applicable; and
    (C) If technically practicable, the owner or operator of a 
significant emissions unit that relies on an emission factor to 
calculate PAL pollutant emissions shall conduct validation testing to 
determine a site-specific emission factor within 6 months of PAL permit 
issuance, unless the reviewing authority determines that testing is not 
required.
    (vii) A source owner or operator must record and report maximum 
potential emissions without considering enforceable emission limitations 
or operational restrictions for an emissions unit during any period of 
time that there is no monitoring data, unless another method for 
determining emissions during such periods is specified in the PAL 
permit.
    (viii) Notwithstanding the requirements in paragraphs (f)(12)(iii) 
through (vii) of this section, where an owner or operator of an 
emissions unit cannot demonstrate a correlation between the monitored 
parameter(s) and the PAL pollutant emissions rate at all operating 
points of the emissions unit, the reviewing authority shall, at the time 
of permit issuance:
    (A) Establish default value(s) for determining compliance with the 
PAL based on the highest potential emissions reasonably estimated at 
such operating point(s); or
    (B) Determine that operation of the emissions unit during operating 
conditions when there is no correlation between monitored parameter(s) 
and the PAL pollutant emissions is a violation of the PAL.
    (ix) Re-validation. All data used to establish the PAL pollutant 
must be re-validated through performance testing or other scientifically 
valid means approved by the reviewing authority. Such testing must occur 
at least once every 5 years after issuance of the PAL.
    (13) Recordkeeping requirements. (i) The PAL permit shall require an 
owner or operator to retain a copy of all records necessary to determine 
compliance with any requirement of paragraph (f) of this section and of 
the PAL, including a determination of each

[[Page 223]]

emissions unit's 12-month rolling total emissions, for 5 years from the 
date of such record.
    (ii) The PAL permit shall require an owner or operator to retain a 
copy of the following records for the duration of the PAL effective 
period plus 5 years:
    (A) A copy of the PAL permit application and any applications for 
revisions to the PAL; and
    (B) Each annual certification of compliance pursuant to title V and 
the data relied on in certifying the compliance.
    (14) Reporting and notification requirements. The owner or operator 
shall submit semi-annual monitoring reports and prompt deviation reports 
to the reviewing authority in accordance with the applicable title V 
operating permit program. The reports shall meet the requirements in 
paragraphs (f)(14)(i) through (iii).
    (i) Semi-Annual Report. The semi-annual report shall be submitted to 
the reviewing authority within 30 days of the end of each reporting 
period. This report shall contain the information required in paragraphs 
(f)(14)(i)(A) through (G) of this section.
    (A) The identification of owner and operator and the permit number.
    (B) Total annual emissions (tons/year) based on a 12-month rolling 
total for each month in the reporting period recorded pursuant to 
paragraph (f)(13)(i) of this section.
    (C) All data relied upon, including, but not limited to, any Quality 
Assurance or Quality Control data, in calculating the monthly and annual 
PAL pollutant emissions.
    (D) A list of any emissions units modified or added to the major 
stationary source during the preceding 6-month period.
    (E) The number, duration, and cause of any deviations or monitoring 
malfunctions (other than the time associated with zero and span 
calibration checks), and any corrective action taken.
    (F) A notification of a shutdown of any monitoring system, whether 
the shutdown was permanent or temporary, the reason for the shutdown, 
the anticipated date that the monitoring system will be fully 
operational or replaced with another monitoring system, and whether the 
emissions unit monitored by the monitoring system continued to operate, 
and the calculation of the emissions of the pollutant or the number 
determined by method included in the permit, as provided by paragraph 
(f)(12)(vii) of this section.
    (G) A signed statement by the responsible official (as defined by 
the applicable title V operating permit program) certifying the truth, 
accuracy, and completeness of the information provided in the report.
    (ii) Deviation report. The major stationary source owner or operator 
shall promptly submit reports of any deviations or exceedance of the PAL 
requirements, including periods where no monitoring is available. A 
report submitted pursuant to Sec. 70.6(a)(3)(iii)(B) of this chapter 
shall satisfy this reporting requirement. The deviation reports shall be 
submitted within the time limits prescribed by the applicable program 
implementing Sec. 70.6(a)(3)(iii)(B) of this chapter. The reports shall 
contain the following information:
    (A) The identification of owner and operator and the permit number;
    (B) The PAL requirement that experienced the deviation or that was 
exceeded;
    (C) Emissions resulting from the deviation or the exceedance; and
    (D) A signed statement by the responsible official (as defined by 
the applicable title V operating permit program) certifying the truth, 
accuracy, and completeness of the information provided in the report.
    (iii) Re-validation results. The owner or operator shall submit to 
the reviewing authority the results of any re-validation test or method 
within 3 months after completion of such test or method.
    (15) Transition requirements. (i) No reviewing authority may issue a 
PAL that does not comply with the requirements in paragraphs (f)(1) 
through (15) of this section after the Administrator has approved 
regulations incorporating these requirements into a plan.
    (ii) The reviewing authority may supersede any PAL which was 
established prior to the date of approval of the plan by the 
Administrator with a PAL

[[Page 224]]

that complies with the requirements of paragraphs (f)(1) through (15) of 
this section.
    (g) If any provision of this section, or the application of such 
provision to any person or circumstance, is held invalid, the remainder 
of this section, or the application of such provision to persons or 
circumstances other than those as to which it is held invalid, shall not 
be affected thereby.
    (h) Equipment replacement provision. Without regard to other 
considerations, routine maintenance, repair and replacement includes, 
but is not limited to, the replacement of any component of a process 
unit with an identical or functionally equivalent component(s), and 
maintenance and repair activities that are part of the replacement 
activity, provided that all of the requirements in paragraphs (h)(1) 
through (3) of this section are met.
    (1) Capital Cost threshold for Equipment Replacement. (i) For an 
electric utility steam generating unit, as defined in Sec. 
51.165(a)(1)(xx), the fixed capital cost of the replacement component(s) 
plus the cost of any associated maintenance and repair activities that 
are part of the replacement shall not exceed 20 percent of the 
replacement value of the process unit, at the time the equipment is 
replaced. For a process unit that is not an electric utility steam 
generating unit the fixed capital cost of the replacement component(s) 
plus the cost of any associated maintenance and repair activities that 
are part of the replacement shall not exceed 20 percent of the 
replacement value of the process unit, at the time the equipment is 
replaced.
    (ii) In determining the replacement value of the process unit; and, 
except as otherwise allowed under paragraph (h)(1)(iii) of this section, 
the owner or operator shall determine the replacement value of the 
process unit on an estimate of the fixed capital cost of constructing a 
new process unit, or on the current appraised value of the process unit.
    (iii) As an alternative to paragraph (h)(1)(ii) of this section for 
determining the replacement value of a process unit, an owner or 
operator may choose to use insurance value (where the insurance value 
covers only complete replacement), investment value adjusted for 
inflation, or another accounting procedure if such procedure is based on 
Generally Accepted Accounting Principles, provided that the owner or 
operator sends a notice to the reviewing authority. The first time that 
an owner or operator submits such a notice for a particular process 
unit, the notice may be submitted at any time, but any subsequent notice 
for that process unit may be submitted only at the beginning of the 
process unit's fiscal year. Unless the owner or operator submits a 
notice to the reviewing authority, then paragraph (h)(1)(ii) of this 
section will be used to establish the replacement value of the process 
unit. Once the owner or operator submits a notice to use an alternative 
accounting procedure, the owner or operator must continue to use that 
procedure for the entire fiscal year for that process unit. In 
subsequent fiscal years, the owner or operator must continue to use this 
selected procedure unless and until the owner or operator sends another 
notice to the reviewing authority selecting another procedure consistent 
with this paragraph or paragraph (h)(1)(ii) of this section at the 
beginning of such fiscal year.
    (2) Basic design parameters. The replacement does not change the 
basic design parameter(s) of the process unit to which the activity 
pertains.
    Note to paragraph (h): By a court order on December 24, 2003, this 
paragraph (h) is stayed indefinitely. The stayed provisions will become 
effective immediately if the court terminates the stay. At that time, 
EPA will publish a document in the Federal Register advising the public 
of the termination of the stay.
    (i) Except as provided in paragraph (h)(2)(iii) of this section, for 
a process unit at a steam electric generating facility, the owner or 
operator may select as its basic design parameters either maximum hourly 
heat input and maximum hourly fuel consumption rate or maximum hourly 
electric output rate and maximum steam flow rate. When establishing fuel 
consumption specifications in terms of weight or volume, the minimum 
fuel quality based on British Thermal Units content shall be used for 
determining the basic design parameter(s) for a coal-

[[Page 225]]

fired electric utility steam generating unit.
    (ii) Except as provided in paragraph (h)(2)(iii) of this section, 
the basic design parameter(s) for any process unit that is not at a 
steam electric generating facility are maximum rate of fuel or heat 
input, maximum rate of material input, or maximum rate of product 
output. Combustion process units will typically use maximum rate of fuel 
input. For sources having multiple end products and raw materials, the 
owner or operator should consider the primary product or primary raw 
material when selecting a basic design parameter.
    (iii) If the owner or operator believes the basic design 
parameter(s) in paragraphs (h)(2)(i) and (ii) of this section is not 
appropriate for a specific industry or type of process unit, the owner 
or operator may propose to the reviewing authority an alternative basic 
design parameter(s) for the source's process unit(s). If the reviewing 
authority approves of the use of an alternative basic design 
parameter(s), the reviewing authority shall issue a permit that is 
legally enforceable that records such basic design parameter(s) and 
requires the owner or operator to comply with such parameter(s).
    (iv) The owner or operator shall use credible information, such as 
results of historic maximum capability tests, design information from 
the manufacturer, or engineering calculations, in establishing the 
magnitude of the basic design parameter(s) specified in paragraphs 
(h)(2)(i) and (ii) of this section.
    (v) If design information is not available for a process unit, then 
the owner or operator shall determine the process unit's basic design 
parameter(s) using the maximum value achieved by the process unit in the 
five-year period immediately preceding the planned activity.
    (vi) Efficiency of a process unit is not a basic design parameter.
    (3) The replacement activity shall not cause the process unit to 
exceed any emission limitation, or operational limitation that has the 
effect of constraining emissions, that applies to the process unit and 
that is legally enforceable.

[51 FR 40669, Nov. 7, 1986, as amended at 52 FR 24713, July 1, 1987; 52 
FR 29386, Aug 7, 1987; 54 FR 27285, 27299 June 28, 1989; 57 FR 3946, 
Feb. 3, 1992; 57 FR 32334, July 21, 1992; 67 FR 80244, Dec. 31, 2002; 68 
FR 61276, Oct. 27, 2003; 68 FR 63027, Nov. 7, 2003; 69 FR 40275, July 1, 
2004; 70 FR 71698, Nov. 29, 2005]



Sec. 51.166  Prevention of significant deterioration of air quality.

    (a)(1) Plan requirements. In accordance with the policy of section 
101(b)(1) of the Act and the purposes of section 160 of the Act, each 
applicable State Implementation Plan and each applicable Tribal 
Implementation Plan shall contain emission limitations and such other 
measures as may be necessary to prevent significant deterioration of air 
quality.
    (2) Plan revisions. If a State Implementation Plan revision would 
result in increased air quality deterioration over any baseline 
concentration, the plan revision shall include a demonstration that it 
will not cause or contribute to a violation of the applicable 
increment(s). If a plan revision proposing less restrictive requirements 
was submitted after August 7, 1977 but on or before any applicable 
baseline date and was pending action by the Administrator on that date, 
no such demonstration is necessary with respect to the area for which a 
baseline date would be established before final action is taken on the 
plan revision. Instead, the assessment described in paragraph (a)(4) of 
this section, shall review the expected impact to the applicable 
increment(s).
    (3) Required plan revision. If the State or the Administrator 
determines that a plan is substantially inadequate to prevent 
significant deterioration or that an applicable increment is being 
violated, the plan shall be revised to correct the inadequacy or the 
violation. The plan shall be revised within 60 days of such a finding by 
a State or within 60 days following notification by the Administrator, 
or by such later date as prescribed by the Administrator after 
consultation with the State.
    (4) Plan assessment. The State shall review the adequacy of a plan 
on a periodic basis and within 60 days of

[[Page 226]]

such time as information becomes available that an applicable increment 
is being violated.
    (5) Public participation. Any State action taken under this 
paragraph shall be subject to the opportunity for public hearing in 
accordance with procedures equivalent to those established in Sec. 
51.102.
    (6) Amendments. (i) Any State required to revise its implementation 
plan by reason of an amendment to this section, including any amendment 
adopted simultaneously with this paragraph (a)(6)(i), shall adopt and 
submit such plan revision to the Administrator for approval no later 
than three years after such amendment is published in the Federal 
Register.
    (ii) Any revision to an implementation plan that would amend the 
provisions for the prevention of significant air quality deterioration 
in the plan shall specify when and as to what sources and modifications 
the revision is to take effect.
    (iii) Any revision to an implementation plan that an amendment to 
this section required shall take effect no later than the date of its 
approval and may operate prospectively.
    (7) Applicability. Each plan shall contain procedures that 
incorporate the requirements in paragraphs (a)(7)(i) through (vi) of 
this section.
    (i) The requirements of this section apply to the construction of 
any new major stationary source (as defined in paragraph (b)(1) of this 
section) or any project at an existing major stationary source in an 
area designated as attainment or unclassifiable under sections 
107(d)(1)(A)(ii) or (iii) of the Act.
    (ii) The requirements of paragraphs (j) through (r) of this section 
apply to the construction of any new major stationary source or the 
major modification of any existing major stationary source, except as 
this section otherwise provides.
    (iii) No new major stationary source or major modification to which 
the requirements of paragraphs (j) through (r)(5) of this section apply 
shall begin actual construction without a permit that states that the 
major stationary source or major modification will meet those 
requirements.
    (iv) Each plan shall use the specific provisions of paragraphs 
(a)(7)(iv)(a) through (f) of this section. Deviations from these 
provisions will be approved only if the State specifically demonstrates 
that the submitted provisions are more stringent than or at least as 
stringent in all respects as the corresponding provisions in paragraphs 
(a)(7)(iv)(a) through (f) of this section.
    (a) Except as otherwise provided in paragraphs (a)(7)(v) and (vi) of 
this section, and consistent with the definition of major modification 
contained in paragraph (b)(2) of this section, a project is a major 
modification for a regulated NSR pollutant if it causes two types of 
emissions increases--a significant emissions increase (as defined in 
paragraph (b)(39) of this section), and a significant net emissions 
increase (as defined in paragraphs (b)(3) and (b)(23) of this section). 
The project is not a major modification if it does not cause a 
significant emissions increase. If the project causes a significant 
emissions increase, then the project is a major modification only if it 
also results in a significant net emissions increase.
    (b) The procedure for calculating (before beginning actual 
construction) whether a significant emissions increase (i.e., the first 
step of the process) will occur depends upon the type of emissions units 
being modified, according to paragraphs (a)(7)(iv)(c) through (f) of 
this section. The procedure for calculating (before beginning actual 
construction) whether a significant net emissions increase will occur at 
the major stationary source (i.e., the second step of the process) is 
contained in the definition in paragraph (b)(3) of this section. 
Regardless of any such preconstruction projections, a major modification 
results if the project causes a significant emissions increase and a 
significant net emissions increase.
    (c) Actual-to-projected-actual applicability test for projects that 
only involve existing emissions units. A significant emissions increase 
of a regulated NSR pollutant is projected to occur if the sum of the 
difference between the projected actual emissions (as defined in 
paragraph (b)(40) of this section) and

[[Page 227]]

the baseline actual emissions (as defined in paragraphs (b)(47)(i) and 
(ii) of this section) for each existing emissions unit, equals or 
exceeds the significant amount for that pollutant (as defined in 
paragraph (b)(23) of this section).
    (d) Actual-to-potential test for projects that only involve 
construction of a new emissions unit(s). A significant emissions 
increase of a regulated NSR pollutant is projected to occur if the sum 
of the difference between the potential to emit (as defined in paragraph 
(b)(4) of this section) from each new emissions unit following 
completion of the project and the baseline actual emissions (as defined 
in paragraph (b)(47)(iii) of this section) of these units before the 
project equals or exceeds the significant amount for that pollutant (as 
defined in paragraph (b)(23) of this section).
    (e) Emission test for projects that involve Clean Units. For a 
project that will be constructed and operated at a Clean Unit without 
causing the emissions unit to lose its Clean Unit designation, no 
emissions increase is deemed to occur.
    (f) Hybrid test for projects that involve multiple types of 
emissions units. A significant emissions increase of a regulated NSR 
pollutant is projected to occur if the sum of the emissions increases 
for each emissions unit, using the method specified in paragraphs 
(a)(7)(iv)(c) through (e) of this section as applicable with respect to 
each emissions unit, for each type of emissions unit equals or exceeds 
the significant amount for that pollutant (as defined in paragraph 
(b)(23) of this section). For example, if a project involves both an 
existing emissions unit and a Clean Unit, the projected increase is 
determined by summing the values determined using the method specified 
in paragraph (a)(7)(iv)(c) of this section for the existing unit and 
determined using the method specified in paragraph (a)(7)(iv)(e) of this 
section for the Clean Unit.
    (v) The plan shall require that for any major stationary source for 
a PAL for a regulated NSR pollutant, the major stationary source shall 
comply with requirements under paragraph (w) of this section.
    (vi) The plan shall require that an owner or operator undertaking a 
PCP (as defined in paragraph (b)(31) of this section) shall comply with 
the requirements under paragraph (v) of this section.
    (b) Definitions. All State plans shall use the following definitions 
for the purposes of this section. Deviations from the following wording 
will be approved only if the State specifically demonstrates that the 
submitted definition is more stringent, or at least as stringent, in all 
respects as the corresponding definitions below:
    (1)(i) Major stationary source means:
    (a) Any of the following stationary sources of air pollutants which 
emits, or has the potential to emit, 100 tons per year or more of any a 
regulated NSR pollutant: Fossil fuel-fired steam electric plants of more 
than 250 million British thermal units per hour heat input, coal 
cleaning plants (with thermal dryers), kraft pulp mills, portland cement 
plants, primary zinc smelters, iron and steel mill plants, primary 
aluminum ore reduction plants, primary copper smelters, municipal 
incinerators capable of charging more than 250 tons of refuse per day, 
hydrofluoric, sulfuric, and nitric acid plants, petroleum refineries, 
lime plants, phosphate rock processing plants, coke oven batteries, 
sulfur recovery plants, carbon black plants (furnace process), primary 
lead smelters, fuel conversion plants, sintering plants, secondary metal 
production plants, chemical process plants, fossil fuel boilers (or 
combinations thereof) totaling more than 250 million British thermal 
units per hour heat input, petroleum storage and transfer units with a 
total storage capacity exceeding 300,000 barrels, taconite ore 
processing plants, glass fiber processing plants, and charcoal 
production plants;
    (b) Notwithstanding the stationary source size specified in 
paragraph (b)(1)(i)(a) of this section, any stationary source which 
emits, or has the potential to emit, 250 tons per year or more of a 
regulated NSR pollutant; or
    (c) Any physical change that would occur at a stationary source not 
otherwise qualifying under paragraph (b)(1) of this section, as a major 
stationary

[[Page 228]]

source if the change would constitute a major stationary source by 
itself.
    (ii) A major source that is major for volatile organic compounds or 
NOX shall be considered major for ozone.
    (iii) The fugitive emissions of a stationary source shall not be 
included in determining for any of the purposes of this section whether 
it is a major stationary source, unless the source belongs to one of the 
following categories of stationary sources:
    (a) Coal cleaning plants (with thermal dryers);
    (b) Kraft pulp mills;
    (c) Portland cement plants;
    (d) Primary zinc smelters;
    (e) Iron and steel mills;
    (f) Primary aluminum ore reduction plants;
    (g) Primary copper smelters;
    (h) Municipal incinerators capable of charging more than 250 tons of 
refuse per day;
    (i) Hydrofluoric, sulfuric, or nitric acid plants;
    (j) Petroleum refineries;
    (k) Lime plants;
    (l) Phosphate rock processing plants;
    (m) Coke oven batteries;
    (n) Sulfur recovery plants;
    (o) Carbon black plants (furnace process);
    (p) Primary lead smelters;
    (q) Fuel conversion plants;
    (r) Sintering plants;
    (s) Secondary metal production plants;
    (t) Chemical process plants;
    (u) Fossil-fuel boilers (or combination thereof) totaling more than 
250 million British thermal units per hour heat input;
    (v) Petroleum storage and transfer units with a total storage 
capacity exceeding 300,000 barrels;
    (w) Taconite ore processing plants;
    (x) Glass fiber processing plants;
    (y) Charcoal production plants;
    (z) Fossil fuel-fired steam electric plants of more that 250 million 
British thermal units per hour heat input;
    (aa) Any other stationary source category which, as of August 7, 
1980, is being regulated under section 111 or 112 of the Act.
    (2)(i) Major modification means any physical change in or change in 
the method of operation of a major stationary source that would result 
in: a significant emissions increase (as defined in paragraph (b)(39) of 
this section) of a regulated NSR pollutant (as defined in paragraph 
(b)(49) of this section); and a significant net emissions increase of 
that pollutant from the major stationary source.
    (ii) Any significant emissions increase (as defined at paragraph 
(b)(39) of this section) from any emissions units or net emissions 
increase (as defined in paragraph (b)(3) of this section) at a major 
stationary source that is significant for volatile organic compounds or 
NOX shall be considered significant for ozone.
    (iii) A physical change or change in the method of operation shall 
not include:
    (a) Routine maintenance, repair and replacement. Routine 
maintenance, repair and replacement shall include, but not be limited 
to, any activity(s) that meets the requirements of the equipment 
replacement provisions contained in paragraph (y) of this section;
    Note to paragraph (b)(2)(iii)(a): On December 24, 2003, the second 
sentence of this paragraph (b)(2)(iii)(a) is stayed indefinitely by 
court order. The stayed provisions will become effective immediately if 
the court terminates the stay. At that time, EPA will publish a document 
in the Federal Register advising the public of the termination of the 
stay.
    (b) Use of an alternative fuel or raw material by reason of any 
order under section 2 (a) and (b) of the Energy Supply and Environmental 
Coordination Act of 1974 (or any superseding legislation) or by reason 
of a natural gas curtailment plan pursuant to the Federal Power Act;
    (c) Use of an alternative fuel by reason of an order or rule under 
section 125 of the Act;
    (d) Use of an alternative fuel at a steam generating unit to the 
extent that the fuel is generated from municipal solid waste;
    (e) Use of an alternative fuel or raw material by a stationary 
source which:
    (1) The source was capable of accommodating before January 6, 1975, 
unless such change would be prohibited under any federally enforceable 
permit condition which was established after January 6, 1975 pursuant to 
40 CFR 52.21 or

[[Page 229]]

under regulations approved pursuant to 40 CFR subpart I or Sec. 51.166; 
or
    (2) The source is approved to use under any permit issued under 40 
CFR 52.21 or under regulations approved pursuant to 40 CFR 51.166;
    (f) An increase in the hours of operation or in the production rate, 
unless such change would be prohibited under any federally enforceable 
permit condition which was established after January 6, 1975, pursuant 
to 40 CFR 52.21 or under regulations approved pursuant to 40 CFR subpart 
I or Sec. 51.166.
    (g) Any change in ownership at a stationary source.
    (h) The addition, replacement, or use of a PCP, as defined in 
paragraph (b)(31) of this section, at an existing emissions unit meeting 
the requirements of paragraph (v) of this section. A replacement control 
technology must provide more effective emission control than that of the 
replaced control technology to qualify for this exclusion.
    (i) The installation, operation, cessation, or removal of a 
temporary clean coal technology demonstration project, provided that the 
project complies with:
    (1) The State implementation plan for the State in which the project 
is located; and
    (2) Other requirements necessary to attain and maintain the national 
ambient air quality standards during the project and after it is 
terminated.
    (j) The installation or operation of a permanent clean coal 
technology demonstration project that constitutes repowering, provided 
that the project does not result in an increase in the potential to emit 
of any regulated pollutant emitted by the unit. This exemption shall 
apply on a pollutant-by-pollutant basis.
    (k) The reactivation of a very clean coal-fired electric utility 
steam generating unit.
    (iv) This definition shall not apply with respect to a particular 
regulated NSR pollutant when the major stationary source is complying 
with the requirements under paragraph (w) of this section for a PAL for 
that pollutant. Instead, the definition at paragraph (w)(2)(viii) of 
this section shall apply.
    (3)(i) Net emissions increase means, with respect to any regulated 
NSR pollutant emitted by a major stationary source, the amount by which 
the sum of the following exceeds zero:
    (a) The increase in emissions from a particular physical change or 
change in the method of operation at a stationary source as calculated 
pursuant to paragraph (a)(7)(iv) of this section; and
    (b) Any other increases and decreases in actual emissions at the 
major stationary source that are contemporaneous with the particular 
change and are otherwise creditable. Baseline actual emissions for 
calculating increases and decreases under this paragraph (b)(3)(i)(b) 
shall be determined as provided in paragraph (b)(47), except that 
paragraphs (b)(47)(i)(c) and (b)(47)(ii)(d) of this section shall not 
apply.
    (ii) An increase or decrease in actual emissions is contemporaneous 
with the increase from the particular change only if it occurs within a 
reasonable period (to be specified by the State) before the date that 
the increase from the particular change occurs.
    (iii) An increase or decrease in actual emissions is creditable only 
if:
    (a) It occurs within a reasonable period (to be specified by the 
reviewing authority); and
    (b) The reviewing authority has not relied on it in issuing a permit 
for the source under regulations approved pursuant to this section, 
which permit is in effect when the increase in actual emissions from the 
particular change occurs; and
    (c) The increase or decrease in emissions did not occur at a Clean 
Unit, except as provided in paragraphs (t)(8) and (u)(10) of this 
section.
    (iv) An increase or decrease in actual emissions of sulfur dioxide, 
particulate matter, or nitrogen oxides that occurs before the applicable 
minor source baseline date is creditable only if it is required to be 
considered in calculating the amount of maximum allowable increases 
remaining available.
    (v) An increase in actual emissions is creditable only to the extent 
that the new level of actual emissions exceeds the old level.

[[Page 230]]

    (vi) A decrease in actual emissions is creditable only to the extent 
that:
    (a) The old level of actual emissions or the old level of allowable 
emissions, whichever is lower, exceeds the new level of actual 
emissions;
    (b) It is enforceable as a practical matter at and after the time 
that actual construction on the particular change begins;
    (c) It has approximately the same qualitative significance for 
public health and welfare as that attributed to the increase from the 
particular change; and
    (d) The decrease in actual emissions did not result from the 
installation of add-on control technology or application of pollution 
prevention practices that were relied on in designating an emissions 
unit as a Clean Unit under Sec. 52.21(y) or under regulations approved 
pursuant to paragraph (u) of this section or Sec. 51.165(d). That is, 
once an emissions unit has been designated as a Clean Unit, the owner or 
operator cannot later use the emissions reduction from the air pollution 
control measures that the Clean Unit designation is based on in 
calculating the net emissions increase for another emissions unit (i.e., 
must not use that reduction in a ``netting analysis'' for another 
emissions unit). However, any new emissions reductions that were not 
relied upon in a PCP excluded pursuant to paragraph (v) of this section 
or for the Clean Unit designation are creditable to the extent they meet 
the requirements in paragraph (v)(6)(iv) of this section for the PCP and 
paragraph (t)(8) or (u)(10) of this section for a Clean Unit.
    (vii) An increase that results from a physical change at a source 
occurs when the emissions unit on which construction occurred becomes 
operational and begins to emit a particular pollutant. Any replacement 
unit that requires shakedown becomes operational only after a reasonable 
shakedown period, not to exceed 180 days.
    (viii) Paragraph (b)(21)(ii) of this section shall not apply for 
determining creditable increases and decreases.
    (4) Potential to emit means the maximum capacity of a stationary 
source to emit a pollutant under its physical and operational design. 
Any physical or operational limitation on the capacity of the source to 
emit a pollutant, including air pollution control equipment and 
restrictions on hours of operation or on the type or amount of material 
combusted, stored, or processed, shall be treated as part of its design 
if the limitation or the effect it would have on emissions is federally 
enforceable. Secondary emissions do not count in determining the 
potential to emit of a stationary source.
    (5) Stationary source means any building, structure, facility, or 
installation which emits or may emit a regulated NSR pollutant.
    (6) Building, structure, facility, or installation means all of the 
pollutant-emitting activities which belong to the same industrial 
grouping, are located on one or more contiguous or adjacent properties, 
and are under the control of the same person (or persons under common 
control) except the activities of any vessel. Pollutant-emitting 
activities shall be considered as part of the same industrial grouping 
if they belong to the same Major Group (i.e., which have the same two-
digit code) as described in the Standard Industrial Classification 
Manual, 1972, as amended by the 1977 Supplement (U.S. Government 
Printing Office stock numbers 4101-0066 and 003-005-00176-0, 
respectively).
    (7) Emissions unit means any part of a stationary source that emits 
or would have the potential to emit any regulated NSR pollutant and 
includes an electric utility steam generating unit as defined in 
paragraph (b)(30) of this section. For purposes of this section, there 
are two types of emissions units as described in paragraphs (b)(7)(i) 
and (ii) of this section.
    (i) A new emissions unit is any emissions unit that is (or will be) 
newly constructed and that has existed for less than 2 years from the 
date such emissions unit first operated.
    (ii) An existing emissions unit is any emissions unit that does not 
meet the requirements in paragraph (b)(7)(i) of this section. A 
replacement unit, as defined in paragraph (b)(32) of this section, is an 
existing emissions unit.

[[Page 231]]

    (8) Construction means any physical change or change in the method 
of operation (including fabrication, erection, installation, demolition, 
or modification of an emissions unit) that would result in a change in 
emissions.
    (9) Commence as applied to construction of a major stationary source 
or major modification means that the owner or operator has all necessary 
preconstruction approvals or permits and either has:
    (i) Begun, or caused to begin, a continuous program of actual on-
site construction of the source, to be completed within a reasonable 
time; or
    (ii) Entered into binding agreements or contractual obligations, 
which cannot be cancelled or modified without substantial loss to the 
owner or operator, to undertake a program of actual construction of the 
source to be completed within a reasonable time.
    (10) Necessary preconstruction approvals or permits means those 
permits or approvals required under Federal air quality control laws and 
regulations and those air quality control laws and regulations which are 
part of the applicable State Implementation Plan.
    (11) Begin actual construction means, in general, initiation of 
physical on-site construction activities on an emissions unit which are 
of a permanent nature. Such activities include, but are not limited to, 
installation of building supports and foundations, laying of underground 
pipework, and construction of permanent storage structures. With respect 
to a change in method of operation this term refers to those on-site 
activities, other than preparatory activities, which mark the initiation 
of the change.
    (12) Best available control technology means an emissions limitation 
(including a visible emissions standard) based on the maximum degree of 
reduction for each a regulated NSR pollutant which would be emitted from 
any proposed major stationary source or major modification which the 
reviewing authority, on a case-by-case basis, taking into account 
energy, environmental, and economic impacts and other costs, determines 
is achievable for such source or modification through application of 
production processes or available methods, systems, and techniques, 
including fuel cleaning or treatment or innovative fuel combination 
techniques for control of such pollutant. In no event shall application 
of best available control technology result in emissions of any 
pollutant which would exceed the emissions allowed by any applicable 
standard under 40 CFR parts 60 and 61. If the reviewing authority 
determines that technological or economic limitations on the application 
of measurement methodology to a particular emissions unit would make the 
imposition of an emissions standard infeasible, a design, equipment, 
work practice, operational standard or combination thereof, may be 
prescribed instead to satisfy the requirement for the application of 
best available control technology. Such standard shall, to the degree 
possible, set forth the emissions reduction achievable by implementation 
of such design, equipment, work practice or operation, and shall provide 
for compliance by means which achieve equivalent results.
    (13)(i) Baseline concentration means that ambient concentration 
level that exists in the baseline area at the time of the applicable 
minor source baseline date. A baseline concentration is determined for 
each pollutant for which a minor source baseline date is established and 
shall include:
    (a) The actual emissions, as defined in paragraph (b)(21) of this 
section, representative of sources in existence on the applicable minor 
source baseline date, except as provided in paragraph (b)(13)(ii) of 
this section;
    (b) The allowable emissions of major stationary sources that 
commenced construction before the major source baseline date, but were 
not in operation by the applicable minor source baseline date.
    (ii) The following will not be included in the baseline 
concentration and will affect the applicable maximum allowable 
increase(s):
    (a) Actual emissions, as defined in paragraph (b)(21) of this 
section, from any major stationary source on which construction 
commenced after the major source baseline date; and
    (b) Actual emissions increases and decreases, as defined in 
paragraph

[[Page 232]]

(b)(21) of this section, at any stationary source occurring after the 
minor source baseline date.
    (14)(i) Major source baseline date means:
    (a) In the case of particulate matter and sulfur dioxide, January 6, 
1975, and
    (b) In the case of nitrogen dioxide, February 8, 1988.
    (ii) Minor source baseline date means the earliest date after the 
trigger date on which a major stationary source or a major modification 
subject to 40 CFR 52.21 or to regulations approved pursuant to 40 CFR 
51.166 submits a complete application under the relevant regulations. 
The trigger date is:
    (a) In the case of particulate matter and sulfur dioxide, August 7, 
1977, and
    (b) In the case of nitrogen dioxide, February 8, 1988.
    (iii) The baseline date is established for each pollutant for which 
increments or other equivalent measures have been established if:
    (a) The area in which the proposed source or modification would 
construct is designated as attainment or unclassifiable under section 
107(d)(i) (D) or (E) of the Act for the pollutant on the date of its 
complete application under 40 CFR 52.21 or under regulations approved 
pursuant to 40 CFR 51.166; and
    (b) In the case of a major stationary source, the pollutant would be 
emitted in significant amounts, or, in the case of a major modification, 
there would be a significant net emissions increase of the pollutant.
    (iv) Any minor source baseline date established originally for the 
TSP increments shall remain in effect and shall apply for purposes of 
determining the amount of available PM-10 increments, except that the 
reviewing authority may rescind any such minor source baseline date 
where it can be shown, to the satisfaction of the reviewing authority, 
that the emissions increase from the major stationary source, or the net 
emissions increase from the major modification, responsible for 
triggering that date did not result in a significant amount of PM-10 
emissions.
    (15)(i) Baseline area means any intrastate area (and every part 
thereof) designated as attainment or unclassifiable under section 
107(d)(1) (D) or (E) of the Act in which the major source or major 
modification establishing the minor source baseline date would construct 
or would have an air quality impact equal to or greater than 1 [micro]g/
m\3\ (annual average) of the pollutant for which the minor source 
baseline date is established.
    (ii) Area redesignations under section 107(d)(1) (D) or (E) of the 
Act cannot intersect or be smaller than the area of impact of any major 
stationary source or major modification which:
    (a) Establishes a minor source baseline date; or
    (b) Is subject to 40 CFR 52.21 or under regulations approved 
pursuant to 40 CFR 51.166, and would be constructed in the same State as 
the State proposing the redesignation.
    (iii) Any baseline area established originally for the TSP 
increments shall remain in effect and shall apply for purposes of 
determining the amount of available PM-10 increments, except that such 
baseline area shall not remain in effect if the permit authority 
rescinds the corresponding minor source baseline date in accordance with 
paragraph (b)(14)(iv) of this section.
    (16) Allowable emissions means the emissions rate of a stationary 
source calculated using the maximum rated capacity of the source (unless 
the source is subject to federally enforceable limits which restrict the 
operating rate, or hours of operation, or both) and the most stringent 
of the following:
    (i) The applicable standards as set forth in 40 CFR parts 60 and 61;
    (ii) The applicable State Implementation Plan emissions limitation, 
including those with a future compliance date; or
    (iii) The emissions rate specified as a federally enforceable permit 
condition.
    (17) Federally enforceable means all limitations and conditions 
which are enforceable by the Administrator, including those requirements 
developed pursuant to 40 CFR parts 60 and 61, requirements within any 
applicable State implementation plan, any permit requirements 
established pursuant to 40 CFR 52.21 or under regulations approved 
pursuant to 40 CFR part 51, subpart I, including operating permits 
issued under an EPA-approved program

[[Page 233]]

that is incorporated into the State implementation plan and expressly 
requires adherence to any permit issued under such program.
    (18) Secondary emissions means emissions which occur as a result of 
the construction or operation of a major stationary source or major 
modification, but do not come from the major stationary source or major 
modification itself. For the purposes of this section, secondary 
emissions must be specific, well defined, quantifiable, and impact the 
same general areas the stationary source modification which causes the 
secondary emissions. Secondary emissions include emissions from any 
offsite support facility which would not be constructed or increase its 
emissions except as a result of the construction or operation of the 
major stationary source or major modification. Secondary emissions do 
not include any emissions which come directly from a mobile source, such 
as emissions from the tailpipe of a motor vehicle, from a train, or from 
a vessel.
    (19) Innovative control technology means any system of air pollution 
control that has not been adequately demonstrated in practice, but would 
have a substantial likelihood of achieving greater continuous emissions 
reduction than any control system in current practice or of achieving at 
least comparable reductions at lower cost in terms of energy, economics, 
or nonair quality environmental impacts.
    (20) Fugitive emissions means those emissions which could not 
reasonably pass through a stack, chimney, vent, or other functionally 
equivalent opening.
    (21)(i) Actual emissions means the actual rate of emissions of a 
regulated NSR pollutant from an emissions unit, as determined in 
accordance with paragraphs (b)(21)(ii) through (iv) of this section, 
except that this definition shall not apply for calculating whether a 
significant emissions increase has occurred, or for establishing a PAL 
under paragraph (w) of this section. Instead, paragraphs (b)(40) and 
(b)(47) of this section shall apply for those purposes.
    (ii) In general, actual emissions as of a particular date shall 
equal the average rate, in tons per year, at which the unit actually 
emitted the pollutant during a consecutive 24-month period which 
precedes the particular date and which is representative of normal 
source operation. The reviewing authority shall allow the use of a 
different time period upon a determination that it is more 
representative of normal source operation. Actual emissions shall be 
calculated using the unit's actual operating hours, production rates, 
and types of materials processed, stored, or combusted during the 
selected time period.
    (iii) The reviewing authority may presume that source-specific 
allowable emissions for the unit are equivalent to the actual emissions 
of the unit.
    (iv) For any emissions unit that has not begun normal operations on 
the particular date, actual emissions shall equal the potential to emit 
of the unit on that date.
    (22) Complete means, in reference to an application for a permit, 
that the application contains all the information necessary for 
processing the application. Designating an application complete for 
purposes of permit processing does not preclude the reviewing authority 
from requesting or accepting any additional information.
    (23)(i) Significant means, in reference to a net emissions increase 
or the potential of a source to emit any of the following pollutants, a 
rate of emissions that would equal or exceed any of the following rates:

                      Pollutant and Emissions Rate

Carbon monoxide: 100 tons per year (tpy)
Nitrogen oxides: 40 tpy
Sulfur dioxide: 40 tpy
Particulate matter: 25 tpy of particulate matter emissions. 15 tpy of 
PM10 emissions.
Ozone: 40 tpy of volatile organic compounds or NOX
Lead: 0.6 tpy
Fluorides: 3 tpy
Sulfuric acid mist: 7 tpy
Hydrogen sulfide (H2 S): 10 tpy
Total reduced sulfur (including H2 S): 10 tpy
Reduced sulfur compounds (including H2 S): 10 tpy
Municipal waste combustor organics (measured as total tetra- through 
octa-chlorinated dibenzo-p-dioxins and dibenzofurans): 3.2 x 
10-6 megagrams per year (3.5 x 10-6 tons per year)
Municipal waste combustor metals (measured as articulate matter): 14 
megagrams per year (15 tons per year) Municipal waste combustor acid 
gases (measured as sulfur

[[Page 234]]

dioxide and hydrogen chloride): 36 megagrams per year (40 tons per year)
Municipal solid waste landfill emissions (measured as nonmethane organic 
compounds): 45 megagrams per year (50 tons per year)

    (ii) Significant means, in reference to a net emissions increase or 
the potential of a source to emit a regulated NSR pollutant that 
paragraph (b)(23)(i) of this section, does not list, any emissions rate.
    (iii) Notwithstanding paragraph (b)(23)(i) of this section, 
significant means any emissions rate or any net emissions increase 
associated with a major stationary source or major modification, which 
would construct within 10 kilometers of a Class I area, and have an 
impact on such area equal to or greater than 1 [micro]g/m\3\ (24-hour 
average).
    (24) Federal Land Manager means, with respect to any lands in the 
United States, the Secretary of the department with authority over such 
lands.
    (25) High terrain means any area having an elevation 900 feet or 
more above the base of the stack of a source.
    (26) Low terrain means any area other than high terrain.
    (27) Indian Reservation means any federally recognized reservation 
established by Treaty, Agreement, Executive Order, or Act of Congress.
    (28) Indian Governing Body means the governing body of any tribe, 
band, or group of Indians subject to the jurisdiction of the United 
States and recognized by the United States as possessing power of self-
government.
    (29) Volatile organic compounds (VOC) is as defined in Sec. 
51.100(s) of this part.
    (30) Electric utility steam generating unit means any steam electric 
generating unit that is constructed for the purpose of supplying more 
than one-third of its potential electric output capacity and more than 
25 MW electrical output to any utility power distribution system for 
sale. Any steam supplied to a steam distribution system for the purpose 
of providing steam to a steam-electric generator that would produce 
electrical energy for sale is also considered in determining the 
electrical energy output capacity of the affected facility.
    (31) Pollution control project (PCP) means any activity, set of work 
practices or project (including pollution prevention as defined under 
paragraph (b)(38) of this section) undertaken at an existing emissions 
unit that reduces emissions of air pollutants from such unit. Such 
qualifying activities or projects can include the replacement or upgrade 
of an existing emissions control technology with a more effective unit. 
Other changes that may occur at the source are not considered part of 
the PCP if they are not necessary to reduce emissions through the PCP. 
Projects listed in paragraphs (b)(31)(i) through (vi) of this section 
are presumed to be environmentally beneficial pursuant to paragraph 
(v)(2)(i) of this section. Projects not listed in these paragraphs may 
qualify for a case-specific PCP exclusion pursuant to the requirements 
of paragraphs (v)(2) and (v)(5) of this section.
    (i) Conventional or advanced flue gas desulfurization or sorbent 
injection for control of SO2.
    (ii) Electrostatic precipitators, baghouses, high efficiency 
multiclones, or scrubbers for control of particulate matter or other 
pollutants.
    (iii) Flue gas recirculation, low-NOX burners or 
combustors, selective non-catalytic reduction, selective catalytic 
reduction, low emission combustion (for IC engines), and oxidation/
absorption catalyst for control of NOX.
    (iv) Regenerative thermal oxidizers, catalytic oxidizers, 
condensers, thermal incinerators, hydrocarbon combustion flares, 
biofiltration, absorbers and adsorbers, and floating roofs for storage 
vessels for control of volatile organic compounds or hazardous air 
pollutants. For the purpose of this section, ``hydrocarbon combustion 
flare'' means either a flare used to comply with an applicable NSPS or 
MACT standard (including uses of flares during startup, shutdown, or 
malfunction permitted under such a standard), or a flare that serves to 
control emissions of waste streams comprised predominately of 
hydrocarbons and containing no more than 230 mg/dscm hydrogen sulfide.
    (v) Activities or projects undertaken to accommodate switching (or 
partially switching) to an inherently less polluting fuel, to be limited 
to the following fuel switches:

[[Page 235]]

    (a) Switching from a heavier grade of fuel oil to a lighter fuel 
oil, or any grade of oil to 0.05 percent sulfur diesel (i.e., from a 
higher sulfur content 2 fuel or from 6 fuel, to CA 
0.05 percent sulfur 2 diesel);
    (b) Switching from coal, oil, or any solid fuel to natural gas, 
propane, or gasified coal;
    (c) Switching from coal to wood, excluding construction or 
demolition waste, chemical or pesticide treated wood, and other forms of 
``unclean'' wood;
    (d) Switching from coal to 2 fuel oil (0.5 percent maximum 
sulfur content); and
    (e) Switching from high sulfur coal to low sulfur coal (maximum 1.2 
percent sulfur content).
    (vi) Activities or projects undertaken to accommodate switching from 
the use of one ozone depleting substance (ODS) to the use of a substance 
with a lower or zero ozone depletion potential (ODP), including changes 
to equipment needed to accommodate the activity or project, that meet 
the requirements of paragraphs (b)(31)(vi)(a) and (b) of this section.
    (a) The productive capacity of the equipment is not increased as a 
result of the activity or project.
    (b) The projected usage of the new substance is lower, on an ODP-
weighted basis, than the baseline usage of the replaced ODS. To make 
this determination, follow the procedure in paragraphs (b)(31)(vi)(b)(1) 
through (4) of this section.
    (1) Determine the ODP of the substances by consulting 40 CFR part 
82, subpart A, appendices A and B.
    (2) Calculate the replaced ODP-weighted amount by multiplying the 
baseline actual usage (using the annualized average of any 24 
consecutive months of usage within the past 10 years) by the ODP of the 
replaced ODS.
    (3) Calculate the projected ODP-weighted amount by multiplying the 
projected annual usage of the new substance by its ODP.
    (4) If the value calculated in paragraph (b)(31)(vi)(b)(2) of this 
section is more than the value calculated in paragraph (b)(31)(vi)(b)(3) 
of this section, then the projected use of the new substance is lower, 
on an ODP-weighted basis, than the baseline usage of the replaced ODS.
    (32) Replacement unit means an emissions unit for which all the 
criteria listed in paragraphs (b)(32)(i) through (iv) of this section 
are met. No creditable emission reductions shall be generated from 
shutting down the existing emissions unit that is replaced.
    (i) The emissions unit is a reconstructed unit within the meaning of 
Sec. 60.15(b)(1) of this chapter, or the emissions unit completely 
takes the place of an existing emissions unit.
    (ii) The emissions unit is identical to or functionally equivalent 
to the replaced emissions unit.
    (iii) The replacement does not change the basic design parameter(s) 
(as discussed in paragraph (y)(2) of this section) of the process unit.
    (iv) The replaced emissions unit is permanently removed from the 
major stationary source, otherwise permanently disabled, or permanently 
barred from operation by a permit that is enforceable as a practical 
matter. If the replaced emissions unit is brought back into operation, 
it shall constitute a new emissions unit.
    (33) Clean coal technology means any technology, including 
technologies applied at the precombustion, combustion, or post 
combustion stage, at a new or existing facility which will achieve 
significant reductions in air emissions of sulfur dioxide or oxides of 
nitrogen associated with the utilization of coal in the generation of 
electricity, or process steam which was not in widespread use as of 
November 15, 1990.
    (34) Clean coal technology demonstration project means a project 
using funds appropriated under the heading ``Department of Energy--Clean 
Coal Technology'', up to a total amount of $2,500,000,000 for commercial 
demonstration of clean coal technology, or similar projects funded 
through appropriations for the Environmental Protection Agency. The 
Federal contribution for a qualifying project shall be at least 20 
percent of the total cost of the demonstration project.
    (35) Temporary clean coal technology demonstration project means a 
clean coal technology demonstration project that is operated for a 
period of 5 years

[[Page 236]]

or less, and which complies with the State implementation plan for the 
State in which the project is located and other requirements necessary 
to attain and maintain the national ambient air quality standards during 
and after the project is terminated.
    (36)(i) Repowering means replacement of an existing coal-fired 
boiler with one of the following clean coal technologies: atmospheric or 
pressurized fluidized bed combustion, integrated gasification combined 
cycle, magnetohydrodynamics, direct and indirect coal-fired turbines, 
integrated gasification fuel cells, or as determined by the 
Administrator, in consultation with the Secretary of Energy, a 
derivative of one or more of these technologies, and any other 
technology capable of controlling multiple combustion emissions 
simultaneously with improved boiler or generation efficiency and with 
significantly greater waste reduction relative to the performance of 
technology in widespread commercial use as of November 15, 1990.
    (ii) Repowering shall also include any oil and/or gas-fired unit 
which has been awarded clean coal technology demonstration funding as of 
January 1, 1991, by the Department of Energy.
    (iii) The reviewing authority shall give expedited consideration to 
permit applications for any source that satisfies the requirements of 
this subsection and is granted an extension under section 409 of the 
Clean Air Act.
    (37) Reactivation of a very clean coal-fired electric utility steam 
generating unit means any physical change or change in the method of 
operation associated with the commencement of commercial operations by a 
coal-fired utility unit after a period of discontinued operation where 
the unit:
    (i) Has not been in operation for the two-year period prior to the 
enactment of the Clean Air Act Amendments of 1990, and the emissions 
from such unit continue to be carried in the permitting authority's 
emissions inventory at the time of enactment;
    (ii) Was equipped prior to shutdown with a continuous system of 
emissions control that achieves a removal efficiency for sulfur dioxide 
of no less than 85 percent and a removal efficiency for particulates of 
no less than 98 percent;
    (iii) Is equipped with low-NOX burners prior to the time 
of commencement of operations following reactivation; and
    (iv) Is otherwise in compliance with the requirements of the Clean 
Air Act.
    (38) Pollution prevention means any activity that through process 
changes, product reformulation or redesign, or substitution of less 
polluting raw materials, eliminates or reduces the release of air 
pollutants (including fugitive emissions) and other pollutants to the 
environment prior to recycling, treatment, or disposal; it does not mean 
recycling (other than certain ``in-process recycling'' practices), 
energy recovery, treatment, or disposal.
    (39) Significant emissions increase means, for a regulated NSR 
pollutant, an increase in emissions that is significant (as defined in 
paragraph (b)(23) of this section) for that pollutant.
    (40)(i) Projected actual emissions means the maximum annual rate, in 
tons per year, at which an existing emissions unit is projected to emit 
a regulated NSR pollutant in any one of the 5 years (12-month period) 
following the date the unit resumes regular operation after the project, 
or in any one of the 10 years following that date, if the project 
involves increasing the emissions unit's design capacity or its 
potential to emit that regulated NSR pollutant, and full utilization of 
the unit would result in a significant emissions increase, or a 
significant net emissions increase at the major stationary source.
    (ii) In determining the projected actual emissions under paragraph 
(b)(40)(i) of this section (before beginning actual construction), the 
owner or operator of the major stationary source:
    (a) Shall consider all relevant information, including but not 
limited to, historical operational data, the company's own 
representations, the company's expected business activity and the 
company's highest projections of business activity, the company's 
filings with the State or Federal regulatory authorities, and compliance 
plans under the approved plan; and

[[Page 237]]

    (b) Shall include fugitive emissions to the extent quantifiable and 
emissions associated with startups, shutdowns, and malfunctions; and
    (c) Shall exclude, in calculating any increase in emissions that 
results from the particular project, that portion of the unit's 
emissions following the project that an existing unit could have 
accommodated during the consecutive 24-month period used to establish 
the baseline actual emissions under paragraph (b)(47) of this section 
and that are also unrelated to the particular project, including any 
increased utilization due to product demand growth; or,
    (d) In lieu of using the method set out in paragraphs (b)(40)(ii)(a) 
through (c) of this section, may elect to use the emissions unit's 
potential to emit, in tons per year, as defined under paragraph (b)(4) 
of this section.
    (41) Clean Unit means any emissions unit that has been issued a 
major NSR permit that requires compliance with BACT or LAER, is 
complying with such BACT/LAER requirements, and qualifies as a Clean 
Unit pursuant to regulations approved by the Administrator in accordance 
with paragraph (t) of this section; or any emissions unit that has been 
designated by a reviewing authority as a Clean Unit, based on the 
criteria in paragraphs (u)(3)(i) through (iv) of this section, using a 
plan-approved permitting process; or any emissions unit that has been 
designated as a Clean Unit by the Administrator in accordance with 52.21 
(y)(3)(i) through (iv) of this chapter.
    (42) Prevention of Significant Deterioration Program (PSD) program 
means a major source preconstruction permit program that has been 
approved by the Administrator and incorporated into the plan to 
implement the requirements of this section, or the program in Sec. 
52.21 of this chapter. Any permit issued under such a program is a major 
NSR permit.
    (43) Continuous emissions monitoring system (CEMS) means all of the 
equipment that may be required to meet the data acquisition and 
availability requirements of this section, to sample, condition (if 
applicable), analyze, and provide a record of emissions on a continuous 
basis.
    (44) Predictive emissions monitoring system (PEMS) means all of the 
equipment necessary to monitor process and control device operational 
parameters (for example, control device secondary voltages and electric 
currents) and other information (for example, gas flow rate, O\2\ or 
CO\2\ concentrations), and calculate and record the mass emissions rate 
(for example, lb/hr) on a continuous basis.
    (45) Continuous parameter monitoring system (CPMS) means all of the 
equipment necessary to meet the data acquisition and availability 
requirements of this section, to monitor process and control device 
operational parameters (for example, control device secondary voltages 
and electric currents) and other information (for example, gas flow 
rate, O\2\ or CO\2\ concentrations), and to record average operational 
parameter value(s) on a continuous basis.
    (46) Continuous emissions rate monitoring system (CERMS) means the 
total equipment required for the determination and recording of the 
pollutant mass emissions rate (in terms of mass per unit of time).
    (47) Baseline actual emissions means the rate of emissions, in tons 
per year, of a regulated NSR pollutant, as determined in accordance with 
paragraphs (b)(47)(i) through (iv) of this section.
    (i) For any existing electric utility steam generating unit, 
baseline actual emissions means the average rate, in tons per year, at 
which the unit actually emitted the pollutant during any consecutive 24-
month period selected by the owner or operator within the 5-year period 
immediately preceding when the owner or operator begins actual 
construction of the project. The reviewing authority shall allow the use 
of a different time period upon a determination that it is more 
representative of normal source operation.
    (a) The average rate shall include fugitive emissions to the extent 
quantifiable, and emissions associated with startups, shutdowns, and 
malfunctions.
    (b) The average rate shall be adjusted downward to exclude any non-
compliant emissions that occurred while the source was operating above 
an emission limitation that was legally enforceable during the 
consecutive 24-month period.

[[Page 238]]

    (c) For a regulated NSR pollutant, when a project involves multiple 
emissions units, only one consecutive 24-month period must be used to 
determine the baseline actual emissions for the emissions units being 
changed. A different consecutive 24-month period can be used For each 
regulated NSR pollutant.
    (d) The average rate shall not be based on any consecutive 24-month 
period for which there is inadequate information for determining annual 
emissions, in tons per year, and for adjusting this amount if required 
by paragraph (b)(47)(i)(b) of this section.
    (ii) For an existing emissions unit (other than an electric utility 
steam generating unit), baseline actual emissions means the average 
rate, in tons per year, at which the emissions unit actually emitted the 
pollutant during any consecutive 24-month period selected by the owner 
or operator within the 10-year period immediately preceding either the 
date the owner or operator begins actual construction of the project, or 
the date a complete permit application is received by the reviewing 
authority for a permit required either under this section or under a 
plan approved by the Administrator, whichever is earlier, except that 
the 10-year period shall not include any period earlier than November 
15, 1990.
    (a) The average rate shall include fugitive emissions to the extent 
quantifiable, and emissions associated with startups, shutdowns, and 
malfunctions.
    (b) The average rate shall be adjusted downward to exclude any non-
compliant emissions that occurred while the source was operating above 
an emission limitation that was legally enforceable during the 
consecutive 24-month period.
    (c) The average rate shall be adjusted downward to exclude any 
emissions that would have exceeded an emission limitation with which the 
major stationary source must currently comply, had such major stationary 
source been required to comply with such limitations during the 
consecutive 24-month period. However, if an emission limitation is part 
of a maximum achievable control technology standard that the 
Administrator proposed or promulgated under part 63 of this chapter, the 
baseline actual emissions need only be adjusted if the State has taken 
credit for such emissions reductions in an attainment demonstration or 
maintenance plan consistent with the requirements of Sec. 
51.165(a)(3)(ii)(G).
    (d) For a regulated NSR pollutant, when a project involves multiple 
emissions units, only one consecutive 24-month period must be used to 
determine the baseline actual emissions for the emissions units being 
changed. A different consecutive 24-month period can be used For each 
regulated NSR pollutant.
    (e) The average rate shall not be based on any consecutive 24-month 
period for which there is inadequate information for determining annual 
emissions, in tons per year, and for adjusting this amount if required 
by paragraphs (b)(47)(ii)(b) and (c) of this section.
    (iii) For a new emissions unit, the baseline actual emissions for 
purposes of determining the emissions increase that will result from the 
initial construction and operation of such unit shall equal zero; and 
thereafter, for all other purposes, shall equal the unit's potential to 
emit.
    (iv) For a PAL for a stationary source, the baseline actual 
emissions shall be calculated for existing electric utility steam 
generating units in accordance with the procedures contained in 
paragraph (b)(47)(i) of this section, for other existing emissions units 
in accordance with the procedures contained in paragraph (b)(47)(ii) of 
this section, and for a new emissions unit in accordance with the 
procedures contained in paragraph (b)(47)(iii) of this section.
    (48) [Reserved]
    (49) Regulated NSR pollutant, for purposes of this section, means 
the following:
    (i) Any pollutant for which a national ambient air quality standard 
has been promulgated and any constituents or precursors for such 
pollutants identified by the Administrator (e.g., volatile organic 
compounds and NOX are precursors for ozone);
    (ii) Any pollutant that is subject to any standard promulgated under 
section 111 of the Act;

[[Page 239]]

    (iii) Any Class I or II substance subject to a standard promulgated 
under or established by title VI of the Act; or
    (iv) Any pollutant that otherwise is subject to regulation under the 
Act; except that any or all hazardous air pollutants either listed in 
section 112 of the Act or added to the list pursuant to section 
112(b)(2) of the Act, which have not been delisted pursuant to section 
112(b)(3) of the Act, are not regulated NSR pollutants unless the listed 
hazardous air pollutant is also regulated as a constituent or precursor 
of a general pollutant listed under section 108 of the Act.
    (50) Reviewing authority means the State air pollution control 
agency, local agency, other State agency, Indian tribe, or other agency 
authorized by the Administrator to carry out a permit program under 
Sec. 51.165 and this section, or the Administrator in the case of EPA-
implemented permit programs under Sec. 52.21 of this chapter.
    (51) Project means a physical change in, or change in method of 
operation of, an existing major stationary source.
    (52) Lowest achievable emission rate (LAER) is as defined in Sec. 
51.165(a)(1)(xiii).
    (53)(i) In general, process unit means any collection of structures 
and/or equipment that processes, assembles, applies, blends, or 
otherwise uses material inputs to produce or store an intermediate or a 
completed product. A single stationary source may contain more than one 
process unit, and a process unit may contain more than one emissions 
unit.
    (ii) Pollution control equipment is not part of the process unit, 
unless it serves a dual function as both process and control equipment. 
Administrative and warehousing facilities are not part of the process 
unit.
    (iii) For replacement cost purposes, components shared between two 
or more process units are proportionately allocated based on capacity.
    (iv) The following list identifies the process units at specific 
categories of stationary sources.
    (a) For a steam electric generating facility, the process unit 
consists of those portions of the plant that contribute directly to the 
production of electricity. For example, at a pulverized coal-fired 
facility, the process unit would generally be the combination of those 
systems from the coal receiving equipment through the emission stack 
(excluding post-combustion pollution controls), including the coal 
handling equipment, pulverizers or coal crushers, feedwater heaters, ash 
handling, boiler, burners, turbine-generator set, condenser, cooling 
tower, water treatment system, air preheaters, and operating control 
systems. Each separate generating unit is a separate process unit.
    (b) For a petroleum refinery, there are several categories of 
process units: those that separate and/or distill petroleum feedstocks; 
those that change molecular structures; petroleum treating processes; 
auxiliary facilities, such as steam generators and hydrogen production 
units; and those that load, unload, blend or store intermediate or 
completed products.
    (c) For an incinerator, the process unit would consist of components 
from the feed pit or refuse pit to the stack, including conveyors, 
combustion devices, heat exchangers and steam generators, quench tanks, 
and fans.
    Note to paragraph (b)(53): By a court order on December 24, 2003, 
this paragraph (b)(53) is stayed indefinitely. The stayed provisions 
will become effective immediately if the court terminates the stay. At 
that time, EPA will publish a document in the Federal Register advising 
the public of the termination of the stay.
    (54) Functionally equivalent component means a component that serves 
the same purpose as the replaced component.
    Note to paragraph (b)(54): By a court order on December 24, 2003, 
this paragraph (b)(54) is stayed indefinitely. The stayed provisions 
will become effective immediately if the court terminates the stay. At 
that time, EPA will publish a document in the Federal Register advising 
the public of the termination of the stay.
    (55) Fixed capital cost means the capital needed to provide all the 
depreciable components. ``Depreciable components'' refers to all 
components of fixed capital cost and is calculated by subtracting land 
and working capital from the total capital investment, as defined in 
paragraph (b)(56) of this section.
    Note to paragraph (b)(55): By a court order on December 24, 2003, 
this paragraph

[[Page 240]]

(b)(55) is stayed indefinitely. The stayed provisions will become 
effective immediately if the court terminates the stay. At that time, 
EPA will publish a document in the Federal Register advising the public 
of the termination of the stay.
    (56) Total capital investment means the sum of the following: all 
costs required to purchase needed process equipment (purchased equipment 
costs); the costs of labor and materials for installing that equipment 
(direct installation costs); the costs of site preparation and 
buildings; other costs such as engineering, construction and field 
expenses, fees to contractors, startup and performance tests, and 
contingencies (indirect installation costs); land for the process 
equipment; and working capital for the process equipment.
    Note to paragraph (b)(56): By a court order on December 24, 2003, 
this paragraph (b)(56) is stayed indefinitely. The stayed provisions 
will become effective immediately if the court terminates the stay. At 
that time, EPA will publish a document in the Federal Register advising 
the public of the termination of the stay.
    (c) Ambient air increments and other measures. (1) The plan shall 
contain emission limitations and such other measures as may be necessary 
to assure that in areas designated as Class I, II, or III, increases in 
pollutant concentrations over the baseline concentration shall be 
limited to the following:

------------------------------------------------------------------------
                                                              Maximum
                                                             allowable
                                                             increase
                        Pollutant                           (micrograms
                                                             per cubic
                                                              meter)
------------------------------------------------------------------------
                                 Class I
------------------------------------------------------------------------
Particulate matter:
    PM10, annual arithmetic mean........................               4
    PM10, 24-hr maximum.................................               8
Sulfur dioxide:
    Annual arithmetic mean..............................               2
    24-hr maximum.......................................               5
    3-hr maximum........................................              25
Nitrogen dioxide:
    Annual arithmetic mean..............................             2.5
------------------------------------------------------------------------
                                Class II
------------------------------------------------------------------------
Particulate matter:
    PM10, annual arithmetic mean........................              17
    PM10, 24-hr maximum.................................              30
Sulfur dioxide:
    Annual arithmetic mean..............................              20
    24-hr maximum.......................................              91
    3-hr maximum........................................             512
Nitrogen dioxide:
    Annual arithmetic mean..............................              25
------------------------------------------------------------------------
                                Class III
------------------------------------------------------------------------
Particulate matter:
    PM10, annual arithmetic mean........................              34
    PM10, 24-hr maximum.................................              60
Sulfur dioxide:
    Annual arithmetic mean..............................              40
    24-hr maximum.......................................             182
    3-hr maximum........................................             700
Nitrogen dioxide:
    Annual arithmetic mean..............................              50
------------------------------------------------------------------------

    For any period other than an annual period, the applicable maximum 
allowable increase may be exceeded during one such period per year at 
any one location.
    (2) Where the State can demonstrate that it has alternative measures 
in its plan other than maximum allowable increases that satisfy the 
requirements in sections 166(c) and 166(d) of the Clean Air Act for 
nitrogen oxides, the requirements for maximum allowable increases for 
nitrogen dioxide under paragraph (c)(1) of this section shall not apply 
upon approval of the plan by the Administrator.
    (d) Ambient air ceilings. The plan shall provide that no 
concentration of a pollutant shall exceed:
    (1) The concentration permitted under the national secondary ambient 
air quality standard, or
    (2) The concentration permitted under the national primary ambient 
air quality standard, whichever concentration is lowest for the 
pollutant for a period of exposure.
    (e) Restrictions on area classifications. The plan shall provide 
that--
    (1) All of the following areas which were in existence on August 7, 
1977, shall be Class I areas and may not be redesignated:
    (i) International parks,
    (ii) National wilderness areas which exceed 5,000 acres in size,
    (iii) National memorial parks which exceed 5,000 acres in size, and
    (iv) National parks which exceed 6,000 acres in size.
    (2) Areas which were redesignated as Class I under regulations 
promulgated before August 7, 1977, shall remain Class I, but may be 
redesignated as provided in this section.

[[Page 241]]

    (3) Any other area, unless otherwise specified in the legislation 
creating such an area, is initially designated Class II, but may be 
redesignated as provided in this section.
    (4) The following areas may be redesignated only as Class I or II:
    (i) An area which as of August 7, 1977, exceeded 10,000 acres in 
size and was a national monument, a national primitive area, a national 
preserve, a national recreational area, a national wild and scenic 
river, a national wildlife refuge, a national lakeshore or seashore; and
    (ii) A national park or national wilderness area established after 
August 7, 1977, which exceeds 10,000 acres in size.
    (f) Exclusions from increment consumption. (1) The plan may provide 
that the following concentrations shall be excluded in determining 
compliance with a maximum allowable increase:
    (i) Concentrations attributable to the increase in emissions from 
stationary sources which have converted from the use of petroleum 
products, natural gas, or both by reason of an order in effect under 
section 2 (a) and (b) of the Energy Supply and Environmental 
Coordination Act of 1974 (or any superseding legislation) over the 
emissions from such sources before the effective date of such an order;
    (ii) Concentrations attributable to the increase in emissions from 
sources which have converted from using natural gas by reason of natural 
gas curtailment plan in effect pursuant to the Federal Power Act over 
the emissions from such sources before the effective date of such plan;
    (iii) Concentrations of particulate matter attributable to the 
increase in emissions from construction or other temporary emission-
related activities of new or modified sources;
    (iv) The increase in concentrations attributable to new sources 
outside the United States over the concentrations attributable to 
existing sources which are included in the baseline concentration; and
    (v) Concentrations attributable to the temporary increase in 
emissions of sulfur dioxide, particulate matter, or nitrogen oxides from 
stationary sources which are affected by plan revisions approved by the 
Administrator as meeting the criteria specified in paragraph (f)(4) of 
this section.
    (2) If the plan provides that the concentrations to which paragraph 
(f)(1) (i) or (ii) of this section, refers shall be excluded, it shall 
also provide that no exclusion of such concentrations shall apply more 
than five years after the effective date of the order to which paragraph 
(f)(1)(i) of this section, refers or the plan to which paragraph 
(f)(1)(ii) of this section, refers, whichever is applicable. If both 
such order and plan are applicable, no such exclusion shall apply more 
than five years after the later of such effective dates.
    (3) [Reserved]
    (4) For purposes of excluding concentrations pursuant to paragraph 
(f)(1)(v) of this section, the Administrator may approve a plan revision 
that:
    (i) Specifies the time over which the temporary emissions increase 
of sulfur dioxide, particulate matter, or nitrogen oxides would occur. 
Such time is not to exceed 2 years in duration unless a longer time is 
approved by the Administrator.
    (ii) Specifies that the time period for excluding certain 
contributions in accordance with paragraph (f)(4)(i) of this section, is 
not renewable;
    (iii) Allows no emissions increase from a stationary source which 
would:
    (a) Impact a Class I area or an area where an applicable increment 
is known to be violated; or
    (b) Cause or contribute to the violation of a national ambient air 
quality standard;
    (iv) Requires limitations to be in effect the end of the time period 
specified in accordance with paragraph (f)(4)(i) of this section, which 
would ensure that the emissions levels from stationary sources affected 
by the plan revision would not exceed those levels occurring from such 
sources before the plan revision was approved.
    (g) Redesignation. (1) The plan shall provide that all areas of the 
State (except as otherwise provided under paragraph (e) of this section) 
shall be designated either Class I, Class II, or Class III. Any 
designation other than Class II shall be subject to the redesignation 
procedures of this paragraph. Redesignation (except as otherwise 
precluded

[[Page 242]]

by paragraph (e) of this section) may be proposed by the respective 
States or Indian Governing Bodies, as provided below, subject to 
approval by the Administrator as a revision to the applicable State 
implementation plan.
    (2) The plan may provide that the State may submit to the 
Administrator a proposal to redesignate areas of the State Class I or 
Class II: Provided, That:
    (i) At least one public hearing has been held in accordance with 
procedures established in Sec. 51.102.
    (ii) Other States, Indian Governing Bodies, and Federal Land 
Managers whose lands may be affected by the proposed redesignation were 
notified at least 30 days prior to the public hearing;
    (iii) A discussion of the reasons for the proposed redesignation, 
including a satisfactory description and analysis of the health, 
environmental, economic, social, and energy effects of the proposed 
redesignation, was prepared and made available for public inspection at 
least 30 days prior to the hearing and the notice announcing the hearing 
contained appropriate notification of the availability of such 
discussion;
    (iv) Prior to the issuance of notice respecting the redesignation of 
an area that includes any Federal lands, the State has provided written 
notice to the appropriate Federal Land Manager and afforded adequate 
opportunity (not in excess of 60 days) to confer with the State 
respecting the redesignation and to submit written comments and 
recommendations. In redesignating any area with respect to which any 
Federal Land Manager had submitted written comments and recommendations, 
the State shall have published a list of any inconsistency between such 
redesignation and such comments and recommendations (together with the 
reasons for making such redesignation against the recommendation of the 
Federal Land Manager); and
    (v) The State has proposed the redesignation after consultation with 
the elected leadership of local and other substate general purpose 
governments in the area covered by the proposed redesignation.
    (3) The plan may provide that any area other than an area to which 
paragraph (e) of this section refers may be redesignated as Class III 
if--
    (i) The redesignation would meet the requirements of provisions 
established in accordance with paragraph (g)(2) of this section;
    (ii) The redesignation, except any established by an Indian 
Governing Body, has been specifically approved by the Governor of the 
State, after consultation with the appropriate committees of the 
legislature, if it is in session, or with the leadership of the 
legislature, if it is not in session (unless State law provides that 
such redesignation must be specifically approved by State legislation) 
and if general purpose units of local government representing a majority 
of the residents of the area to be redesignated enact legislation 
(including resolutions where appropriate) concurring in the 
redesignation;
    (iii) The redesignation would not cause, or contribute to, a 
concentration of any air pollutant which would exceed any maximum 
allowable increase permitted under the classification of any other area 
or any national ambient air quality standard; and
    (iv) Any permit application for any major stationary source or major 
modification subject to provisions established in accordance with 
paragraph (l) of this section which could receive a permit only if the 
area in question were redesignated as Class III, and any material 
submitted as part of that application, were available, insofar as was 
practicable, for public inspection prior to any public hearing on 
redesignation of any area as Class III.
    (4) The plan shall provide that lands within the exterior boundaries 
of Indian Reservations may be redesignated only by the appropriate 
Indian Governing Body. The appropriate Indian Governing Body may submit 
to the Administrator a proposal to redesignate areas Class I, Class II, 
or Class III: Provided, That:
    (i) The Indian Governing Body has followed procedures equivalent to 
those required of a State under paragraphs (g) (2), (3)(iii), and 
(3)(iv) of this section; and
    (ii) Such redesignation is proposed after consultation with the 
State(s) in

[[Page 243]]

which the Indian Reservation is located and which border the Indian 
Reservation.
    (5) The Administrator shall disapprove, within 90 days of 
submission, a proposed redesignation of any area only if he finds, after 
notice and opportunity for public hearing, that such redesignation does 
not meet the procedural requirements of this section or is inconsistent 
with paragraph (e) of this section. If any such disapproval occurs, the 
classification of the area shall be that which was in effect prior to 
the redesignation which was disapproved.
    (6) If the Administrator disapproves any proposed area designation, 
the State or Indian Governing Body, as appropriate, may resubmit the 
proposal after correcting the deficiencies noted by the Administrator.
    (h) Stack heights. The plan shall provide, as a minimum, that the 
degree of emission limitation required for control of any air pollutant 
under the plan shall not be affected in any manner by--
    (1) So much of a stack height, not in existence before December 31, 
1970, as exceeds good engineering practice, or
    (2) Any other dispersion technique not implemented before then.
    (i) Exemptions. (1) The plan may provide that requirements 
equivalent to those contained in paragraphs (j) through (r) of this 
section do not apply to a particular major stationary source or major 
modification if:
    (i) The major stationary source would be a nonprofit health or 
nonprofit educational institution or a major modification that would 
occur at such an institution; or
    (ii) The source or modification would be a major stationary source 
or major modification only if fugitive emissions, to the extent 
quantifiable, are considered in calculating the potential to emit of the 
stationary source or modification and such source does not belong to any 
following categories:
    (a) Coal cleaning plants (with thermal dryers);
    (b) Kraft pulp mills;
    (c) Portland cement plants;
    (d) Primary zinc smelters;
    (e) Iron and steel mills;
    (f) Primary aluminum ore reduction plants;
    (g) Primary copper smelters;
    (h) Municipal incinerators capable of charging more than 250 tons of 
refuse per day;
    (i) Hydrofluoric, sulfuric, or nitric acid plants;
    (j) Petroleum refineries;
    (k) Lime plants;
    (l) Phosphate rock processing plants;
    (m) Coke oven batteries;
    (n) Sulfur recovery plants;
    (o) Carbon black plants (furnace process);
    (p) Primary lead smelters;
    (q) Fuel conversion plants;
    (r) Sintering plants;
    (s) Secondary metal production plants;
    (t) Chemical process plants;
    (u) Fossil-fuel boilers (or combination thereof) totaling more than 
250 million British thermal units per hour heat input;
    (v) Petroleum storage and transfer units with a total storage 
capacity exceeding 300,000 barrels;
    (w) Taconite ore processing plants;
    (x) Glass fiber processing plants;
    (y) Charcoal production plants;
    (z) Fossil fuel-fired steam electric plants of more than 250 million 
British thermal units per hour heat input;
    (aa) Any other stationary source category which, as of August 7, 
1980, is being regulated under section 111 or 112 of the Act; or
    (iii) The source or modification is a portable stationary source 
which has previously received a permit under requirements equivalent to 
those contained in paragraphs (j) through (r) of this section, if:
    (a) The source proposes to relocate and emissions of the source at 
the new location would be temporary; and
    (b) The emissions from the source would not exceed its allowable 
emissions; and
    (c) The emissions from the source would impact no Class I area and 
no area where an applicable increment is known to be violated; and

[[Page 244]]

    (d) Reasonable notice is given to the reviewing authority prior to 
the relocation identifying the proposed new location and the probable 
duration of operation at the new location. Such notice shall be given to 
the reviewing authority not less than 10 days in advance of the proposed 
relocation unless a different time duration is previously approved by 
the reviewing authority.
    (2) The plan may provide that requirements equivalent to those 
contained in paragraphs (j) through (r) of this section do not apply to 
a major stationary source or major modification with respect to a 
particular pollutant if the owner or operator demonstrates that, as to 
that pollutant, the source or modification is located in an area 
designated as nonattainment under section 107 of the Act.
    (3) The plan may provide that requirements equivalent to those 
contained in paragraphs (k), (m), and (o) of this section do not apply 
to a proposed major stationary source or major modification with respect 
to a particular pollutant, if the allowable emissions of that pollutant 
from a new source, or the net emissions increase of that pollutant from 
a modification, would be temporary and impact no Class I area and no 
area where an applicable increment is known to be violated.
    (4) The plan may provide that requirements equivalent to those 
contained in paragraphs (k), (m), and (o) of this section as they relate 
to any maximum allowable increase for a Class II area do not apply to a 
modification of a major stationary source that was in existence on March 
1, 1978, if the net increase in allowable emissions of each a regulated 
NSR pollutant from the modification after the application of best 
available control technology would be less than 50 tons per year.
    (5) The plan may provide that the reviewing authority may exempt a 
proposed major stationary source or major modification from the 
requirements of paragraph (m) of this section, with respect to 
monitoring for a particular pollutant, if:
    (i) The emissions increase of the pollutant from a new stationary 
source or the net emissions increase of the pollutant from a 
modification would cause, in any area, air quality impacts less than the 
following amounts:
    (a) Carbon monoxide--575 ug/m\3\, 8-hour average;
    (b) Nitrogen dioxide--14 ug/m\3\, annual average;
    (c) Particulate matter--10 [micro]g/m\3\ of PM-10, 24-hour average.
    (d) Sulfur dioxide--13 ug/m\3\, 24-hour average;
    (e) Ozone; \1\
---------------------------------------------------------------------------

    \1\ No de minimis air quality level is provided for ozone. However, 
any net emissions increase of 100 tons per year or more of volatile 
organic compounds or nitrogen oxides subject to PSD would be required to 
perform an ambient impact analysis, including the gathering of air 
quality data.
---------------------------------------------------------------------------

    (f) Lead--0.1 [micro]g/m\3\, 3-month average.
    (g) Fluorides--0.25 [micro]g/m\3\, 24-hour average;
    (h) Total reduced sulfur--10 [micro]g/m\3\, 1-hour average
    (i) Hydrogen sulfide--0.2 [micro]g/m\3\, 1-hour average;
    (j) Reduced sulfur compounds--10 [micro]g/m\3\, 1-hour average; or
    (ii) The concentrations of the pollutant in the area that the source 
or modification would affect are less than the concentrations listed in 
(i)(8)(i) of this section; or
    (iii) The pollutants is not listed in paragraph (i)(8)(i) of this 
section.
    (6) If EPA approves a plan revision under 40 CFR 51.166 as in effect 
before August 7, 1980, any subsequent revision which meets the 
requirements of this section may contain transition provisions which 
parallel the transition provisions of 40 CFR 52.21(i)(9), (i)(10) and 
(m)(1)(v) as in effect on that date, which provisions relate to 
requirements for best available control technology and air quality 
analyses. Any such subsequent revision may not contain any transition 
provision which in the context of the revision would operate any less 
stringently than would its counterpart in 40 CFR 52.21.
    (7) If EPA approves a plan revision under Sec. 51.166 as in effect 
[before July 31, 1987], any subsequent revision which meets the 
requirements of this section may contain transition provisions which 
parallel the transition provisions of Sec. 52.21 (i)(11), and (m)(1) 
(vii) and (viii) of this chapter as in effect on

[[Page 245]]

that date, these provisions being related to monitoring requirements for 
particulate matter. Any such subsequent revision may not contain any 
transition provision which in the context of the revision would operate 
any less stringently than would its counterpart in Sec. 52.21 of this 
chapter.
    (8) The plan may provide that the permitting requirements equivalent 
to those contained in paragraph (k)(2) of this section do not apply to a 
stationary source or modification with respect to any maximum allowable 
increase for nitrogen oxides if the owner or operator of the source or 
modification submitted an application for a permit under the applicable 
permit program approved or promulgated under the Act before the 
provisions embodying the maximum allowable increase took effect as part 
of the plan and the permitting authority subsequently determined that 
the application as submitted before that date was complete.
    (9) The plan may provide that the permitting requirements equivalent 
to those contained in paragraph (k)(2) of this section shall not apply 
to a stationary source or modification with respect to any maximum 
allowable increase for PM-10 if (i) the owner or operator of the source 
or modification submitted an application for a permit under the 
applicable permit program approved under the Act before the provisions 
embodying the maximum allowable increases for PM-10 took effect as part 
of the plan, and (ii) the permitting authority subsequently determined 
that the application as submitted before that date was complete. 
Instead, the applicable requirements equivalent to paragraph (k)(2) 
shall apply with respect to the maximum allowable increases for TSP as 
in effect on the date the application was submitted.
    (j) Control technology review. The plan shall provide that:
    (1) A major stationary source or major modification shall meet each 
applicable emissions limitation under the State Implementation Plan and 
each applicable emission standards and standard of performance under 40 
CFR parts 60 and 61.
    (2) A new major stationary source shall apply best available control 
technology for each a regulated NSR pollutant that it would have the 
potential to emit in significant amounts.
    (3) A major modification shall apply best available control 
technology for each a regulated NSR pollutant for which it would be a 
significant net emissions increase at the source. This requirement 
applies to each proposed emissions unit at which a net emissions 
increase in the pollutant would occur as a result of a physical change 
or change in the method of operation in the unit.
    (4) For phased construction projects, the determination of best 
available control technology shall be reviewed and modified as 
appropriate at the least reasonable time which occurs no later than 18 
months prior to commencement of construction of each independent phase 
of the project. At such time, the owner or operator of the applicable 
stationary source may be required to demonstrate the adequacy of any 
previous determination of best available control technology for the 
source.
    (k) Source impact analysis. The plan shall provide that the owner or 
operator of the proposed source or modification shall demonstrate that 
allowable emission increases from the proposed source or modification, 
in conjunction with all other applicable emissions increases or 
reduction (including secondary emissions) would not cause or contribute 
to air pollution in violation of:
    (1) Any national ambient air quality standard in any air quality 
control region; or
    (2) Any applicable maximum allowable increase over the baseline 
concentration in any area.
    (l) Air quality models. The plan shall provide for procedures which 
specify that--
    (1) All applications of air quality modeling involved in this 
subpart shall be based on the applicable models, data bases, and other 
requirements specified in appendix W of this part (Guideline on Air 
Quality Models).
    (2) Where an air quality model specified in appendix W of this part 
(Guideline on Air Quality Models) is inappropriate, the model may be 
modified or another model substituted. Such a

[[Page 246]]

modification or substitution of a model may be made on a case-by-case 
basis or, where appropriate, on a generic basis for a specific State 
program. Written approval of the Administrator must be obtained for any 
modification or substitution. In addition, use of a modified or 
substituted model must be subject to notice and opportunity for public 
comment under procedures set forth in Sec. 51.102.
    (m) Air quality analysis--(1) Preapplication analysis. (i) The plan 
shall provide that any application for a permit under regulations 
approved pursuant to this section shall contain an analysis of ambient 
air quality in the area that the major stationary source or major 
modification would affect for each of the following pollutants:
    (a) For the source, each pollutant that it would have the potential 
to emit in a significant amount;
    (b) For the modification, each pollutant for which it would result 
in a significant net emissions increase.
    (ii) The plan shall provide that, with respect to any such pollutant 
for which no National Ambient Air Quality Standard exists, the analysis 
shall contain such air quality monitoring data as the reviewing 
authority determines is necessary to assess ambient air quality for that 
pollutant in any area that the emissions of that pollutant would affect.
    (iii) The plan shall provide that with respect to any such pollutant 
(other than nonmethane hydrocarbons) for which such a standard does 
exist, the analysis shall contain continuous air quality monitoring data 
gathered for purposes of determining whether emissions of that pollutant 
would cause or contribute to a violation of the standard or any maxiumum 
allowable increase.
    (iv) The plan shall provide that, in general, the continuous air 
monitoring data that is required shall have been gathered over a period 
of one year and shall represent the year preceding receipt of the 
application, except that, if the reviewing authority determines that a 
complete and adequate analysis can be accomplished with monitoring data 
gathered over a period shorter than one year (but not to be less than 
four months), the data that is required shall have been gathered over at 
least that shorter period.
    (v) The plan may provide that the owner or operator of a proposed 
major stationary source or major modification of volatile organic 
compounds who satisfies all conditions of 40 CFR part 51 appendix S, 
section IV may provide postapproval monitoring data for ozone in lieu of 
providing preconstruction data as required under paragraph (m)(1) of 
this section.
    (2) Post-construction monitoring. The plan shall provide that the 
owner or operator of a major stationary source or major modification 
shall, after construction of the stationary source or modification, 
conduct such ambient monitoring as the reviewing authority determines is 
necessary to determine the effect emissions from the stationary source 
or modification may have, or are having, on air quality in any area.
    (3) Operation of monitoring stations. The plan shall provide that 
the owner or operator of a major stationary source or major modification 
shall meet the requirements of appendix B to part 58 of this chapter 
during the operation of monitoring stations for purposes of satisfying 
paragraph (m) of this section.
    (n) Source information. (1) The plan shall provide that the owner or 
operator of a proposed source or modification shall submit all 
information necessary to perform any analysis or make any determination 
required under procedures established in accordance with this section.
    (2) The plan may provide that such information shall include:
    (i) A description of the nature, location, design capacity, and 
typical operating schedule of the source or modification, including 
specifications and drawings showing its design and plant layout;
    (ii) A detailed schedule for construction of the source or 
modification;
    (iii) A detailed description as to what system of continuous 
emission reduction is planned by the source or modification, emission 
estimates, and any other information as necessary to determine that best 
available control technology as applicable would be applied;

[[Page 247]]

    (3) The plan shall provide that upon request of the State, the owner 
or operator shall also provide information on:
    (i) The air quality impact of the source or modification, including 
meteorological and topographical data necessary to estimate such impact; 
and
    (ii) The air quality impacts and the nature and extent of any or all 
general commercial, residential, industrial, and other growth which has 
occurred since August 7, 1977, in the area the source or modification 
would affect.
    (o) Additional impact analyses. The plan shall provide that--
    (1) The owner or operator shall provide an analysis of the 
impairment to visibility, soils, and vegetation that would occur as a 
result of the source or modification and general commercial, 
residential, industrial, and other growth associated with the source or 
modification. The owner or operator need not provide an analysis of the 
impact on vegetation having no significant commercial or recreational 
value.
    (2) The owner or operator shall provide an analysis of the air 
quality impact projected for the area as a result of general commercial, 
residential, industrial, and other growth associated with the source or 
modification.
    (p) Sources impacting Federal Class I areas--additional 
requirements--(1) Notice to EPA. The plan shall provide that the 
reviewing authority shall transmit to the Administrator a copy of each 
permit application relating to a major stationary source or major 
modification and provide notice to the Administrator of every action 
related to the consideration of such permit.
    (2) Federal Land Manager. The Federal Land Manager and the Federal 
official charged with direct responsibility for management of Class I 
lands have an affirmative responsibility to protect the air quality 
related values (including visibility) of any such lands and to consider, 
in consultation with the Administrator, whether a proposed source or 
modification would have an adverse impact on such values.
    (3) Denial--impact on air quality related values. The plan shall 
provide a mechanism whereby a Federal Land Manager of any such lands may 
present to the State, after the reviewing authority's preliminary 
determination required under procedures developed in accordance with 
paragraph (r) of this section, a demonstration that the emissions from 
the proposed source or modification would have an adverse impact on the 
air quality-related values (including visibility) of any Federal 
mandatory Class I lands, notwithstanding that the change in air quality 
resulting from emissions from such source or modification would not 
cause or contribute to concentrations which would exceed the maximum 
allowable increases for a Class I area. If the State concurs with such 
demonstration, the reviewing authority shall not issue the permit.
    (4) Class I Variances. The plan may provide that the owner or 
operator of a proposed source or modification may demonstrate to the 
Federal Land Manager that the emissions from such source would have no 
adverse impact on the air quality related values of such lands 
(including visibility), notwithstanding that the change in air quality 
resulting from emissions from such source or modification would cause or 
contribute to concentrations which would exceed the maximum allowable 
increases for a Class I area. If the Federal land manager concurs with 
such demonstration and so certifies to the State, the reviewing 
authority may: Provided, That applicable requirements are otherwise met, 
issue the permit with such emission limitations as may be necessary to 
assure that emissions of sulfur dioxide, particulate matter, and 
nitrogen oxides would not exceed the following maximum allowable 
increases over minor source baseline concentration for such pollutants:

------------------------------------------------------------------------
                                                               Maximum
                                                              allowable
                                                               increase
                         Pollutant                           (micrograms
                                                              per cubic
                                                                meter)
------------------------------------------------------------------------
Particulate matter:
    PM-10, annual arithmetic mean..........................         17
    PM-10, 24-hour maximum.................................         30
Sulfur dioxide:
    Annual arithmetic mean.................................         20
    24-hr maximum..........................................         91
    3-hr maximum...........................................        325
Nitrogen dioxide: Annual arithmetic mean...................         25
------------------------------------------------------------------------

    (5) Sulfur dioxide variance by Governor with Federal Land Manager's 
concurrence. The plan may provide that--

[[Page 248]]

    (i) The owner or operator of a proposed source or modification which 
cannot be approved under procedures developed pursuant to paragraph 
(q)(4) of this section may demonstrate to the Governor that the source 
or modification cannot be constructed by reason of any maximum allowable 
increase for sulfur dioxide for periods of twenty-four hours or less 
applicable to any Class I area and, in the case of Federal mandatory 
Class I areas, that a variance under this clause would not adversely 
affect the air quality related values of the area (including 
visibility);
    (ii) The Governor, after consideration of the Federal Land Manager's 
recommendation (if any) and subject to his concurrence, may grant, after 
notice and an opportunity for a public hearing, a variance from such 
maximum allowable increase; and
    (iii) If such variance is granted, the reviewing authority may issue 
a permit to such source or modification in accordance with provisions 
developed pursuant to paragraph (q)(7) of this section: Provided, That 
the applicable requirements of the plan are otherwise met.
    (6) Variance by the Governor with the President's concurrence. The 
plan may provide that--
    (i) The recommendations of the Governor and the Federal Land Manager 
shall be transferred to the President in any case where the Governor 
recommends a variance in which the Federal Land Manager does not concur;
    (ii) The President may approve the Governor's recommendation if he 
finds that such variance is in the national interest; and
    (iii) If such a variance is approved, the reviewing authority may 
issue a permit in accordance with provisions developed pursuant to the 
requirements of paragraph (q)(7) of this section: Provided, That the 
applicable requirements of the plan are otherwise met.
    (7) Emission limitations for Presidential or gubernatorial variance. 
The plan shall provide that in the case of a permit issued under 
procedures developed pursuant to paragraph (q) (5) or (6) of this 
section, the source or modification shall comply with emission 
limitations as may be necessary to assure that emissions of sulfur 
dioxide from the source or modification would not (during any day on 
which the otherwise applicable maximum allowable increases are exceeded) 
cause or contribute to concentrations which would exceed the following 
maximum allowable increases over the baseline concentration and to 
assure that such emissions would not cause or contribute to 
concentrations which exceed the otherwise applicable maximum allowable 
increases for periods of exposure of 24 hours or less for more than 18 
days, not necessarily consecutive, during any annual period:

                       Maximum Allowable Increase
                      [Micrograms per cubic meter]
------------------------------------------------------------------------
                                                          Terrain areas
                  Period of exposure                   -----------------
                                                          Low      High
------------------------------------------------------------------------
24-hr maximum.........................................       36       62
3-hr maximum..........................................      130      221
------------------------------------------------------------------------

    (q) Public participation. The plan shall provide that--
    (1) The reviewing authority shall notify all applicants within a 
specified time period as to the completeness of the application or any 
deficiency in the application or information submitted. In the event of 
such a deficiency, the date of receipt of the application shall be the 
date on which the reviewing authority received all required information.
    (2) Within one year after receipt of a complete application, the 
reviewing authority shall:
    (i) Make a preliminary determination whether construction should be 
approved, approved with conditions, or disapproved.
    (ii) Make available in at least one location in each region in which 
the proposed source would be constructed a copy of all materials the 
applicant submitted, a copy of the preliminary determination, and a copy 
or summary of other materials, if any, considered in making the 
preliminary determination.
    (iii) Notify the public, by advertisement in a newspaper of general 
circulation in each region in which the proposed source would be 
constructed, of

[[Page 249]]

the application, the preliminary determination, the degree of increment 
consumption that is expected from the source or modification, and of the 
opportunity for comment at a public hearing as well as written public 
comment.
    (iv) Send a copy of the notice of public comment to the applicant, 
the Administrator and to officials and agencies having cognizance over 
the location where the proposed construction would occur as follows: Any 
other State or local air pollution control agencies, the chief 
executives of the city and county where the source would be located; any 
comprehensive regional land use planning agency, and any State, Federal 
Land Manager, or Indian Governing body whose lands may be affected by 
emissions from the source or modification.
    (v) Provide opportunity for a public hearing for interested persons 
to appear and submit written or oral comments on the air quality impact 
of the source, alternatives to it, the control technology required, and 
other appropriate considerations.
    (vi) Consider all written comments submitted within a time specified 
in the notice of public comment and all comments received at any public 
hearing(s) in making a final decision on the approvability of the 
application. The reviewing authority shall make all comments available 
for public inspection in the same locations where the reviewing 
authority made available preconstruction information relating to the 
proposed source or modification.
    (vii) Make a final determination whether construction should be 
approved, approved with conditions, or disapproved.
    (viii) Notify the applicant in writing of the final determination 
and make such notification available for public inspection at the same 
location where the reviewing authority made available preconstruction 
information and public comments relating to the source.
    (r) Source obligation. (1) The plan shall include enforceable 
procedures to provide that approval to construct shall not relieve any 
owner or operator of the responsibility to comply fully with applicable 
provisions of the plan and any other requirements under local, State or 
Federal law.
    (2) The plan shall provide that at such time that a particular 
source or modification becomes a major stationary source or major 
modification solely by virtue of a relaxation in any enforceable 
limitation which was established after August 7, 1980, on the capacity 
of the source or modification otherwise to emit a pollutant, such as a 
restriction on hours of operation, then the requirements of paragraphs 
(j) through (s) of this section shall apply to the source or 
modification as though construction had not yet commenced on the source 
or modification.
    (3)-(5) [Reserved]
    (6) Each plan shall provide that the following specific provisions 
apply to projects at existing emissions units at a major stationary 
source (other than projects at a Clean Unit or at a source with a PAL) 
in circumstances where there is a reasonable possibility that a project 
that is not a part of a major modification may result in a significant 
emissions increase and the owner or operator elects to use the method 
specified in paragraphs (b)(40)(ii)(a) through (c) of this section for 
calculating projected actual emissions. Deviations from these provisions 
will be approved only if the State specifically demonstrates that the 
submitted provisions are more stringent than or at least as stringent in 
all respects as the corresponding provisions in paragraphs (r)(6)(i) 
through (v) of this section.
    (i) Before beginning actual construction of the project, the owner 
or operator shall document and maintain a record of the following 
information:
    (a) A description of the project;
    (b) Identification of the emissions unit(s) whose emissions of a 
regulated NSR pollutant could be affected by the project; and
    (c) A description of the applicability test used to determine that 
the project is not a major modification for any regulated NSR pollutant, 
including the baseline actual emissions, the projected actual emissions, 
the amount of emissions excluded under paragraph (b)(40)(ii)(c) of this 
section and an explanation for why such amount was excluded, and any 
netting calculations, if applicable.

[[Page 250]]

    (ii) If the emissions unit is an existing electric utility steam 
generating unit, before beginning actual construction, the owner or 
operator shall provide a copy of the information set out in paragraph 
(r)(6)(i) of this section to the reviewing authority. Nothing in this 
paragraph (r)(6)(ii) shall be construed to require the owner or operator 
of such a unit to obtain any determination from the reviewing authority 
before beginning actual construction.
    (iii) The owner or operator shall monitor the emissions of any 
regulated NSR pollutant that could increase as a result of the project 
and that is emitted by any emissions unit identified in paragraph 
(r)(6)(i)(b) of this section; and calculate and maintain a record of the 
annual emissions, in tons per year on a calendar year basis, for a 
period of 5 years following resumption of regular operations after the 
change, or for a period of 10 years following resumption of regular 
operations after the change if the project increases the design capacity 
or potential to emit of that regulated NSR pollutant at such emissions 
unit.
    (iv) If the unit is an existing electric utility steam generating 
unit, the owner or operator shall submit a report to the reviewing 
authority within 60 days after the end of each year during which records 
must be generated under paragraph (r)(6)(iii) of this section setting 
out the unit's annual emissions during the calendar year that preceded 
submission of the report.
    (v) If the unit is an existing unit other than an electric utility 
steam generating unit, the owner or operator shall submit a report to 
the reviewing authority if the annual emissions, in tons per year, from 
the project identified in paragraph (r)(6)(i) of this section, exceed 
the baseline actual emissions (as documented and maintained pursuant to 
paragraph (r)(6)(i)(c) of this section) by a significant amount (as 
defined in paragraph (b)(23) of this section) for that regulated NSR 
pollutant, and if such emissions differ from the preconstruction 
projection as documented and maintained pursuant to paragraph 
(r)(6)(i)(c) of this section. Such report shall be submitted to the 
reviewing authority within 60 days after the end of such year. The 
report shall contain the following:
    (a) The name, address and telephone number of the major stationary 
source;
    (b) The annual emissions as calculated pursuant to paragraph 
(r)(6)(iii) of this section; and
    (c) Any other information that the owner or operator wishes to 
include in the report (e.g., an explanation as to why the emissions 
differ from the preconstruction projection).
    (7) Each plan shall provide that the owner or operator of the source 
shall make the information required to be documented and maintained 
pursuant to paragraph (r)(6) of this section available for review upon 
request for inspection by the reviewing authority or the general public 
pursuant to the requirements contained in Sec. 70.4(b)(3)(viii) of this 
chapter.
    (s) Innovative control technology. (1) The plan may provide that an 
owner or operator of a proposed major stationary source or major 
modification may request the reviewing authority to approve a system of 
innovative control technology.
    (2) The plan may provide that the reviewing authority may, with the 
consent of the Governor(s) of other affected State(s), determine that 
the source or modification may employ a system of innovative control 
technology, if:
    (i) The proposed control system would not cause or contribute to an 
unreasonable risk to public health, welfare, or safety in its operation 
or function;
    (ii) The owner or operator agrees to achieve a level of continuous 
emissions reduction equivalent to that which would have been required 
under paragraph (j)(2) of this section, by a date specified by the 
reviewing authority. Such date shall not be later than 4 years from the 
time of startup or 7 years from permit issuance;
    (iii) The source or modification would meet the requirements 
equivalent to those in paragraphs (j) and (k) of this section, based on 
the emissions rate that the stationary source employing the system of 
innovative control technology would be required to meet on the date 
specified by the reviewing authority;

[[Page 251]]

    (iv) The source or modification would not before the date specified 
by the reviewing authority:
    (a) Cause or contribute to any violation of an applicable national 
ambient air quality standard; or
    (b) Impact any area where an applicable increment is known to be 
violated;
    (v) All other applicable requirements including those for public 
participation have been met.
    (vi) The provisions of paragraph (p) of this section (relating to 
Class I areas) have been satisfied with respect to all periods during 
the life of the source or modification.
    (3) The plan shall provide that the reviewing authority shall 
withdraw any approval to employ a system of innovative control 
technology made under this section, if:
    (i) The proposed system fails by the specified date to achieve the 
required continuous emissions reduction rate; or
    (ii) The proposed system fails before the specified date so as to 
contribute to an unreasonable risk to public health, welfare, or safety; 
or
    (iii) The reviewing authority decides at any time that the proposed 
system is unlikely to achieve the required level of control or to 
protect the public health, welfare, or safety.
    (4) The plan may provide that if a source or modification fails to 
meet the required level of continuous emissions reduction within the 
specified time period, or if the approval is withdrawn in accordance 
with paragraph (s)(3) of this section, the reviewing authority may allow 
the source or modification up to an additional 3 years to meet the 
requirement for the application of best available control technology 
through use of a demonstrated system of control.
    (t) Clean Unit Test for emissions units that are subject to BACT or 
LAER. The plan shall provide an owner or operator of a major stationary 
source the option of using the Clean Unit Test to determine whether 
emissions increases at a Clean Unit are part of a project that is a 
major modification according to the provisions in paragraphs (t)(1) 
through (9) of this section.
    (1) Applicability. The provisions of this paragraph (t) apply to any 
emissions unit for which the reviewing authority has issued a major NSR 
permit within the past 10 years.
    (2) General provisions for Clean Units. The provisions in paragraphs 
(t)(2)(i) through (iv) of this section apply to a Clean Unit.
    (i) Any project for which the owner or operator begins actual 
construction after the effective date of the Clean Unit designation (as 
determined in accordance with paragraph (t)(4) of this section) and 
before the expiration date (as determined in accordance with paragraph 
(t)(5) of this section) will be considered to have occurred while the 
emissions unit was a Clean Unit.
    (ii) If a project at a Clean Unit does not cause the need for a 
change in the emission limitations or work practice requirements in the 
permit for the unit that were adopted in conjunction with BACT and the 
project would not alter any physical or operational characteristics that 
formed the basis for the BACT determination as specified in paragraph 
(t)(6)(iv) of this section, the emissions unit remains a Clean Unit.
    (iii) If a project causes the need for a change in the emission 
limitations or work practice requirements in the permit for the unit 
that were adopted in conjunction with BACT or the project would alter 
any physical or operational characteristics that formed the basis for 
the BACT determination as specified in paragraph (t)(6)(iv) of this 
section, then the emissions unit loses its designation as a Clean Unit 
upon issuance of the necessary permit revisions (unless the unit re-
qualifies as a Clean Unit pursuant to paragraph (t)(3)(iii) of this 
section). If the owner or operator begins actual construction on the 
project without first applying to revise the emissions unit's permit, 
the Clean Unit designation ends immediately prior to the time when 
actual construction begins.
    (iv) A project that causes an emissions unit to lose its designation 
as a Clean Unit is subject to the applicability requirements of 
paragraphs (a)(7)(iv)(a) through (d) and paragraph (a)(7)(iv)(f) of this 
section as if the emissions unit is not a Clean Unit.
    (3) Qualifying or re-qualifying to use the Clean Unit Applicability 
Test. An emissions unit automatically qualifies

[[Page 252]]

as a Clean Unit when the unit meets the criteria in paragraphs (t)(3)(i) 
and (ii) of this section. After the original Clean Unit designation 
expires in accordance with paragraph (t)(5) of this section or is lost 
pursuant to paragraph (t)(2)(iii) of this section, such emissions unit 
may re-qualify as a Clean Unit under either paragraph (t)(3)(iii) of 
this section, or under the Clean Unit provisions in paragraph (u) of 
this section. To re-qualify as a Clean Unit under paragraph (t)(3)(iii) 
of this section, the emissions unit must obtain a new major NSR permit 
issued through the applicable PSD program and meet all the criteria in 
paragraph (t)(3)(iii) of this section. The Clean Unit designation 
applies individually for each pollutant emitted by the emissions unit.
    (i) Permitting requirement. The emissions unit must have received a 
major NSR permit within the past 10 years. The owner or operator must 
maintain and be able to provide information that would demonstrate that 
this permitting requirement is met.
    (ii) Qualifying air pollution control technologies. Air pollutant 
emissions from the emissions unit must be reduced through the use of air 
pollution control technology (which includes pollution prevention as 
defined under paragraph (b)(38) of this section or work practices) that 
meets both the following requirements in paragraphs (t)(3)(ii)(a) and 
(b) of this section.
    (a) The control technology achieves the BACT or LAER level of 
emissions reductions as determined through issuance of a major NSR 
permit within the past 10 years. However, the emissions unit is not 
eligible for the Clean Unit designation if the BACT determination 
resulted in no requirement to reduce emissions below the level of a 
standard, uncontrolled, new emissions unit of the same type.
    (b) The owner or operator made an investment to install the control 
technology. For the purpose of this determination, an investment 
includes expenses to research the application of a pollution prevention 
technique to the emissions unit or expenses to apply a pollution 
prevention technique to an emissions unit.
    (iii) Re-qualifying for the Clean Unit designation. The emissions 
unit must obtain a new major NSR permit that requires compliance with 
the current-day BACT (or LAER), and the emissions unit must meet the 
requirements in paragraphs (t)(3)(i) and (t)(3)(ii) of this section.
    (4) Effective date of the Clean Unit designation. The effective date 
of an emissions unit's Clean Unit designation (that is, the date on 
which the owner or operator may begin to use the Clean Unit Test to 
determine whether a project at the emissions unit is a major 
modification) is determined according to the applicable paragraph 
(t)(4)(i) or (t)(4)(ii) of this section.
    (i) Original Clean Unit designation, and emissions units that re-
qualify as Clean Units by implementing a new control technology to meet 
current-day BACT. The effective date is the date the emissions unit's 
air pollution control technology is placed into service, or 3 years 
after the issuance date of the major NSR permit, whichever is earlier, 
but no sooner than the date that provisions for the Clean Unit 
applicability test are approved by the Administrator for incorporation 
into the plan and become effective for the State in which the unit is 
located.
    (ii) Emissions Units that re-qualify for the Clean Unit designation 
using an existing control technology. The effective date is the date the 
new, major NSR permit is issued.
    (5) Clean Unit expiration. An emissions unit's Clean Unit 
designation expires (that is, the date on which the owner or operator 
may no longer use the Clean Unit Test to determine whether a project 
affecting the emissions unit is, or is part of, a major modification) 
according to the applicable paragraph (t)(5)(i) or (ii) of this section.
    (i) Original Clean Unit designation, and emissions units that re-
qualify by implementing new control technology to meet current-day BACT. 
For any emissions unit that automatically qualifies as a Clean Unit 
under paragraphs (t)(3)(i) and (ii) of this section or re-qualifies by 
implementing new control technology to meet current-day BACT

[[Page 253]]

under paragraph (t)(3)(iii) of this section, the Clean Unit designation 
expires 10 years after the effective date, or the date the equipment 
went into service, whichever is earlier; or, it expires at any time the 
owner or operator fails to comply with the provisions for maintaining 
the Clean Unit designation in paragraph (t)(7) of this section.
    (ii) Emissions units that re-qualify for the Clean Unit designation 
using an existing control technology. For any emissions unit that re-
qualifies as a Clean Unit under paragraph (t)(3)(iii) of this section 
using an existing control technology, the Clean Unit designation expires 
10 years after the effective date; or, it expires any time the owner or 
operator fails to comply with the provisions for maintaining the Clean 
Unit designation in paragraph (t)(7) of this section.
    (6) Required title V permit content for a Clean Unit. After the 
effective date of the Clean Unit designation, and in accordance with the 
provisions of the applicable title V permit program under part 70 or 
part 71 of this chapter, but no later than when the title V permit is 
renewed, the title V permit for the major stationary source must include 
the following terms and conditions related to the Clean Unit in 
paragraphs (t)(6)(i) through (vi) of this section.
    (i) A statement indicating that the emissions unit qualifies as a 
Clean Unit and identifying the pollutant(s) for which this Clean Unit 
designation applies.
    (ii) The effective date of the Clean Unit designation. If this date 
is not known when the Clean Unit designation is initially recorded in 
the title V permit (e.g., because the air pollution control technology 
is not yet in service), the permit must describe the event that will 
determine the effective date (e.g., the date the control technology is 
placed into service). Once the effective date is determined, the owner 
or operator must notify the reviewing authority of the exact date. This 
specific effective date must be added to the source's title V permit at 
the first opportunity, such as a modification, revision, reopening, or 
renewal of the title V permit for any reason, whichever comes first, but 
in no case later than the next renewal.
    (iii) The expiration date of the Clean Unit designation. If this 
date is not known when the Clean Unit designation is initially recorded 
into the title V permit (e.g., because the air pollution control 
technology is not yet in service), then the permit must describe the 
event that will determine the expiration date (e.g., the date the 
control technology is placed into service). Once the expiration date is 
determined, the owner or operator must notify the reviewing authority of 
the exact date. The expiration date must be added to the source's title 
V permit at the first opportunity, such as a modification, revision, 
reopening, or renewal of the title V permit for any reason, whichever 
comes first, but in no case later than the next renewal.
    (iv) All emission limitations and work practice requirements adopted 
in conjunction with BACT, and any physical or operational 
characteristics that formed the basis for the BACT determination (e.g., 
possibly the emissions unit's capacity or throughput).
    (v) Monitoring, recordkeeping, and reporting requirements as 
necessary to demonstrate that the emissions unit continues to meet the 
criteria for maintaining the Clean Unit designation. (See paragraph 
(t)(7) of this section.)
    (vi) Terms reflecting the owner or operator's duties to maintain the 
Clean Unit designation and the consequences of failing to do so, as 
presented in paragraph (t)(7) of this section.
    (7) Maintaining the Clean Unit designation. To maintain the Clean 
Unit designation, the owner or operator must conform to all the 
restrictions listed in paragraphs (t)(7)(i) through (iii) of this 
section. This paragraph (t)(7) applies independently to each pollutant 
for which the emissions unit has the Clean Unit designation. That is, 
failing to conform to the restrictions for one pollutant affects the 
Clean Unit designation only for that pollutant.
    (i) The Clean Unit must comply with the emission limitation(s) and/
or work practice requirements adopted in conjunction with the BACT that 
is recorded in the major NSR permit, and subsequently reflected in the 
title V permit. The owner or operator may not make a physical change in 
or change in

[[Page 254]]

the method of operation of the Clean Unit that causes the emissions unit 
to function in a manner that is inconsistent with the physical or 
operational characteristics that formed the basis for the BACT 
determination (e.g., possibly the emissions unit's capacity or 
throughput).
    (ii) The Clean Unit must comply with any terms and conditions in the 
title V permit related to the unit's Clean Unit designation.
    (iii) The Clean Unit must continue to control emissions using the 
specific air pollution control technology that was the basis for its 
Clean Unit designation. If the emissions unit or control technology is 
replaced, then the Clean Unit designation ends.
    (8) Netting at Clean Units. Emissions changes that occur at a Clean 
Unit must not be included in calculating a significant net emissions 
increase (that is, must not be used in a ``netting analysis''), unless 
such use occurs before the effective date of the Clean Unit designation, 
or after the Clean Unit designation expires; or, unless the emissions 
unit reduces emissions below the level that qualified the unit as a 
Clean Unit. However, if the Clean Unit reduces emissions below the level 
that qualified the unit as a Clean Unit, then the owner or operator may 
generate a credit for the difference between the level that qualified 
the unit as a Clean Unit and the new emission limitation if such 
reductions are surplus, quantifiable, and permanent. For purposes of 
generating offsets, the reductions must also be federally enforceable. 
For purposes of determining creditable net emissions increases and 
decreases, the reductions must also be enforceable as a practical 
matter.
    (9) Effect of redesignation on the Clean Unit designation. The Clean 
Unit designation of an emissions unit is not affected by redesignation 
of the attainment status of the area in which it is located. That is, if 
a Clean Unit is located in an attainment area and the area is 
redesignated to nonattainment, its Clean Unit designation is not 
affected. Similarly, redesignation from nonattainment to attainment does 
not affect the Clean Unit designation. However, if an existing Clean 
Unit designation expires, it must re-qualify under the requirements that 
are currently applicable in the area.
    (u) Clean Unit provisions for emissions units that achieve an 
emission limitation comparable to BACT. The plan shall provide an owner 
or operator of a major stationary source the option of using the Clean 
Unit Test to determine whether emissions increases at a Clean Unit are 
part of a project that is a major modification according to the 
provisions in paragraphs (u)(1) through (11) of this section.
    (1) Applicability. The provisions of this paragraph (u) apply to 
emissions units which do not qualify as Clean Units under paragraph (t) 
of this section, but which are achieving a level of emissions control 
comparable to BACT, as determined by the reviewing authority in 
accordance with this paragraph (u).
    (2) General provisions for Clean Units. The provisions in paragraphs 
(u)(2)(i) through (iv) of this section apply to a Clean Unit.
    (i) Any project for which the owner or operator begins actual 
construction after the effective date of the Clean Unit designation (as 
determined in accordance with paragraph (u)(5) of this section) and 
before the expiration date (as determined in accordance with paragraph 
(u)(6) of this section) will be considered to have occurred while the 
emissions unit was a Clean Unit.
    (ii) If a project at a Clean Unit does not cause the need for a 
change in the emission limitations or work practice requirements in the 
permit for the unit that have been determined (pursuant to paragraph 
(u)(4) of this section) to be comparable to BACT, and the project would 
not alter any physical or operational characteristics that formed the 
basis for determining that the emissions unit's control technology 
achieves a level of emissions control comparable to BACT as specified in 
paragraph (u)(8)(iv) of this section, the emissions unit remains a Clean 
Unit.
    (iii) If a project causes the need for a change in the emission 
limitations or work practice requirements in the permit for the unit 
that have been determined (pursuant to paragraph (u)(4) of this section) 
to be comparable to BACT, or the project would alter any physical or 
operational characteristics

[[Page 255]]

that formed the basis for determining that the emissions unit's control 
technology achieves a level of emissions control comparable to BACT as 
specified in paragraph (u)(8)(iv) of this section, then the emissions 
unit loses its designation as a Clean Unit upon issuance of the 
necessary permit revisions (unless the unit re-qualifies as a Clean Unit 
pursuant to paragraph (u)(3)(iv) of this section). If the owner or 
operator begins actual construction on the project without first 
applying to revise the emissions unit's permit, the Clean Unit 
designation ends immediately prior to the time when actual construction 
begins.
    (iv) A project that causes an emissions unit to lose its designation 
as a Clean Unit is subject to the applicability requirements of 
paragraphs (a)(7)(iv)(a) through (d) and paragraph (a)(7)(iv)(f) of this 
section as if the emissions unit is not a Clean Unit.
    (3) Qualifying or re-qualifying to use the Clean Unit applicability 
test. An emissions unit qualifies as a Clean Unit when the unit meets 
the criteria in paragraphs (u)(3)(i) through (iii) of this section. 
After the original Clean Unit designation expires in accordance with 
paragraph (u)(6) of this section or is lost pursuant to paragraph 
(u)(2)(iii) of this section, such emissions unit may re-qualify as a 
Clean Unit under either paragraph (u)(3)(iv) of this section, or under 
the Clean Unit provisions in paragraph (t) of this section. To re-
qualify as a Clean Unit under paragraph (u)(3)(iv) of this section, the 
emissions unit must obtain a new permit issued pursuant to the 
requirements in paragraphs (u)(7) and (8) of this section and meet all 
the criteria in paragraph (u)(3)(iv) of this section. The reviewing 
authority will make a separate Clean Unit designation for each pollutant 
emitted by the emissions unit for which the emissions unit qualifies as 
a Clean Unit.
    (i) Qualifying air pollution control technologies. Air pollutant 
emissions from the emissions unit must be reduced through the use of air 
pollution control technology (which includes pollution prevention as 
defined under paragraph (b)(38) or work practices) that meets both the 
following requirements in paragraphs (u)(3)(i)(a) and (b) of this 
section.
    (a) The owner or operator has demonstrated that the emissions unit's 
control technology is comparable to BACT according to the requirements 
of paragraph (u)(4) of this section. However, the emissions unit is not 
eligible for the Clean Unit designation if its emissions are not reduced 
below the level of a standard, uncontrolled emissions unit of the same 
type (e.g., if the BACT determinations to which it is compared have 
resulted in a determination that no control measures are required).
    (b) The owner or operator made an investment to install the control 
technology. For the purpose of this determination, an investment 
includes expenses to research the application of a pollution prevention 
technique to the emissions unit or to retool the unit to apply a 
pollution prevention technique.
    (ii) Impact of emissions from the unit. The reviewing authority must 
determine that the allowable emissions from the emissions unit will not 
cause or contribute to a violation of any national ambient air quality 
standard or PSD increment, or adversely impact an air quality related 
value (such as visibility) that has been identified for a Federal Class 
I area by a Federal Land Manager and for which information is available 
to the general public.
    (iii) Date of installation. An emissions unit may qualify as a Clean 
Unit even if the control technology, on which the Clean Unit designation 
is based, was installed before the effective date of plan requirements 
to implement the requirements of this paragraph (u)(3)(iii). However, 
for such emissions units, the owner or operator must apply for the Clean 
Unit designation within 2 years after the plan requirements become 
effective. For technologies installed after the plan requirements become 
effective, the owner or operator must apply for the Clean Unit 
designation at the time the control technology is installed.
    (iv) Re-qualifying as a Clean Unit. The emissions unit must obtain a 
new permit (pursuant to requirements in paragraphs (u)(7) and (8) of 
this section) that demonstrates that the emissions unit's control 
technology is achieving

[[Page 256]]

a level of emission control comparable to current-day BACT, and the 
emissions unit must meet the requirements in paragraphs (u)(3)(i)(a) and 
(u)(3)(ii) of this section.
    (4) Demonstrating control effectiveness comparable to BACT. The 
owner or operator may demonstrate that the emissions unit's control 
technology is comparable to BACT for purposes of paragraph (u)(3)(i) of 
this section according to either paragraph (u)(4)(i) or (ii) of this 
section. Paragraph (u)(4)(iii) of this section specifies the time for 
making this comparison.
    (i) Comparison to previous BACT and LAER determinations. The 
Administrator maintains an on-line data base of previous determinations 
of RACT, BACT, and LAER in the RACT/BACT/LAER Clearinghouse (RBLC). The 
emissions unit's control technology is presumed to be comparable to BACT 
if it achieves an emission limitation that is equal to or better than 
the average of the emission limitations achieved by all the sources for 
which a BACT or LAER determination has been made within the preceding 5 
years and entered into the RBLC, and for which it is technically 
feasible to apply the BACT or LAER control technology to the emissions 
unit. The reviewing authority shall also compare this presumption to any 
additional BACT or LAER determinations of which it is aware, and shall 
consider any information on achieved-in-practice pollution control 
technologies provided during the public comment period, to determine 
whether any presumptive determination that the control technology is 
comparable to BACT is correct.
    (ii) The substantially-as-effective test. The owner or operator may 
demonstrate that the emissions unit's control technology is 
substantially as effective as BACT. In addition, any other person may 
present evidence related to whether the control technology is 
substantially as effective as BACT during the public participation 
process required under paragraph (u)(7) of this section. The reviewing 
authority shall consider such evidence on a case-by-case basis and 
determine whether the emissions unit's air pollution control technology 
is substantially as effective as BACT.
    (iii) Time of comparison--(a) Emissions units with control 
technologies that are installed before the effective date of plan 
requirements implementing this paragraph. The owner or operator of an 
emissions unit whose control technology is installed before the 
effective date of plan requirements implementing this paragraph (u) may, 
at its option, either demonstrate that the emission limitation achieved 
by the emissions unit's control technology is comparable to the BACT 
requirements that applied at the time the control technology was 
installed, or demonstrate that the emission limitation achieved by the 
emissions unit's control technology is comparable to current-day BACT 
requirements. The expiration date of the Clean Unit designation will 
depend on which option the owner or operator uses, as specified in 
paragraph (u)(6) of this section.
    (b) Emissions units with control technologies that are installed 
after the effective date of plan requirements implementing this 
paragraph. The owner or operator must demonstrate that the emission 
limitation achieved by the emissions unit's control technology is 
comparable to current-day BACT requirements.
    (5) Effective date of the Clean Unit designation. The effective date 
of an emissions unit's Clean Unit designation (that is, the date on 
which the owner or operator may begin to use the Clean Unit Test to 
determine whether a project involving the emissions unit is a major 
modification) is the date that the permit required by paragraph (u)(7) 
of this section is issued or the date that the emissions unit's air 
pollution control technology is placed into service, whichever is later.
    (6) Clean Unit expiration. If the owner or operator demonstrates 
that the emission limitation achieved by the emissions unit's control 
technology is comparable to the BACT requirements that applied at the 
time the control technology was installed, then the Clean Unit 
designation expires 10 years from the date that the control technology 
was installed. For all other

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emissions units, the Clean Unit designation expires 10 years from the 
effective date of the Clean Unit designation, as determined according to 
paragraph (u)(5) of this section. In addition, for all emissions units, 
the Clean Unit designation expires any time the owner or operator fails 
to comply with the provisions for maintaining the Clean Unit designation 
in paragraph (u)(9) of this section.
    (7) Procedures for designating emissions units as Clean Units. The 
reviewing authority shall designate an emissions unit a Clean Unit only 
by issuing a permit through a permitting program that has been approved 
by the Administrator and that conforms with the requirements of 
Sec. Sec. 51.160 through 51.164 of this chapter, including requirements 
for public notice of the proposed Clean Unit designation and opportunity 
for public comment. Such permit must also meet the requirements in 
paragraph (u)(8) of this section.
    (8) Required permit content. The permit required by paragraph (u)(7) 
of this section shall include the terms and conditions set forth in 
paragraphs (u)(8)(i) through (vi). Such terms and conditions shall be 
incorporated into the major stationary source's title V permit in 
accordance with the provisions of the applicable title V permit program 
under part 70 or part 71 of this chapter, but no later than when the 
title V permit is renewed.
    (i) A statement indicating that the emissions unit qualifies as a 
Clean Unit and identifying the pollutant(s) for which the Clean Unit 
designation applies.
    (ii) The effective date of the Clean Unit designation. If this date 
is not known when the reviewing authority issues the permit (e.g., 
because the air pollution control technology is not yet in service), 
then the permit must describe the event that will determine the 
effective date (e.g., the date the control technology is placed into 
service). Once the effective date is known, then the owner or operator 
must notify the reviewing authority of the exact date. This specific 
effective date must be added to the source's title V permit at the first 
opportunity, such as a modification, revision, reopening, or renewal of 
the title V permit for any reason, whichever comes first, but in no case 
later than the next renewal.
    (iii) The expiration date of the Clean Unit designation. If this 
date is not known when the reviewing authority issues the permit (e.g., 
because the air pollution control technology is not yet in service), 
then the permit must describe the event that will determine the 
expiration date (e.g., the date the control technology is placed into 
service). Once the expiration date is known, then the owner or operator 
must notify the reviewing authority of the exact date. The expiration 
date must be added to the source's title V permit at the first 
opportunity, such as a modification, revision, reopening, or renewal of 
the title V permit for any reason, whichever comes first, but in no case 
later than the next renewal.
    (iv) All emission limitations and work practice requirements adopted 
in conjunction with emission limitations necessary to assure that the 
control technology continues to achieve an emission limitation 
comparable to BACT, and any physical or operational characteristics that 
formed the basis for determining that the emissions unit's control 
technology achieves a level of emissions control comparable to BACT 
(e.g., possibly the emissions unit's capacity or throughput).
    (v) Monitoring, recordkeeping, and reporting requirements as 
necessary to demonstrate that the emissions unit continues to meet the 
criteria for maintaining its Clean Unit designation. (See paragraph 
(u)(9) of this section.)
    (vi) Terms reflecting the owner or operator's duties to maintain the 
Clean Unit designation and the consequences of failing to do so, as 
presented in paragraph (u)(9) of this section.
    (9) Maintaining the Clean Unit designation. To maintain the Clean 
Unit designation, the owner or operator must conform to all the 
restrictions listed in paragraphs (u)(9)(i) through (v) of this section. 
This paragraph (u)(9) applies independently to each pollutant for which 
the reviewing authority has designated the emissions unit a Clean Unit. 
That is, failing to conform to the restrictions for one pollutant 
affects the Clean Unit designation only for that pollutant.

[[Page 258]]

    (i) The Clean Unit must comply with the emission limitation(s) and/
or work practice requirements adopted to ensure that the control 
technology continues to achieve emission control comparable to BACT.
    (ii) The owner or operator may not make a physical change in or 
change in the method of operation of the Clean Unit that causes the 
emissions unit to function in a manner that is inconsistent with the 
physical or operational characteristics that formed the basis for the 
determination that the control technology is achieving a level of 
emission control that is comparable to BACT (e.g., possibly the 
emissions unit's capacity or throughput).
    (iii) [Reserved]
    (iv) The Clean Unit must comply with any terms and conditions in the 
title V permit related to the unit's Clean Unit designation.
    (v) The Clean Unit must continue to control emissions using the 
specific air pollution control technology that was the basis for its 
Clean Unit designation. If the emissions unit or control technology is 
replaced, then the Clean Unit designation ends.
    (10) Netting at Clean Units. Emissions changes that occur at a Clean 
Unit must not be included in calculating a significant net emissions 
increase (that is, must not be used in a ``netting analysis'') unless 
such use occurs before the effective date of plan requirements adopted 
to implement this paragraph (u) or after the Clean Unit designation 
expires; or, unless the emissions unit reduces emissions below the level 
that qualified the unit as a Clean Unit. However, if the Clean Unit 
reduces emissions below the level that qualified the unit as a Clean 
Unit, then the owner or operator may generate a credit for the 
difference between the level that qualified the unit as a Clean Unit and 
the emissions unit's new emission limitation if such reductions are 
surplus, quantifiable, and permanent. For purposes of generating 
offsets, the reductions must also be federally enforceable. For purposes 
of determining creditable net emissions increases and decreases, the 
reductions must also be enforceable as a practical matter.
    (11) Effect of redesignation on the Clean Unit designation. The 
Clean Unit designation of an emissions unit is not affected by 
redesignation of the attainment designation of the area in which it is 
located. That is, if a Clean Unit is located in an attainment area and 
the area is redesignated to nonattainment, its Clean Unit designation is 
not affected. Similarly, redesignation from nonattainment to attainment 
does not affect the Clean Unit designation. However, if a Clean Unit's 
designation expires or is lost pursuant to paragraphs (t)(2)(iii) and 
(u)(2)(iii) of this section, it must re-qualify under the requirements 
that are currently applicable.
    (v) PCP exclusion procedural requirements. Each plan shall include 
provisions for PCPs equivalent to those contained in paragraphs (v)(1) 
through (6) of this section.
    (1) Before an owner or operator begins actual construction of a PCP, 
the owner or operator must either submit a notice to the reviewing 
authority if the project is listed in paragraphs (b)(31)(i) through (vi) 
of this section, or if the project is not listed in paragraphs 
(b)(31)(i) through (vi) of this section, then the owner or operator must 
submit a permit application and obtain approval to use the PCP exclusion 
from the reviewing authority consistent with the requirements in 
paragraph (v)(5) of this section. Regardless of whether the owner or 
operator submits a notice or a permit application, the project must meet 
the requirements in paragraph (v)(2) of this section, and the notice or 
permit application must contain the information required in paragraph 
(v)(3) of this section.
    (2) Any project that relies on the PCP exclusion must meet the 
requirements in paragraphs (v)(2)(i) and (ii) of this section.
    (i) Environmentally beneficial analysis. The environmental benefit 
from the emission reductions of pollutants regulated under the Act must 
outweigh the environmental detriment of emissions increases in 
pollutants regulated under the Act. A statement that a technology from 
paragraphs (b)(31)(i) through (vi) of this section is being used shall 
be presumed to satisfy this requirement.
    (ii) Air quality analysis. The emissions increases from the project 
will not cause or contribute to a violation of any national ambient air 
quality

[[Page 259]]

standard or PSD increment, or adversely impact an air quality related 
value (such as visibility) that has been identified for a Federal Class 
I area by a Federal Land Manager and for which information is available 
to the general public.
    (3) Content of notice or permit application. In the notice or permit 
application sent to the reviewing authority, the owner or operator must 
include, at a minimum, the information listed in paragraphs (v)(3)(i) 
through (v) of this section.
    (i) A description of the project.
    (ii) The potential emissions increases and decreases of any 
pollutant regulated under the Act and the projected emissions increases 
and decreases using the methodology in paragraph (a)(7)(vi) of this 
section, that will result from the project, and a copy of the 
environmentally beneficial analysis required by paragraph (v)(2)(i) of 
this section.
    (iii) A description of monitoring and recordkeeping, and all other 
methods, to be used on an ongoing basis to demonstrate that the project 
is environmentally beneficial. Methods should be sufficient to meet the 
requirements in part 70 and part 71.
    (iv) A certification that the project will be designed and operated 
in a manner that is consistent with proper industry and engineering 
practices, in a manner that is consistent with the environmentally 
beneficial analysis and air quality analysis required by paragraphs 
(v)(2)(i) and (ii) of this section, with information submitted in the 
notice or permit application, and in such a way as to minimize, within 
the physical configuration and operational standards usually associated 
with the emissions control device or strategy, emissions of collateral 
pollutants.
    (v) Demonstration that the PCP will not have an adverse air quality 
impact (e.g., modeling, screening level modeling results, or a statement 
that the collateral emissions increase is included within the parameters 
used in the most recent modeling exercise) as required by paragraph 
(v)(2)(ii) of this section. An air quality impact analysis is not 
required for any pollutant that will not experience a significant 
emissions increase as a result of the project.
    (4) Notice process for listed projects. For projects listed in 
paragraphs (b)(31)(i) through (vi) of this section, the owner or 
operator may begin actual construction of the project immediately after 
notice is sent to the reviewing authority (unless otherwise prohibited 
under requirements of the applicable plan). The owner or operator shall 
respond to any requests by its reviewing authority for additional 
information that the reviewing authority determines is necessary to 
evaluate the suitability of the project for the PCP exclusion.
    (5) Permit process for unlisted projects. Before an owner or 
operator may begin actual construction of a PCP project that is not 
listed in paragraphs (b)(31)(i) through (vi) of this section, the 
project must be approved by the reviewing authority and recorded in a 
plan-approved permit or title V permit using procedures that are 
consistent with Sec. Sec. 51.160 and 51.161 of this chapter. This 
includes the requirement that the reviewing authority provide the public 
with notice of the proposed approval, with access to the environmentally 
beneficial analysis and the air quality analysis, and provide at least a 
30-day period for the public and the Administrator to submit comments. 
The reviewing authority must address all material comments received by 
the end of the comment period before taking final action on the permit.
    (6) Operational requirements. Upon installation of the PCP, the 
owner or operator must comply with the requirements of paragraphs 
(v)(6)(i) through (iv) of this section.
    (i) General duty. The owner or operator must operate the PCP 
consistent with proper industry and engineering practices, in a manner 
that is consistent with the environmentally beneficial analysis and air 
quality analysis required by paragraphs (v)(2)(i) and (ii) of this 
section, with information submitted in the notice or permit application 
required by paragraph (v)(3), and in such a way as to minimize, within 
the physical configuration and operational standards usually associated 
with the emissions control device or strategy, emissions of collateral 
pollutants.

[[Page 260]]

    (ii) Recordkeeping. The owner or operator must maintain copies on 
site of the environmentally beneficial analysis, the air quality impacts 
analysis, and monitoring and other emission records to prove that the 
PCP operated consistent with the general duty requirements in paragraph 
(v)(6)(i) of this section.
    (iii) Permit requirements. The owner or operator must comply with 
any provisions in the plan-approved permit or title V permit related to 
use and approval of the PCP exclusion.
    (iv) Generation of Emission Reduction Credits. Emission reductions 
created by a PCP shall not be included in calculating a significant net 
emissions increase unless the emissions unit further reduces emissions 
after qualifying for the PCP exclusion (e.g., taking an operational 
restriction on the hours of operation.) The owner or operator may 
generate a credit for the difference between the level of reduction 
which was used to qualify for the PCP exclusion and the new emission 
limitation if such reductions are surplus, quantifiable, and permanent. 
For purposes of generating offsets, the reductions must also be 
federally enforceable. For purposes of determining creditable net 
emissions increases and decreases, the reductions must also be 
enforceable as a practical matter.
    (w) Actuals PALs. The plan shall provide for PALs according to the 
provisions in paragraphs (w)(1) through (15) of this section.
    (1) Applicability. (i) The reviewing authority may approve the use 
of an actuals PAL for any existing major stationary source if the PAL 
meets the requirements in paragraphs (w)(1) through (15) of this 
section. The term ``PAL'' shall mean ``actuals PAL'' throughout 
paragraph (w) of this section.
    (ii) Any physical change in or change in the method of operation of 
a major stationary source that maintains its total source-wide emissions 
below the PAL level, meets the requirements in paragraphs (w)(1) through 
(15) of this section, and complies with the PAL permit:
    (a) Is not a major modification for the PAL pollutant;
    (b) Does not have to be approved through the plan's major NSR 
program; and
    (c) Is not subject to the provisions in paragraph (r)(2) of this 
section (restrictions on relaxing enforceable emission limitations that 
the major stationary source used to avoid applicability of the major NSR 
program).
    (iii) Except as provided under paragraph (w)(1)(ii)(c) of this 
section, a major stationary source shall continue to comply with all 
applicable Federal or State requirements, emission limitations, and work 
practice requirements that were established prior to the effective date 
of the PAL.
    (2) Definitions. The plan shall use the definitions in paragraphs 
(w)(2)(i) through (xi) of this section for the purpose of developing and 
implementing regulations that authorize the use of actuals PALs 
consistent with paragraphs (w)(1) through (15) of this section. When a 
term is not defined in these paragraphs, it shall have the meaning given 
in paragraph (b) of this section or in the Act.
    (i) Actuals PAL for a major stationary source means a PAL based on 
the baseline actual emissions (as defined in paragraph (b)(47) of this 
section) of all emissions units (as defined in paragraph (b)(7) of this 
section) at the source, that emit or have the potential to emit the PAL 
pollutant.
    (ii) Allowable emissions means ``allowable emissions'' as defined in 
paragraph (b)(16) of this section, except as this definition is modified 
according to paragraphs (w)(2)(ii)(a) and (b) of this section.
    (a) The allowable emissions for any emissions unit shall be 
calculated considering any emission limitations that are enforceable as 
a practical matter on the emissions unit's potential to emit.
    (b) An emissions unit's potential to emit shall be determined using 
the definition in paragraph (b)(4) of this section, except that the 
words ``or enforceable as a practical matter'' should be added after 
``federally enforceable.''
    (iii) Small emissions unit means an emissions unit that emits or has 
the potential to emit the PAL pollutant in an amount less than the 
significant level for that PAL pollutant, as defined

[[Page 261]]

in paragraph (b)(23) of this section or in the Act, whichever is lower.
    (iv) Major emissions unit means:
    (a) Any emissions unit that emits or has the potential to emit 100 
tons per year or more of the PAL pollutant in an attainment area; or
    (b) Any emissions unit that emits or has the potential to emit the 
PAL pollutant in an amount that is equal to or greater than the major 
source threshold for the PAL pollutant as defined by the Act for 
nonattainment areas. For example, in accordance with the definition of 
major stationary source in section 182(c) of the Act, an emissions unit 
would be a major emissions unit for VOC if the emissions unit is located 
in a serious ozone nonattainment area and it emits or has the potential 
to emit 50 or more tons of VOC per year.
    (v) Plantwide applicability limitation (PAL) means an emission 
limitation expressed in tons per year, for a pollutant at a major 
stationary source, that is enforceable as a practical matter and 
established source-wide in accordance with paragraphs (w)(1) through 
(15) of this section.
    (vi) PAL effective date generally means the date of issuance of the 
PAL permit. However, the PAL effective date for an increased PAL is the 
date any emissions unit that is part of the PAL major modification 
becomes operational and begins to emit the PAL pollutant.
    (vii) PAL effective period means the period beginning with the PAL 
effective date and ending 10 years later.
    (viii) PAL major modification means, notwithstanding paragraphs 
(b)(2) and (b)(3) of this section (the definitions for major 
modification and net emissions increase), any physical change in or 
change in the method of operation of the PAL source that causes it to 
emit the PAL pollutant at a level equal to or greater than the PAL.
    (ix) PAL permit means the major NSR permit, the minor NSR permit, or 
the State operating permit under a program that is approved into the 
plan, or the title V permit issued by the reviewing authority that 
establishes a PAL for a major stationary source.
    (x) PAL pollutant means the pollutant for which a PAL is established 
at a major stationary source.
    (xi) Significant emissions unit means an emissions unit that emits 
or has the potential to emit a PAL pollutant in an amount that is equal 
to or greater than the significant level (as defined in paragraph 
(b)(23) of this section or in the Act, whichever is lower) for that PAL 
pollutant, but less than the amount that would qualify the unit as a 
major emissions unit as defined in paragraph (w)(2)(iv) of this section.
    (3) Permit application requirements. As part of a permit application 
requesting a PAL, the owner or operator of a major stationary source 
shall submit the following information in paragraphs (w)(3)(i) through 
(iii) of this section to the reviewing authority for approval.
    (i) A list of all emissions units at the source designated as small, 
significant or major based on their potential to emit. In addition, the 
owner or operator of the source shall indicate which, if any, Federal or 
State applicable requirements, emission limitations, or work practices 
apply to each unit.
    (ii) Calculations of the baseline actual emissions (with supporting 
documentation). Baseline actual emissions are to include emissions 
associated not only with operation of the unit, but also emissions 
associated with startup, shutdown, and malfunction.
    (iii) The calculation procedures that the major stationary source 
owner or operator proposes to use to convert the monitoring system data 
to monthly emissions and annual emissions based on a 12-month rolling 
total for each month as required by paragraph (w)(13)(i) of this 
section.
    (4) General requirements for establishing PALs. (i) The plan allows 
the reviewing authority to establish a PAL at a major stationary source, 
provided that at a minimum, the requirements in paragraphs (w)(4)(i)(a) 
through (g) of this section are met.
    (a) The PAL shall impose an annual emission limitation in tons per 
year, that is enforceable as a practical matter, for the entire major 
stationary source. For each month during the PAL effective period after 
the first 12 months of establishing a PAL, the major stationary source 
owner or operator shall show that the sum of the

[[Page 262]]

monthly emissions from each emissions unit under the PAL for the 
previous 12 consecutive months is less than the PAL (a 12-month average, 
rolled monthly). For each month during the first 11 months from the PAL 
effective date, the major stationary source owner or operator shall show 
that the sum of the preceding monthly emissions from the PAL effective 
date for each emissions unit under the PAL is less than the PAL.
    (b) The PAL shall be established in a PAL permit that meets the 
public participation requirements in paragraph (w)(5) of this section.
    (c) The PAL permit shall contain all the requirements of paragraph 
(w)(7) of this section.
    (d) The PAL shall include fugitive emissions, to the extent 
quantifiable, from all emissions units that emit or have the potential 
to emit the PAL pollutant at the major stationary source.
    (e) Each PAL shall regulate emissions of only one pollutant.
    (f) Each PAL shall have a PAL effective period of 10 years.
    (g) The owner or operator of the major stationary source with a PAL 
shall comply with the monitoring, recordkeeping, and reporting 
requirements provided in paragraphs (w)(12) through (14) of this section 
for each emissions unit under the PAL through the PAL effective period.
    (ii) At no time (during or after the PAL effective period) are 
emissions reductions of a PAL pollutant that occur during the PAL 
effective period creditable as decreases for purposes of offsets under 
Sec. 51.165(a)(3)(ii) of this chapter unless the level of the PAL is 
reduced by the amount of such emissions reductions and such reductions 
would be creditable in the absence of the PAL.
    (5) Public participation requirements for PALs. PALs for existing 
major stationary sources shall be established, renewed, or increased, 
through a procedure that is consistent with Sec. Sec. 51.160 and 51.161 
of this chapter. This includes the requirement that the reviewing 
authority provide the public with notice of the proposed approval of a 
PAL permit and at least a 30-day period for submittal of public comment. 
The reviewing authority must address all material comments before taking 
final action on the permit.
    (6) Setting the 10-year actuals PAL level. (i) Except as provided in 
paragraph (w)(6)(ii) of this section, the plan shall provide that the 
actuals PAL level for a major stationary source shall be established as 
the sum of the baseline actual emissions (as defined in paragraph 
(b)(47) of this section) of the PAL pollutant for each emissions unit at 
the source; plus an amount equal to the applicable significant level for 
the PAL pollutant under paragraph (b)(23) of this section or under the 
Act, whichever is lower. When establishing the actuals PAL level, for a 
PAL pollutant, only one consecutive 24-month period must be used to 
determine the baseline actual emissions for all existing emissions 
units. However, a different consecutive 24-month period may be used for 
each different PAL pollutant. Emissions associated with units that were 
permanently shut down after this 24-month period must be subtracted from 
the PAL level. The reviewing authority shall specify a reduced PAL 
level(s) (in tons/yr) in the PAL permit to become effective on the 
future compliance date(s) of any applicable Federal or State regulatory 
requirement(s) that the reviewing authority is aware of prior to 
issuance of the PAL permit. For instance, if the source owner or 
operator will be required to reduce emissions from industrial boilers in 
half from baseline emissions of 60 ppm NOX to a new rule 
limit of 30 ppm, then the permit shall contain a future effective PAL 
level that is equal to the current PAL level reduced by half of the 
original baseline emissions of such unit(s).
    (ii) For newly constructed units (which do not include modifications 
to existing units) on which actual construction began after the 24-month 
period, in lieu of adding the baseline actual emissions as specified in 
paragraph (w)(6)(i) of this section, the emissions must be added to the 
PAL level in an amount equal to the potential to emit of the units.
    (7) Contents of the PAL permit. The plan shall require that the PAL 
permit contain, at a minimum, the information in paragraphs (w)(7)(i) 
through (x) of this section.

[[Page 263]]

    (i) The PAL pollutant and the applicable source-wide emission 
limitation in tons per year.
    (ii) The PAL permit effective date and the expiration date of the 
PAL (PAL effective period).
    (iii) Specification in the PAL permit that if a major stationary 
source owner or operator applies to renew a PAL in accordance with 
paragraph (w)(10) of this section before the end of the PAL effective 
period, then the PAL shall not expire at the end of the PAL effective 
period. It shall remain in effect until a revised PAL permit is issued 
by the reviewing authority.
    (iv) A requirement that emission calculations for compliance 
purposes include emissions from startups, shutdowns and malfunctions.
    (v) A requirement that, once the PAL expires, the major stationary 
source is subject to the requirements of paragraph (w)(9) of this 
section.
    (vi) The calculation procedures that the major stationary source 
owner or operator shall use to convert the monitoring system data to 
monthly emissions and annual emissions based on a 12-month rolling total 
for each month as required by paragraph (w)(3)(i) of this section.
    (vii) A requirement that the major stationary source owner or 
operator monitor all emissions units in accordance with the provisions 
under paragraph (w)(13) of this section.
    (viii) A requirement to retain the records required under paragraph 
(w)(13) of this section on site. Such records may be retained in an 
electronic format.
    (ix) A requirement to submit the reports required under paragraph 
(w)(14) of this section by the required deadlines.
    (x) Any other requirements that the reviewing authority deems 
necessary to implement and enforce the PAL.
    (8) PAL effective period and reopening of the PAL permit. The plan 
shall require the information in paragraphs (w)(8)(i) and (ii) of this 
section.
    (i) PAL effective period. The reviewing authority shall specify a 
PAL effective period of 10 years.
    (ii) Reopening of the PAL permit. (a) During the PAL effective 
period, the plan shall require the reviewing authority to reopen the PAL 
permit to:
    (1) Correct typographical/calculation errors made in setting the PAL 
or reflect a more accurate determination of emissions used to establish 
the PAL;
    (2) Reduce the PAL if the owner or operator of the major stationary 
source creates creditable emissions reductions for use as offsets under 
Sec. 51.165(a)(3)(ii) of this chapter; and
    (3) Revise the PAL to reflect an increase in the PAL as provided 
under paragraph (w)(11) of this section.
    (b) The plan shall provide the reviewing authority discretion to 
reopen the PAL permit for the following:
    (1) Reduce the PAL to reflect newly applicable Federal requirements 
(for example, NSPS) with compliance dates after the PAL effective date;
    (2) Reduce the PAL consistent with any other requirement, that is 
enforceable as a practical matter, and that the State may impose on the 
major stationary source under the plan; and
    (3) Reduce the PAL if the reviewing authority determines that a 
reduction is necessary to avoid causing or contributing to a NAAQS or 
PSD increment violation, or to an adverse impact on an AQRV that has 
been identified for a Federal Class I area by a Federal Land Manager and 
for which information is available to the general public.
    (c) Except for the permit reopening in paragraph (w)(8)(ii)(a)(1) of 
this section for the correction of typographical/calculation errors that 
do not increase the PAL level, all reopenings shall be carried out in 
accordance with the public participation requirements of paragraph 
(w)(5) of this section.
    (9) Expiration of a PAL. Any PAL that is not renewed in accordance 
with the procedures in paragraph (w)(10) of this section shall expire at 
the end of the PAL effective period, and the requirements in paragraphs 
(w)(9)(i) through (v) of this section shall apply.
    (i) Each emissions unit (or each group of emissions units) that 
existed under the PAL shall comply with an allowable emission limitation 
under a revised permit established according to the procedures in 
paragraphs (w)(9)(i)(a) and (b) of this section.

[[Page 264]]

    (a) Within the time frame specified for PAL renewals in paragraph 
(w)(10)(ii) of this section, the major stationary source shall submit a 
proposed allowable emission limitation for each emissions unit (or each 
group of emissions units, if such a distribution is more appropriate as 
decided by the reviewing authority) by distributing the PAL allowable 
emissions for the major stationary source among each of the emissions 
units that existed under the PAL. If the PAL had not yet been adjusted 
for an applicable requirement that became effective during the PAL 
effective period, as required under paragraph (w)(10)(v) of this 
section, such distribution shall be made as if the PAL had been 
adjusted.
    (b) The reviewing authority shall decide whether and how the PAL 
allowable emissions will be distributed and issue a revised permit 
incorporating allowable limits for each emissions unit, or each group of 
emissions units, as the reviewing authority determines is appropriate.
    (ii) Each emissions unit(s) shall comply with the allowable emission 
limitation on a 12-month rolling basis. The reviewing authority may 
approve the use of monitoring systems (source testing,emission factors, 
etc.) other than CEMS, CERMS, PEMS or CPMS to demonstrate compliance 
with the allowable emission limitation.
    (iii) Until the reviewing authority issues the revised permit 
incorporating allowable limits for each emissions unit, or each group of 
emissions units, as required under paragraph (w)(9)(i)(b) of this 
section, the source shall continue to comply with a source-wide, multi-
unit emissions cap equivalent to the level of the PAL emission 
limitation.
    (iv) Any physical change or change in the method of operation at the 
major stationary source will be subject to major NSR requirements if 
such change meets the definition of major modification in paragraph 
(b)(2) of this section.
    (v) The major stationary source owner or operator shall continue to 
comply with any State or Federal applicable requirements (BACT, RACT, 
NSPS, etc.) that may have applied either during the PAL effective period 
or prior to the PAL effective period except for those emission 
limitations that had been established pursuant to paragraph (r)(2) of 
this section, but were eliminated by the PAL in accordance with the 
provisions in paragraph (w)(1)(ii)(c) of this section.
    (10) Renewal of a PAL. (i) The reviewing authority shall follow the 
procedures specified in paragraph (w)(5) of this section in approving 
any request to renew a PAL for a major stationary source, and shall 
provide both the proposed PAL level and a written rationale for the 
proposed PAL level to the public for review and comment. During such 
public review, any person may propose a PAL level for the source for 
consideration by the reviewing authority.
    (ii) Application deadline. The plan shall require that a major 
stationary source owner or operator shall submit a timely application to 
the reviewing authority to request renewal of a PAL. A timely 
application is one that is submitted at least 6 months prior to, but not 
earlier than 18 months from, the date of permit expiration. This 
deadline for application submittal is to ensure that the permit will not 
expire before the permit is renewed. If the owner or operator of a major 
stationary source submits a complete application to renew the PAL within 
this time period, then the PAL shall continue to be effective until the 
revised permit with the renewed PAL is issued.
    (iii) Application requirements. The application to renew a PAL 
permit shall contain the information required in paragraphs (w)(10)(iii) 
(a) through (d) of this section.
    (a) The information required in paragraphs (w)(3)(i) through (iii) 
of this section.
    (b) A proposed PAL level.
    (c) The sum of the potential to emit of all emissions units under 
the PAL (with supporting documentation).
    (d) Any other information the owner or operator wishes the reviewing 
authority to consider in determining the appropriate level for renewing 
the PAL.
    (iv) PAL adjustment. In determining whether and how to adjust the 
PAL, the reviewing authority shall consider the options outlined in 
paragraphs

[[Page 265]]

(w)(10)(iv) (a) and (b) of this section. However, in no case may any 
such adjustment fail to comply with paragraph (w)(10)(iv)(c) of this 
section.
    (a) If the emissions level calculated in accordance with paragraph 
(w)(6) of this section is equal to or greater than 80 percent of the PAL 
level, the reviewing authority may renew the PAL at the same level 
without considering the factors set forth in paragraph (w)(10)(iv)(b) of 
this section; or
    (b) The reviewing authority may set the PAL at a level that it 
determines to be more representative of the source's baseline actual 
emissions, or that it determines to be appropriate considering air 
quality needs, advances in control technology, anticipated economic 
growth in the area, desire to reward or encourage the source's voluntary 
emissions reductions, or other factors as specifically identified by the 
reviewing authority in its written rationale.
    (c) Notwithstanding paragraphs (w)(10)(iv) (a) and (b) of this 
section:
    (1) If the potential to emit of the major stationary source is less 
than the PAL, the reviewing authority shall adjust the PAL to a level no 
greater than the potential to emit of the source; and
    (2) The reviewing authority shall not approve a renewed PAL level 
higher than the current PAL, unless the major stationary source has 
complied with the provisions of paragraph (w)(11) of this section 
(increasing a PAL).
    (v) If the compliance date for a State or Federal requirement that 
applies to the PAL source occurs during the PAL effective period, and if 
the reviewing authority has not already adjusted for such requirement, 
the PAL shall be adjusted at the time of PAL permit renewal or title V 
permit renewal, whichever occurs first.
    (11) Increasing a PAL during the PAL effective period. (i) The plan 
shall require that the reviewing authority may increase a PAL emission 
limitation only if the major stationary source complies with the 
provisions in paragraphs (w)(11)(i) (a) through (d) of this section.
    (a) The owner or operator of the major stationary source shall 
submit a complete application to request an increase in the PAL limit 
for a PAL major modification. Such application shall identify the 
emissions unit(s) contributing to the increase in emissions so as to 
cause the major stationary source's emissions to equal or exceed its 
PAL.
    (b) As part of this application, the major stationary source owner 
or operator shall demonstrate that the sum of the baseline actual 
emissions of the small emissions units, plus the sum of the baseline 
actual emissions of the significant and major emissions units assuming 
application of BACT equivalent controls, plus the sum of the allowable 
emissions of the new or modified emissions unit(s), exceeds the PAL. The 
level of control that would result from BACT equivalent controls on each 
significant or major emissions unit shall be determined by conducting a 
new BACT analysis at the time the application is submitted, unless the 
emissions unit is currently required to comply with a BACT or LAER 
requirement that was established within the preceding 10 years. In such 
a case, the assumed control level for that emissions unit shall be equal 
to the level of BACT or LAER with which that emissions unit must 
currently comply.
    (c) The owner or operator obtains a major NSR permit for all 
emissions unit(s) identified in paragraph (w)(11)(i)(a) of this section, 
regardless of the magnitude of the emissions increase resulting from 
them (that is, no significant levels apply). These emissions unit(s) 
shall comply with any emissions requirements resulting from the major 
NSR process (for example, BACT), even though they have also become 
subject to the PAL or continue to be subject to the PAL.
    (d) The PAL permit shall require that the increased PAL level shall 
be effective on the day any emissions unit that is part of the PAL major 
modification becomes operational and begins to emit the PAL pollutant.
    (ii) The reviewing authority shall calculate the new PAL as the sum 
of the allowable emissions for each modified or new emissions unit, plus 
the sum of the baseline actual emissions of the significant and major 
emissions units (assuming application of BACT equivalent controls as 
determined in

[[Page 266]]

accordance with paragraph (w)(11)(i)(b) of this section), plus the sum 
of the baseline actual emissions of the small emissions units.
    (iii) The PAL permit shall be revised to reflect the increased PAL 
level pursuant to the public notice requirements of paragraph (w)(5) of 
this section.
    (12) Monitoring requirements for PALs--(i) General requirements. (a) 
Each PAL permit must contain enforceable requirements for the monitoring 
system that accurately determines plantwide emissions of the PAL 
pollutant in terms of mass per unit of time. Any monitoring system 
authorized for use in the PAL permit must be based on sound science and 
meet generally acceptable scientific procedures for data quality and 
manipulation. Additionally, the information generated by such system 
must meet minimum legal requirements for admissibility in a judicial 
proceeding to enforce the PAL permit.
    (b) The PAL monitoring system must employ one or more of the four 
general monitoring approaches meeting the minimum requirements set forth 
in paragraphs (w)(12)(ii) (a) through (d) of this section and must be 
approved by the reviewing authority.
    (c) Notwithstanding paragraph (w)(12)(i)(b) of this section, you may 
also employ an alternative monitoring approach that meets paragraph 
(w)(12)(i)(a) of this section if approved by the reviewing authority.
    (d) Failure to use a monitoring system that meets the requirements 
of this section renders the PAL invalid.
    (ii) Minimum performance requirements for approved monitoring 
approaches. The following are acceptable general monitoring approaches 
when conducted in accordance with the minimum requirements in paragraphs 
(w)(12)(iii) through (ix) of this section:
    (a) Mass balance calculations for activities using coatings or 
solvents;
    (b) CEMS;
    (c) CPMS or PEMS; and
    (d) Emission factors.
    (iii) Mass balance calculations. An owner or operator using mass 
balance calculations to monitor PAL pollutant emissions from activities 
using coating or solvents shall meet the following requirements:
    (a) Provide a demonstrated means of validating the published content 
of the PAL pollutant that is contained in or created by all materials 
used in or at the emissions unit;
    (b) Assume that the emissions unit emits all of the PAL pollutant 
that is contained in or created by any raw material or fuel used in or 
at the emissions unit, if it cannot otherwise be accounted for in the 
process; and
    (c) Where the vendor of a material or fuel, which is used in or at 
the emissions unit, publishes a range of pollutant content from such 
material, the owner or operator must use the highest value of the range 
to calculate the PAL pollutant emissions unless the reviewing authority 
determines there is site-specific data or a site-specific monitoring 
program to support another content within the range.
    (iv) CEMS. An owner or operator using CEMS to monitor PAL pollutant 
emissions shall meet the following requirements:
    (a) CEMS must comply with applicable Performance Specifications 
found in 40 CFR part 60, appendix B; and
    (b) CEMS must sample, analyze, and record data at least every 15 
minutes while the emissions unit is operating.
    (v) CPMS or PEMS. An owner or operator using CPMS or PEMS to monitor 
PAL pollutant emissions shall meet the following requirements:
    (a) The CPMS or the PEMS must be based on current site-specific data 
demonstrating a correlation between the monitored parameter(s) and the 
PAL pollutant emissions across the range of operation of the emissions 
unit; and
    (b) Each CPMS or PEMS must sample, analyze, and record data at least 
every 15 minutes, or at another less frequent interval approved by the 
reviewing authority, while the emissions unit is operating.
    (vi) Emission factors. An owner or operator using emission factors 
to monitor PAL pollutant emissions shall meet the following 
requirements:
    (a) All emission factors shall be adjusted, if appropriate, to 
account for the degree of uncertainty or limitations in the factors' 
development;

[[Page 267]]

    (b) The emissions unit shall operate within the designated range of 
use for the emission factor, if applicable; and
    (c) If technically practicable, the owner or operator of a 
significant emissions unit that relies on an emission factor to 
calculate PAL pollutant emissions shall conduct validation testing to 
determine a site-specific emission factor within 6 months of PAL permit 
issuance, unless the reviewing authority determines that testing is not 
required.
    (vii) A source owner or operator must record and report maximum 
potential emissions without considering enforceable emission limitations 
or operational restrictions for an emissions unit during any period of 
time that there is no monitoring data, unless another method for 
determining emissions during such periods is specified in the PAL 
permit.
    (viii) Notwithstanding the requirements in paragraphs (w)(12)(iii) 
through (vii) of this section, where an owner or operator of an 
emissions unit cannot demonstrate a correlation between the monitored 
parameter(s) and the PAL pollutant emissions rate at all operating 
points of the emissions unit, the reviewing authority shall, at the time 
of permit issuance:
    (a) Establish default value(s) for determining compliance with the 
PAL based on the highest potential emissions reasonably estimated at 
such operating point(s); or
    (b) Determine that operation of the emissions unit during operating 
conditions when there is no correlation between monitored parameter(s) 
and the PAL pollutant emissions is a violation of the PAL.
    (ix) Re-validation. All data used to establish the PAL pollutant 
must be re-validated through performance testing or other scientifically 
valid means approved by the reviewing authority. Such testing must occur 
at least once every 5 years after issuance of the PAL.
    (13) Recordkeeping requirements. (i) The PAL permit shall require an 
owner or operator to retain a copy of all records necessary to determine 
compliance with any requirement of paragraph (w) of this section and of 
the PAL, including a determination of each emissions unit's 12-month 
rolling total emissions, for 5 years from the date of such record.
    (ii) The PAL permit shall require an owner or operator to retain a 
copy of the following records, for the duration of the PAL effective 
period plus 5 years:
    (a) A copy of the PAL permit application and any applications for 
revisions to the PAL; and
    (b) Each annual certification of compliance pursuant to title V and 
the data relied on in certifying the compliance.
    (14) Reporting and notification requirements. The owner or operator 
shall submit semi-annual monitoring reports and prompt deviation reports 
to the reviewing authority in accordance with the applicable title V 
operating permit program. The reports shall meet the requirements in 
paragraphs (w)(14)(i) through (iii) of this section.
    (i) Semi-annual report. The semi-annual report shall be submitted to 
the reviewing authority within 30 days of the end of each reporting 
period. This report shall contain the information required in paragraphs 
(w)(14)(i)(a) through (g) of this section.
    (a) The identification of owner and operator and the permit number.
    (b) Total annual emissions (tons/year) based on a 12-month rolling 
total for each month in the reporting period recorded pursuant to 
paragraph (w)(13)(i) of this section.
    (c) All data relied upon, including, but not limited to, any Quality 
Assurance or Quality Control data, in calculating the monthly and annual 
PAL pollutant emissions.
    (d) A list of any emissions units modified or added to the major 
stationary source during the preceding 6-month period.
    (e) The number, duration, and cause of any deviations or monitoring 
malfunctions (other than the time associated with zero and span 
calibration checks), and any corrective action taken.
    (f) A notification of a shutdown of any monitoring system, whether 
the shutdown was permanent or temporary, the reason for the shutdown, 
the anticipated date that the monitoring system will be fully 
operational

[[Page 268]]

or replaced with another monitoring system, and whether the emissions 
unit monitored by the monitoring system continued to operate, and the 
calculation of the emissions of the pollutant or the number determined 
by method included in the permit, as provided by paragraph (w)(12)(vii) 
of this section.
    (g) A signed statement by the responsible official (as defined by 
the applicable title V operating permit program) certifying the truth, 
accuracy, and completeness of the information provided in the report.
    (ii) Deviation report. The major stationary source owner or operator 
shall promptly submit reports of any deviations or exceedance of the PAL 
requirements, including periods where no monitoring is available. A 
report submitted pursuant to Sec. 70.6(a)(3)(iii)(B) of this chapter 
shall satisfy this reporting requirement. The deviation reports shall be 
submitted within the time limits prescribed by the applicable program 
implementing Sec. 70.6(a)(3)(iii)(B) of this chapter. The reports shall 
contain the following information:
    (a) The identification of owner and operator and the permit number;
    (b) The PAL requirement that experienced the deviation or that was 
exceeded;
    (c) Emissions resulting from the deviation or the exceedance; and
    (d) A signed statement by the responsible official (as defined by 
the applicable title V operating permit program) certifying the truth, 
accuracy, and completeness of the information provided in the report.
    (iii) Re-validation results. The owner or operator shall submit to 
the reviewing authority the results of any re-validation test or method 
within three months after completion of such test or method.
    (15) Transition requirements. (i) No reviewing authority may issue a 
PAL that does not comply with the requirements in paragraphs (w)(1) 
through (15) of this section after the Administrator has approved 
regulations incorporating these requirements into a plan.
    (ii) The reviewing authority may supersede any PAL which was 
established prior to the date of approval of the plan by the 
Administrator with a PAL that complies with the requirements of 
paragraphs (w)(1) through (15) of this section.
    (x) If any provision of this section, or the application of such 
provision to any person or circumstance, is held invalid, the remainder 
of this section, or the application of such provision to persons or 
circumstances other than those as to which it is held invalid, shall not 
be affected thereby.
    (y) Equipment replacement provision. Without regard to other 
considerations, routine maintenance, repair and replacement includes, 
but is not limited to, the replacement of any component of a process 
unit with an identical or functionally equivalent component(s), and 
maintenance and repair activities that are part of the replacement 
activity, provided that all of the requirements in paragraphs (y)(1) 
through (3) of this section are met.
    (1) Capital Cost threshold for Equipment Replacement. (i) For an 
electric utility steam generating unit, as defined in Sec. 
51.166(b)(30), the fixed capital cost of the replacement component(s) 
plus the cost of any associated maintenance and repair activities that 
are part of the replacement shall not exceed 20 percent of the 
replacement value of the process unit, at the time the equipment is 
replaced. For a process unit that is not an electric utility steam 
generating unit the fixed capital cost of the replacement component(s) 
plus the cost of any associated maintenance and repair activities that 
are part of the replacement shall not exceed 20 percent of the 
replacement value of the process unit, at the time the equipment is 
replaced.
    (ii) In determining the replacement value of the process unit; and, 
except as otherwise allowed under paragraph (y)(1)(iii) of this section, 
the owner or operator shall determine the replacement value of the 
process unit on an estimate of the fixed capital cost of constructing a 
new process unit, or on the current appraised value of the process unit.
    (iii) As an alternative to paragraph (y)(1)(ii) of this section for 
determining the replacement value of a process unit, an owner or 
operator may choose

[[Page 269]]

to use insurance value (where the insurance value covers only complete 
replacement), investment value adjusted for inflation, or another 
accounting procedure if such procedure is based on Generally Accepted 
Accounting Principles, provided that the owner or operator sends a 
notice to the reviewing authority. The first time that an owner or 
operator submits such a notice for a particular process unit, the notice 
may be submitted at any time, but any subsequent notice for that process 
unit may be submitted only at the beginning of the process unit's fiscal 
year. Unless the owner or operator submits a notice to the reviewing 
authority, then paragraph (y)(1)(ii) of this section will be used to 
establish the replacement value of the process unit. Once the owner or 
operator submits a notice to use an alternative accounting procedure, 
the owner or operator must continue to use that procedure for the entire 
fiscal year for that process unit. In subsequent fiscal years, the owner 
or operator must continue to use this selected procedure unless and 
until the owner or operator sends another notice to the reviewing 
authority selecting another procedure consistent with this paragraph or 
paragraph (y)(1)(ii) of this section at the beginning of such fiscal 
year.
    (2) Basic design parameters. The replacement does not change the 
basic design parameter(s) of the process unit to which the activity 
pertains.
    (i) Except as provided in paragraph (y)(2)(iii) of this section, for 
a process unit at a steam electric generating facility, the owner or 
operator may select as its basic design parameters either maximum hourly 
heat input and maximum hourly fuel consumption rate or maximum hourly 
electric output rate and maximum steam flow rate. When establishing fuel 
consumption specifications in terms of weight or volume, the minimum 
fuel quality based on British Thermal Units content shall be used for 
determining the basic design parameter(s) for a coal-fired electric 
utility steam generating unit.
    (ii) Except as provided in paragraph (y)(2)(iii) of this section, 
the basic design parameter(s) for any process unit that is not at a 
steam electric generating facility are maximum rate of fuel or heat 
input, maximum rate of material input, or maximum rate of product 
output. Combustion process units will typically use maximum rate of fuel 
input. For sources having multiple end products and raw materials, the 
owner or operator should consider the primary product or primary raw 
material when selecting a basic design parameter.
    (iii) If the owner or operator believes the basic design 
parameter(s) in paragraphs (y)(2)(i) and (ii) of this section is not 
appropriate for a specific industry or type of process unit, the owner 
or operator may propose to the reviewing authority an alternative basic 
design parameter(s) for the source's process unit(s). If the reviewing 
authority approves of the use of an alternative basic design 
parameter(s), the reviewing authority shall issue a permit that is 
legally enforceable that records such basic design parameter(s) and 
requires the owner or operator to comply with such parameter(s).
    (iv) The owner or operator shall use credible information, such as 
results of historic maximum capability tests, design information from 
the manufacturer, or engineering calculations, in establishing the 
magnitude of the basic design parameter(s) specified in paragraphs 
(y)(2)(i) and (ii) of this section.
    (v) If design information is not available for a process unit, then 
the owner or operator shall determine the process unit's basic design 
parameter(s) using the maximum value achieved by the process unit in the 
five-year period immediately preceding the planned activity.
    (vi) Efficiency of a process unit is not a basic design parameter.
    (3) The replacement activity shall not cause the process unit to 
exceed any emission limitation, or operational limitation that has the 
effect of constraining emissions, that applies to the process unit and 
that is legally enforceable.
    Note to paragraph (y): By a court order on December 24, 2003, this 
paragraph (y) is stayed indefinitely. The stayed provisions will become 
effective immediately if the court terminates the stay. At that time, 
EPA will publish a document in the Federal

[[Page 270]]

Register advising the public of the termination of the stay.

(Secs. 101(b)(1), 110, 160-169, 171-178, and 301(a), Clean Air Act, as 
amended (42 U.S.C. 7401(b)(1), 7410, 7470-7479, 7501-7508, and 7601(a)); 
sec. 129(a), Clean Air Act Amendments of 1977 (Pub. L. 95-95, 91 Stat. 
685 (Aug. 7, 1977)))

[43 FR 26382, June 19, 1978]

    Editorial Note: For Federal Register citations affecting Sec. 
51.166, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and on GPO Access.



               Subpart J_Ambient Air Quality Surveillance

    Authority: Secs. 110, 301(a), 313, 319, Clean Air Act (42 U.S.C. 
7410, 7601(a), 7613, 7619).



Sec. 51.190  Ambient air quality monitoring requirements.

    The requirements for monitoring ambient air quality for purposes of 
the plan are located in subpart C of part 58 of this chapter.

[44 FR 27569, May 10, 1979]



                      Subpart K_Source Survelliance

    Source: 51 FR 40673, Nov. 7, 1986, unless otherwise noted.



Sec. 51.210  General.

    Each plan must provide for monitoring the status of compliance with 
any rules and regulations that set forth any portion of the control 
strategy. Specifically, the plan must meet the requirements of this 
subpart.



Sec. 51.211  Emission reports and recordkeeping.

    The plan must provide for legally enforceable procedures for 
requiring owners or operators of stationary sources to maintain records 
of and periodically report to the State--
    (a) Information on the nature and amount of emissions from the 
stationary sources; and
    (b) Other information as may be necessary to enable the State to 
determine whether the sources are in compliance with applicable portions 
of the control strategy.



Sec. 51.212  Testing, inspection, enforcement, and complaints.

    The plan must provide for--
    (a) Periodic testing and inspection of stationary sources; and
    (b) Establishment of a system for detecting violations of any rules 
and regulations through the enforcement of appropriate visible emission 
limitations and for investigating complaints.
    (c) Enforceable test methods for each emission limit specified in 
the plan. For the purpose of submitting compliance certifications or 
establishing whether or not a person has violated or is in violation of 
any standard in this part, the plan must not preclude the use, including 
the exclusive use, of any credible evidence or information, relevant to 
whether a source would have been in compliance with applicable 
requirements if the appropriate performance or compliance test or 
procedure had been performed. As an enforceable method, States may use:
    (1) Any of the appropriate methods in appendix M to this part, 
Recommended Test Methods for State Implementation Plans; or
    (2) An alternative method following review and approval of that 
method by the Administrator; or
    (3) Any appropriate method in appendix A to 40 CFR part 60.

[51 FR 40673, Nov. 7, 1986, as amended at 55 FR 14249, Apr. 17, 1990; 62 
FR 8328, Feb. 24, 1997]



Sec. 51.213  Transportation control measures.

    (a) The plan must contain procedures for obtaining and maintaining 
data on actual emissions reductions achieved as a result of implementing 
transportation control measures.
    (b) In the case of measures based on traffic flow changes or 
reductions in vehicle use, the data must include observed changes in 
vehicle miles traveled and average speeds.
    (c) The data must be maintained in such a way as to facilitate 
comparison of the planned and actual efficacy of the transportation 
control measures.

[61 FR 30163, June 14, 1996]

[[Page 271]]



Sec. 51.214  Continuous emission monitoring.

    (a) The plan must contain legally enforceable procedures to--
    (1) Require stationary sources subject to emission standards as part 
of an applicable plan to install, calibrate, maintain, and operate 
equipment for continuously monitoring and recording emissions; and
    (2) Provide other information as specified in appendix P of this 
part.
    (b) The procedures must--
    (1) Identify the types of sources, by source category and capacity, 
that must install the equipment; and
    (2) Identify for each source category the pollutants which must be 
monitored.
    (c) The procedures must, as a minimum, require the types of sources 
set forth in appendix P of this part to meet the applicable requirements 
set forth therein.
    (d)(1) The procedures must contain provisions that require the owner 
or operator of each source subject to continuous emission monitoring and 
recording requirements to maintain a file of all pertinent information 
for at least two years following the date of collection of that 
information.
    (2) The information must include emission measurements, continuous 
monitoring system performance testing measurements, performance 
evaluations, calibration checks, and adjustments and maintenance 
performed on such monitoring systems and other reports and records 
required by appendix P of this part.
    (e) The procedures must require the source owner or operator to 
submit information relating to emissions and operation of the emission 
monitors to the State to the extent described in appendix P at least as 
frequently as described therein.
    (f)(1) The procedures must provide that sources subject to the 
requirements of paragraph (c) of this section must have installed all 
necessary equipment and shall have begun monitoring and recording within 
18 months after either--
    (i) The approval of a State plan requiring monitoring for that 
source; or
    (ii) Promulgation by the Agency of monitoring requirements for that 
source.
    (2) The State may grant reasonable extensions of this period to 
sources that--
    (i) Have made good faith efforts to purchases, install, and begin 
the monitoring and recording of emission data; and
    (ii) Have been unable to complete the installation within the 
period.



                        Subpart L_Legal Authority

    Source: 51 FR 40673, Nov. 7, 1986, unless otherwise noted.



Sec. 51.230  Requirements for all plans.

    Each plan must show that the State has legal authority to carry out 
the plan, including authority to:
    (a) Adopt emission standards and limitations and any other measures 
necessary for attainment and maintenance of national standards.
    (b) Enforce applicable laws, regulations, and standards, and seek 
injunctive relief.
    (c) Abate pollutant emissions on an emergency basis to prevent 
substantial endangerment to the health of persons, i.e., authority 
comparable to that available to the Administrator under section 305 of 
the Act.
    (d) Prevent construction, modification, or operation of a facility, 
building, structure, or installation, or combination thereof, which 
directly or indirectly results or may result in emissions of any air 
pollutant at any location which will prevent the attainment or 
maintenance of a national standard.
    (e) Obtain information necessary to determine whether air pollution 
sources are in compliance with applicable laws, regulations, and 
standards, including authority to require recordkeeping and to make 
inspections and conduct tests of air pollution sources.
    (f) Require owners or operators of stationary sources to install, 
maintain, and use emission monitoring devices and to make periodic 
reports to the State on the nature and amounts of emissions from such 
stationary sources; also authority for the State to make such data 
available to the public as reported and as correlated with any

[[Page 272]]

applicable emission standards or limitations.



Sec. 51.231  Identification of legal authority.

    (a) The provisions of law or regulation which the State determines 
provide the authorities required under this section must be specifically 
identified, and copies of such laws or regulations be submitted with the 
plan.
    (b) The plan must show that the legal authorities specified in this 
subpart are available to the State at the time of submission of the 
plan.
    (c) Legal authority adequate to fulfill the requirements of Sec. 
51.230 (e) and (f) of this subpart may be delegated to the State under 
section 114 of the Act.



Sec. 51.232  Assignment of legal authority to local agencies.

    (a) A State government agency other than the State air pollution 
control agency may be assigned responsibility for carrying out a portion 
of a plan if the plan demonstrates to the Administrator's satisfaction 
that the State governmental agency has the legal authority necessary to 
carry out the portion of plan.
    (b) The State may authorize a local agency to carry out a plan, or 
portion thereof, within such local agency's jurisdiction if--
    (1) The plan demonstrates to the Administrator's satisfaction that 
the local agency has the legal authority necessary to implement the plan 
or portion of it; and
    (2) This authorization does not relieve the State of responsibility 
under the Act for carrying out such plan, or portion thereof.



                Subpart M_Intergovernmental Consultation

    Authority: Secs. 110, 121, 174(a), 301(a), Clean Air Act, as amended 
(42 U.S.C. 7410, 7421, 7504, and 7601(a)).

    Source: 44 FR 35179, June 18, 1979, unless otherwise noted.

                           Agency Designation



Sec. 51.240  General plan requirements.

    Each State implementation plan must identify organizations, by 
official title, that will participate in developing, implementing, and 
enforcing the plan and the responsibilities of such organizations. The 
plan shall include any related agreements or memoranda of understanding 
among the organizations.



Sec. 51.241  Nonattainment areas for carbon monoxide and ozone.

    (a) For each AQCR or portion of an AQCR in which the national 
primary standard for carbon monoxide or ozone will not be attained by 
July 1, 1979, the Governor (or Governors for interstate areas) shall 
certify, after consultation with local officials, the organization 
responsible for developing the revised implementation plan or portions 
thereof for such AQCR.
    (b)-(f) [Reserved]

[44 FR 35179, June 18, 1979, as amended at 48 FR 29302, June 24, 1983; 
60 FR 33922, June 29, 1995; 61 FR 16060, Apr. 11, 1996]



Sec. 51.242  [Reserved]



                     Subpart N_Compliance Schedules

    Source: 51 FR 40673, Nov. 7, 1986, unless otherwise noted.



Sec. 51.260  Legally enforceable compliance schedules.

    (a) Each plan shall contain legally enforceable compliance schedules 
setting forth the dates by which all stationary and mobile sources or 
categories of such sources must be in compliance with any applicable 
requirement of the plan.
    (b) The compliance schedules must contain increments of progress 
required by Sec. 51.262 of this subpart.



Sec. 51.261  Final compliance schedules.

    (a) Unless EPA grants an extension under subpart R, compliance 
schedules designed to provide for attainment of a primary standard 
must--
    (1) Provide for compliance with the applicable plan requirements as 
soon as practicable; or
    (2) Provide for compliance no later than the date specified for 
attainment of the primary standard under;
    (b) Unless EPA grants an extension under subpart R, compliance 
schedules

[[Page 273]]

designed to provide for attainment of a secondary standard must--
    (1) Provide for compliance with the applicable plan requirements in 
a reasonable time; or
    (2) Provide for compliance no later than the date specified for the 
attainment of the secondary standard under Sec. 51.110(c).



Sec. 51.262  Extension beyond one year.

    (a) Any compliance schedule or revision of it extending over a 
period of more than one year from the date of its adoption by the State 
agency must provide for legally enforceable increments of progress 
toward compliance by each affected source or category of sources. The 
increments of progress must include--
    (1) Each increment of progress specified in Sec. 51.100(q); and
    (2) Additional increments of progress as may be necessary to permit 
close and effective supervision of progress toward timely compliance.
    (b) [Reserved]



            Subpart O_Miscellaneous Plan Content Requirements

    Authority: Secs. 110, 301(a), 313, 319, Clean Air Act (42 U.S.C. 
7410, 7601(a), 7613, 7619).



Sec. 51.280  Resources.

    Each plan must include a description of the resources available to 
the State and local agencies at the date of submission of the plan and 
of any additional resources needed to carry out the plan during the 5-
year period following its submission. The description must include 
projections of the extent to which resources will be acquired at 1-, 3-, 
and 5-year intervals.

[51 FR 40674, Nov. 7, 1986]



Sec. 51.281  Copies of rules and regulations.

    Emission limitations and other measures necessary for attainment and 
maintenance of any national standard, including any measures necessary 
to implement the requirements of subpart L must be adopted as rules and 
regulations enforceable by the State agency. Copies of all such rules 
and regulations must be submitted with the plan. Submittal of a plan 
setting forth proposed rules and regulations will not satisfy the 
requirements of this section nor will it be considered a timely 
submittal.

[51 FR 40674, Nov. 7, 1986]



Sec. 51.285  Public notification.

    By March 1, 1980, the State shall submit a plan revision that 
contains provisions for:
    (a) Notifying the public on a regular basis of instances or areas in 
which any primary standard was exceeded during any portion of the 
preceeding calendar year,
    (b) Advising the public of the health hazards associated with such 
an exceedance of a primary standard, and
    (c) Increasing public awareness of:
    (1) Measures which can be taken to prevent a primary standard from 
being exceeded, and
    (2) Ways in which the public can participate in regulatory and other 
efforts to improve air quality.

[44 FR 27569, May 10, 1979]



Sec. 51.286  Electronic reporting.

    States that wish to receive electronic documents must revise the 
State Implementation Plan to satisfy the requirements of 40 CFR Part 3--
(Electronic reporting).

[70 FR 59887, Oct. 13, 2005]



                   Subpart P_Protection of Visibility

    Authority: Secs. 110, 114, 121, 160-169, 169A, and 301 of the Clean 
Air Act, (42 U.S.C. 7410, 7414, 7421, 7470-7479, and 7601).

    Source: 45 FR 80089, Dec. 2, 1980, unless otherwise noted.



Sec. 51.300  Purpose and applicability.

    (a) Purpose. The primary purposes of this subpart are to require 
States to develop programs to assure reasonable progress toward meeting 
the national goal of preventing any future, and remedying any existing, 
impairment of visibility in mandatory Class I Federal areas which 
impairment results from manmade air pollution; and to establish 
necessary additional procedures for new source permit applicants, States 
and Federal Land Managers to

[[Page 274]]

use in conducting the visibility impact analysis required for new 
sources under Sec. 51.166. This subpart sets forth requirements 
addressing visibility impairment in its two principal forms: 
``reasonably attributable'' impairment (i.e., impairment attributable to 
a single source/small group of sources) and regional haze (i.e., 
widespread haze from a multitude of sources which impairs visibility in 
every direction over a large area).
    (b) Applicability--(1) General Applicability. The provisions of this 
subpart pertaining to implementation plan requirements for assuring 
reasonable progress in preventing any future and remedying any existing 
visibility impairment are applicable to:
    (i) Each State which has a mandatory Class I Federal area identified 
in part 81, subpart D, of this title, and (ii) each State in which there 
is any source the emissions from which may reasonably be anticipated to 
cause or contribute to any impairment of visibility in any such area.
    (2) The provisions of this subpart pertaining to implementation 
plans to address reasonably attributable visibility impairment are 
applicable to the following States:

Alabama, Alaska, Arizona, Arkansas, California, Colorado, Florida, 
    Georgia, Hawaii, Idaho, Kentucky, Louisiana, Maine, Michigan, 
    Minnesota, Missouri, Montana, Nevada, New Hampshire, New Jersey, New 
    Mexico, North Carolina, North Dakota, Oklahoma, Oregon, South 
    Carolina, South Dakota, Tennessee, Texas, Utah, Vermont, Virginia, 
    Virgin Islands, Washington, West Virginia, Wyoming.

    (3) The provisions of this subpart pertaining to implementation 
plans to address regional haze visibility impairment are applicable to 
all States as defined in section 302(d) of the Clean Air Act (CAA) 
except Guam, Puerto Rico, American Samoa, and the Northern Mariana 
Islands.

[45 FR 80089, Dec. 2, 1980, as amended at 64 FR 35763, July 1, 1999]



Sec. 51.301  Definitions.

    For purposes of this subpart:
    Adverse impact on visibility means, for purposes of section 307, 
visibility impairment which interferes with the management, protection, 
preservation, or enjoyment of the visitor's visual experience of the 
Federal Class I area. This determination must be made on a case-by-case 
basis taking into account the geographic extent, intensity, duration, 
frequency and time of visibility impairments, and how these factors 
correlate with (1) times of visitor use of the Federal Class I area, and 
(2) the frequency and timing of natural conditions that reduce 
visibility. This term does not include effects on integral vistas.
    Agency means the U.S. Environmental Protection Agency.
    BART-eligible source means an existing stationary facility as 
defined in this section.
    Best Available Retrofit Technology (BART) means an emission 
limitation based on the degree of reduction achievable through the 
application of the best system of continuous emission reduction for each 
pollutant which is emitted by an existing stationary facility. The 
emission limitation must be established, on a case-by-case basis, taking 
into consideration the technology available, the costs of compliance, 
the energy and nonair quality environmental impacts of compliance, any 
pollution control equipment in use or in existence at the source, the 
remaining useful life of the source, and the degree of improvement in 
visibility which may reasonably be anticipated to result from the use of 
such technology.
    Building, structure, or facility means all of the pollutant-emitting 
activities which belong to the same industrial grouping, are located on 
one or more contiguous or adjacent properties, and are under the control 
of the same person (or persons under common control). Pollutant-emitting 
activities must be considered as part of the same industrial grouping if 
they belong to the same Major Group (i.e., which have the same two-digit 
code) as described in the Standard Industrial Classification Manual, 
1972 as amended by the 1977 Supplement (U.S. Government Printing Office 
stock numbers 4101-0066 and 003-005-00176-0 respectively).

[[Page 275]]

    Deciview means a measurement of visibility impairment. A deciview is 
a haze index derived from calculated light extinction, such that uniform 
changes in haziness correspond to uniform incremental changes in 
perception across the entire range of conditions, from pristine to 
highly impaired. The deciview haze index is calculated based on the 
following equation (for the purposes of calculating deciview, the 
atmospheric light extinction coefficient must be calculated from aerosol 
measurements):

Deciview haze index=10 lne (bext/10 
    Mm-1).
Where bext=the atmospheric light extinction coefficient, 
    expressed in inverse megameters (Mm-1).

    Existing stationary facility means any of the following stationary 
sources of air pollutants, including any reconstructed source, which was 
not in operation prior to August 7, 1962, and was in existence on August 
7, 1977, and has the potential to emit 250 tons per year or more of any 
air pollutant. In determining potential to emit, fugitive emissions, to 
the extent quantifiable, must be counted.
    Fossil-fuel fired steam electric plants of more than 250 million 
British thermal units per hour heat input,
    Coal cleaning plants (thermal dryers),
    Kraft pulp mills,
    Portland cement plants,
    Primary zinc smelters,
    Iron and steel mill plants,
    Primary aluminum ore reduction plants,
    Primary copper smelters,
    Municipal incinerators capable of charging more than 250 tons of 
refuse per day,
    Hydrofluoric, sulfuric, and nitric acid plants,
    Petroleum refineries,
    Lime plants,
    Phosphate rock processing plants,
    Coke oven batteries,
    Sulfur recovery plants,
    Carbon black plants (furnace process),
    Primary lead smelters,
    Fuel conversion plants,
    Sintering plants,
    Secondary metal production facilities,
    Chemical process plants,
    Fossil-fuel boilers of more than 250 million British thermal units 
per hour heat input,
    Petroleum storage and transfer facilities with a capacity exceeding 
300,000 barrels,
    Taconite ore processing facilities,
    Glass fiber processing plants, and
    Charcoal production facilities.
    Federal Class I area means any Federal land that is classified or 
reclassified Class I.
    Federal Land Manager means the Secretary of the department with 
authority over the Federal Class I area (or the Secretary's designee) 
or, with respect to Roosevelt-Campobello International Park, the 
Chairman of the Roosevelt-Campobello International Park Commission.
    Federally enforceable means all limitations and conditions which are 
enforceable by the Administrator under the Clean Air Act including those 
requirements developed pursuant to parts 60 and 61 of this title, 
requirements within any applicable State Implementation Plan, and any 
permit requirements established pursuant to Sec. 52.21 of this chapter 
or under regulations approved pursuant to part 51, 52, or 60 of this 
title.
    Fixed capital cost means the capital needed to provide all of the 
depreciable components.
    Fugitive Emissions means those emissions which could not reasonably 
pass through a stack, chimney, vent, or other functionally equivalent 
opening.
    Geographic enhancement for the purpose of Sec. 51.308 means a 
method, procedure, or process to allow a broad regional strategy, such 
as an emissions trading program designed to achieve greater reasonable 
progress than BART for regional haze, to accommodate BART for reasonably 
attributable impairment.
    Implementation plan means, for the purposes of this part, any State 
Implementation Plan, Federal Implementation Plan, or Tribal 
Implementation Plan.
    Indian tribe or tribe means any Indian tribe, band, nation, or other 
organized group or community, including any

[[Page 276]]

Alaska Native village, which is federally recognized as eligible for the 
special programs and services provided by the United States to Indians 
because of their status as Indians.
    In existence means that the owner or operator has obtained all 
necessary preconstruction approvals or permits required by Federal, 
State, or local air pollution emissions and air quality laws or 
regulations and either has (1) begun, or caused to begin, a continuous 
program of physical on-site construction of the facility or (2) entered 
into binding agreements or contractual obligations, which cannot be 
cancelled or modified without substantial loss to the owner or operator, 
to undertake a program of construction of the facility to be completed 
in a reasonable time.
    In operation means engaged in activity related to the primary design 
function of the source.
    Installation means an identifiable piece of process equipment.
    Integral vista means a view perceived from within the mandatory 
Class I Federal area of a specific landmark or panorama located outside 
the boundary of the mandatory Class I Federal area.
    Least impaired days means the average visibility impairment 
(measured in deciviews) for the twenty percent of monitored days in a 
calendar year with the lowest amount of visibility impairment.
    Major stationary source and major modification mean major stationary 
source and major modification, respectively, as defined in Sec. 51.166.
    Mandatory Class I Federal Area means any area identified in part 81, 
subpart D of this title.
    Most impaired days means the average visibility impairment (measured 
in deciviews) for the twenty percent of monitored days in a calendar 
year with the highest amount of visibility impairment.
    Natural conditions includes naturally occurring phenomena that 
reduce visibility as measured in terms of light extinction, visual 
range, contrast, or coloration.
    Potential to emit means the maximum capacity of a stationary source 
to emit a pollutant under its physical and operational design. Any 
physical or operational limitation on the capacity of the source to emit 
a pollutant including air pollution control equipment and restrictions 
on hours of operation or on the type or amount of material combusted, 
stored, or processed, shall be treated as part of its design if the 
limitation or the effect it would have on emissions is federally 
enforceable. Secondary emissions do not count in determining the 
potential to emit of a stationary source.
    Reasonably attributable means attributable by visual observation or 
any other technique the State deems appropriate.
    Reasonably attributable visibility impairment means visibility 
impairment that is caused by the emission of air pollutants from one, or 
a small number of sources.
    Reconstruction will be presumed to have taken place where the fixed 
capital cost of the new component exceeds 50 percent of the fixed 
capital cost of a comparable entirely new source. Any final decision as 
to whether reconstruction has occurred must be made in accordance with 
the provisions of Sec. 60.15 (f) (1) through (3) of this title.
    Regional haze means visibility impairment that is caused by the 
emission of air pollutants from numerous sources located over a wide 
geographic area. Such sources include, but are not limited to, major and 
minor stationary sources, mobile sources, and area sources.
    Secondary emissions means emissions which occur as a result of the 
construction or operation of an existing stationary facility but do not 
come from the existing stationary facility. Secondary emissions may 
include, but are not limited to, emissions from ships or trains coming 
to or from the existing stationary facility.
    Significant impairment means, for purposes of Sec. 51.303, 
visibility impairment which, in the judgment of the Administrator, 
interferes with the management, protection, preservation, or enjoyment 
of the visitor's visual experience of the mandatory Class I Federal 
area. This determination must be made on a case-by-case basis taking 
into account the geographic extent, intensity, duration, frequency and 
time of the visibility impairment, and how these

[[Page 277]]

factors correlate with (1) times of visitor use of the mandatory Class I 
Federal area, and (2) the frequency and timing of natural conditions 
that reduce visibility.
    State means ``State'' as defined in section 302(d) of the CAA.
    Stationary Source means any building, structure, facility, or 
installation which emits or may emit any air pollutant.
    Visibility impairment means any humanly perceptible change in 
visibility (light extinction, visual range, contrast, coloration) from 
that which would have existed under natural conditions.
    Visibility in any mandatory Class I Federal area includes any 
integral vista associated with that area.

[45 FR 80089, Dec. 2, 1980, as amended at 64 FR 35763, 35774, July 1, 
1999]



Sec. 51.302  Implementation control strategies for reasonably 
attributable visibility impairment.

    (a) Plan Revision Procedures. (1) Each State identified in Sec. 
51.300(b)(2) must have submitted, not later than September 2, 1981, an 
implementation plan meeting the requirements of this subpart pertaining 
to reasonably attributable visibility impairment.
    (2)(i) The State, prior to adoption of any implementation plan to 
address reasonably attributable visibility impairment required by this 
subpart, must conduct one or more public hearings on such plan in 
accordance with Sec. 51.102.
    (ii) In addition to the requirements in Sec. 51.102, the State must 
provide written notification of such hearings to each affected Federal 
Land Manager, and other affected States, and must state where the public 
can inspect a summary prepared by the Federal Land Managers of their 
conclusions and recommendations, if any, on the proposed plan revision.
    (3) Submission of plans as required by this subpart must be 
conducted in accordance with the procedures in Sec. 51.103.
    (b) State and Federal Land Manager Coordination. (1) The State must 
identify to the Federal Land Managers, in writing and within 30 days of 
the date of promulgation of these regulations, the title of the official 
to which the Federal Land Manager of any mandatory Class I Federal area 
can submit a recommendation on the implementation of this subpart 
including, but not limited to:
    (i) A list of integral vistas that are to be listed by the State for 
the purpose of implementing section 304,
    (ii) Identification of impairment of visibility in any mandatory 
Class I Federal area(s), and
    (iii) Identification of elements for inclusion in the visibility 
monitoring strategy required by section 305.
    (2) The State must provide opportunity for consultation, in person 
and at least 60 days prior to holding any public hearing on the plan, 
with the Federal Land Manager on the proposed SIP revision required by 
this subpart. This consultation must include the opportunity for the 
affected Federal Land Managers to discuss their:
    (i) Assessment of impairment of visibility in any mandatory Class I 
Federal area, and
    (ii) Recommendations on the development of the long-term strategy.
    (3) The plan must provide procedures for continuing consultation 
between the State and Federal Land Manager on the implementation of the 
visibility protection program required by this subpart.
    (c) General plan requirements for reasonably attributable visibility 
impairment. (1) The affected Federal Land Manager may certify to the 
State, at any time, that there exists reasonably attributable impairment 
of visibility in any mandatory Class I Federal area.
    (2) The plan must contain the following to address reasonably 
attributable impairment:
    (i) A long-term (10-15 years) strategy, as specified in Sec. 51.305 
and Sec. 51.306, including such emission limitations, schedules of 
compliance, and such other measures including schedules for the 
implementation of the elements of the long-term strategy as may be 
necessary to make reasonable progress toward the national goal specified 
in Sec. 51.300(a).
    (ii) An assessment of visibility impairment and a discussion of how 
each

[[Page 278]]

element of the plan relates to the preventing of future or remedying of 
existing impairment of visibility in any mandatory Class I Federal area 
within the State.
    (iii) Emission limitations representing BART and schedules for 
compliance with BART for each existing stationary facility identified 
according to paragraph (c)(4) of this section.
    (3) The plan must require each source to maintain control equipment 
required by this subpart and establish procedures to ensure such control 
equipment is properly operated and maintained.
    (4) For any existing reasonably attributable visibility impairment 
the Federal Land Manager certifies to the State under paragraph (c)(1) 
of this section, at least 6 months prior to plan submission or revision:
    (i) The State must identify and analyze for BART each existing 
stationary facility which may reasonably be anticipated to cause or 
contribute to impairment of visibility in any mandatory Class I Federal 
area where the impairment in the mandatory Class I Federal area is 
reasonably attributable to that existing stationary facility. The State 
need not consider any integral vista the Federal Land Manager did not 
identify pursuant to Sec. 51.304(b) at least 6 months before plan 
submission.
    (ii) If the State determines that technologicial or economic 
limitations on the applicability of measurement methodology to a 
particular existing stationary facility would make the imposition of an 
emission standard infeasible it may instead prescribe a design, 
equipment, work practice, or other operational standard, or combination 
thereof, to require the application of BART. Such standard, to the 
degree possible, is to set forth the emission reduction to be achieved 
by implementation of such design, equipment, work practice or operation, 
and must provide for compliance by means which achieve equivalent 
results.
    (iii) BART must be determined for fossil-fuel fired generating 
plants having a total generating capacity in excess of 750 megawatts 
pursuant to ``Guidelines for Determining Best Available Retrofit 
Technology for Coal-fired Power Plants and Other Existing Stationary 
Facilities'' (1980), which is incorporated by reference, exclusive of 
appendix E to the Guidelines, except that options more stringent than 
NSPS must be considered. Establishing a BART emission limitation 
equivalent to the NSPS level of control is not a sufficient basis to 
avoid the analysis of control options required by the guidelines. This 
document is EPA publication No. 450/3-80-009b and has been approved for 
incorporation by reference by the Director of the Federal Register in 
accordance with 5 U.S.C. 552(a) and 1 CFR part 51. It is for sale from 
the U.S. Department of Commerce, National Technical Information Service, 
5285 Port Royal Road, Springfield, Virginia 22161. It is also available 
for inspection from the National Archives and Records Administration 
(NARA). For information on the availability of this material at NARA, 
call 202-741-6030, or go to: http://www.archives.gov/federal--register/
index.html.
    (iv) The plan must require that each existing stationary facility 
required to install and operate BART do so as expeditiously as 
practicable but in no case later than five years after plan approval.
    (v) The plan must provide for a BART analysis of any existing 
stationary facility that might cause or contribute to impairment of 
visibility in any mandatory Class I Federal area identified under this 
paragraph (c)(4) at such times, as determined by the Administrator, as 
new technology for control of the pollutant becomes reasonably available 
if:
    (A) The pollutant is emitted by that existing stationary facility,
    (B) Controls representing BART for the pollutant have not previously 
been required under this subpart, and
    (C) The impairment of visibility in any mandatory Class I Federal 
area is reasonably attributable to the emissions of that pollutant.

[45 FR 80089, Dec. 2, 1980, as amended at 57 FR 40042, Sept. 1, 1992; 64 
FR 35764, 35774, July 1, 1999; 69 FR 18803, Apr. 9, 2004; 70 FR 39156, 
July 6, 2005]



Sec. 51.303  Exemptions from control.

    (a)(1) Any existing stationary facility subject to the requirement 
under

[[Page 279]]

Sec. 51.302 to install, operate, and maintain BART may apply to the 
Administrator for an exemption from that requirement.
    (2) An application under this section must include all available 
documentation relevant to the impact of the source's emissions on 
visibility in any mandatory Class I Federal area and a demonstration by 
the existing stationary facility that it does not or will not, by itself 
or in combination with other sources, emit any air pollutant which may 
be reasonably anticipated to cause or contribute to a significant 
impairment of visibility in any mandatory Class I Federal area.
    (b) Any fossil-fuel fired power plant with a total generating 
capacity of 750 megawatts or more may receive an exemption from BART 
only if the owner or operator of such power plant demonstrates to the 
satisfaction of the Administrator that such power plant is located at 
such a distance from all mandatory Class I Federal areas that such power 
plant does not or will not, by itself or in combination with other 
sources, emit any air pollutant which may reasonably be anticipated to 
cause or contribute to significant impairment of visibility in any such 
mandatory Class I Federal area.
    (c) Application under this Sec. 51.303 must be accompanied by a 
written concurrence from the State with regulatory authority over the 
source.
    (d) The existing stationary facility must give prior written notice 
to all affected Federal Land Managers of any application for exemption 
under this Sec. 51.303.
    (e) The Federal Land Manager may provide an initial recommendation 
or comment on the disposition of such application. Such recommendation, 
where provided, must be part of the exemption application. This 
recommendation is not to be construed as the concurrence required under 
paragraph (h) of this section.
    (f) The Administrator, within 90 days of receipt of an application 
for exemption from control, will provide notice of receipt of an 
exemption application and notice of opportunity for public hearing on 
the application.
    (g) After notice and opportunity for public hearing, the 
Administrator may grant or deny the exemption. For purposes of judicial 
review, final EPA action on an application for an exemption under this 
Sec. 51.303 will not occur until EPA approves or disapproves the State 
Implementation Plan revision.
    (h) An exemption granted by the Administrator under this Sec. 
51.303 will be effective only upon concurrence by all affected Federal 
Land Managers with the Administrator's determination.

[45 FR 80089, Dec. 2, 1980, as amended by 64 FR 35774, July 1, 1999]



Sec. 51.304  Identification of integral vistas.

    (a) On or before December 31, 1985 the Federal Land Manager may 
identify any integral vista. The integral vista must be identified 
according to criteria the Federal Land Manager develops. These criteria 
must include, but are not limited to, whether the integral vista is 
important to the visitor's visual experience of the mandatory Class I 
Federal area. Adoption of criteria must be preceded by reasonable notice 
and opportunity for public comment on the proposed criteria.
    (b) The Federal Land Manager must notify the State of any integral 
vistas identified under paragraph (a) of this section, and the reasons 
therefor.
    (c) The State must list in its implementation plan any integral 
vista the Federal Land Manager identifies at least six months prior to 
plan submission, and must list in its implementation plan at its 
earliest opportunity, and in no case later than at the time of the 
periodic review of the SIP required by Sec. 51.306(c), any integral 
vista the Federal Land Manager identifies after that time.
    (d) The State need not in its implementation plan list any integral 
vista the indentification of which was not made in accordance with the 
criteria in paragraph (a) of this section. In making this finding, the 
State must carefully consider the expertise of the Federal Land Manager 
in making the judgments called for by the criteria for identification. 
Where the State and the Federal Land Manager disagree on the 
identification of any integral vista, the

[[Page 280]]

State must give the Federal Land Manager an opportunity to consult with 
the Governor of the State.

[45 FR 80089, Dec. 2, 1980, as amended by 64 FR 35774, July 1, 1999]



Sec. 51.305  Monitoring for reasonably attributable visibility 
impairment.

    (a) For the purposes of addressing reasonably attributable 
visibility impairment, each State containing a mandatory Class I Federal 
area must include in the plan a strategy for evaluating reasonably 
attributable visibility impairment in any mandatory Class I Federal area 
by visual observation or other appropriate monitoring techniques. Such 
strategy must take into account current and anticipated visibility 
monitoring research, the availability of appropriate monitoring 
techniques, and such guidance as is provided by the Agency.
    (b) The plan must provide for the consideration of available 
visibility data and must provide a mechanism for its use in decisions 
required by this subpart.

[45 FR 80089, Dec. 2, 1980, as amended at 64 FR 35764, July 1, 1999]



Sec. 51.306  Long-term strategy requirements for reasonably attributable 
visibility impairment.

    (a)(1) For the purposes of addressing reasonably attributable 
visibility impairment, each plan must include a long-term (10-15 years) 
strategy for making reasonable progress toward the national goal 
specified in Sec. 51.300(a). This strategy must cover any existing 
impairment the Federal Land Manager certifies to the State at least 6 
months prior to plan submission, and any integral vista of which the 
Federal Land Manager notifies the State at least 6 months prior to plan 
submission.
    (2) A long-term strategy must be developed for each mandatory Class 
I Federal area located within the State and each mandatory Class I 
Federal area located outside the State which may be affected by sources 
within the State. This does not preclude the development of a single 
comprehensive plan for all such areas.
    (3) The plan must set forth with reasonable specificity why the 
long-term strategy is adequate for making reasonable progress toward the 
national visibility goal, including remedying existing and preventing 
future impairment.
    (b) The State must coordinate its long-term strategy for an area 
with existing plans and goals, including those provided by the affected 
Federal Land Managers, that may affect impairment of visibility in any 
mandatory Class I Federal area.
    (c) The plan must provide for periodic review and revision, as 
appropriate, of the long-term strategy for addressing reasonably 
attributable visibility impairment. The plan must provide for such 
periodic review and revision not less frequently than every 3 years 
until the date of submission of the State's first plan addressing 
regional haze visibility impairment in accordance with Sec. 51.308(b) 
and (c). On or before this date, the State must revise its plan to 
provide for review and revision of a coordinated long-term strategy for 
addressing reasonably attributable and regional haze visibility 
impairment, and the State must submit the first such coordinated long-
term strategy. Future coordinated long-term strategies must be submitted 
consistent with the schedule for periodic progress reports set forth in 
Sec. 51.308(g). Until the State revises its plan to meet this 
requirement, the State must continue to comply with existing 
requirements for plan review and revision, and with all emission 
management requirements in the plan to address reasonably attributable 
impairment. This requirement does not affect any preexisting deadlines 
for State submittal of a long-term strategy review (or element thereof) 
between August 30, 1999, and the date required for submission of the 
State's first regional haze plan. In addition, the plan must provide for 
review of the long-term strategy as it applies to reasonably 
attributable impairment, and revision as appropriate, within 3 years of 
State receipt of any certification of reasonably attributable impairment 
from a Federal Land Manager. The review process must include 
consultation with the appropriate Federal Land Managers, and the State 
must provide a report to the public and the Administrator on progress 
toward the national

[[Page 281]]

goal. This report must include an assessment of:
    (1) The progress achieved in remedying existing impairment of 
visibility in any mandatory Class I Federal area;
    (2) The ability of the long-term strategy to prevent future 
impairment of visibility in any mandatory Class I Federal area;
    (3) Any change in visibility since the last such report, or, in the 
case of the first report, since plan approval;
    (4) Additional measures, including the need for SIP revisions, that 
may be necessary to assure reasonable progress toward the national 
visibility goal;
    (5) The progress achieved in implementing BART and meeting other 
schedules set forth in the long-term strategy;
    (6) The impact of any exemption granted under Sec. 51.303;
    (7) The need for BART to remedy existing visibility impairment of 
any integral vista listed in the plan since the last such report, or, in 
the case of the first report, since plan approval.
    (d) The long-term strategy must provide for review of the impacts 
from any new major stationary source or major modifications on 
visibility in any mandatory Class I Federal area. This review of major 
stationary sources or major modifications must be in accordance with 
Sec. 51.307, Sec. 51.166, Sec. 51.160, and any other binding guidance 
provided by the Agency insofar as these provisions pertain to protection 
of visibility in any mandatory Class I Federal areas.
    (e) The State must consider, at a minimum, the following factors 
during the development of its long-term strategy:
    (1) Emission reductions due to ongoing air pollution control 
programs,
    (2) Additional emission limitations and schedules for compliance,
    (3) Measures to mitigate the impacts of construction activities,
    (4) Source retirement and replacement schedules,
    (5) Smoke management techniques for agricultural and forestry 
management purposes including such plans as currently exist within the 
State for these purposes, and
    (6) Enforceability of emission limitations and control measures.
    (f) The plan must discuss the reasons why the above and other 
reasonable measures considered in the development of the long-term 
strategy were or were not adopted as part of the long-term strategy.
    (g) The State, in developing the long-term strategy, must take into 
account the effect of new sources, and the costs of compliance, the time 
necessary for compliance, the energy and nonair quality environmental 
impacts of compliance, and the remaining useful life of any affected 
existing source and equipment therein.

[45 FR 80089, Dec. 2, 1980, as amended at 64 FR 35764, 35774, July 1, 
1999]



Sec. 51.307  New source review.

    (a) For purposes of new source review of any new major stationary 
source or major modification that would be constructed in an area that 
is designated attainment or unclassified under section 107(d)(1)(D) or 
(E) of the CAA, the State plan must, in any review under Sec. 51.166 
with respect to visibility protection and analyses, provide for:
    (1) Written notification of all affected Federal Land Managers of 
any proposed new major stationary source or major modification that may 
affect visibility in any Federal Class I area. Such notification must be 
made in writing and include a copy of all information relevant to the 
permit application within 30 days of receipt of and at least 60 days 
prior to public hearing by the State on the application for permit to 
construct. Such notification must include an analysis of the anticipated 
impacts on visibility in any Federal Class I area,
    (2) Where the State requires or receives advance notification (e.g. 
early consultation with the source prior to submission of the 
application or notification of intent to monitor under Sec. 51.166) of 
a permit application of a source that may affect visibility the State 
must notify all affected Federal Land Managers within 30 days of such 
advance notification, and
    (3) Consideration of any analysis performed by the Federal Land 
Manager, provided within 30 days of the notification and analysis 
required by paragraph (a)(1) of this section, that such proposed new 
major stationary source

[[Page 282]]

or major modification may have an adverse impact on visibility in any 
Federal Class I area. Where the State finds that such an analysis does 
not demonstrate to the satisfaction of the State that an adverse impact 
will result in the Federal Class I area, the State must, in the notice 
of public hearing, either explain its decision or give notice as to 
where the explanation can be obtained.
    (b) The plan shall also provide for the review of any new major 
stationary source or major modification:
    (1) That may have an impact on any integral vista of a mandatory 
Class I Federal area, if it is identified in accordance with Sec. 
51.304 by the Federal Land Manager at least 12 months before submission 
of a complete permit application, except where the Federal Land Manager 
has provided notice and opportunity for public comment on the integral 
vista in which case the review must include impacts on any integral 
vista identified at least 6 months prior to submission of a complete 
permit application, unless the State determines under Sec. 51.304(d) 
that the identification was not in accordance with the identification 
criteria, or
    (2) That proposes to locate in an area classified as nonattainment 
under section 107(d)(1)(A), (B), or (C) of the Clean Air Act that may 
have an impact on visibility in any mandatory Class I Federal area.
    (c) Review of any major stationary source or major modification 
under paragraph (b) of this section, shall be conducted in accordance 
with paragraph (a) of this section, and Sec. 51.166(o), (p)(1) through 
(2), and (q). In conducting such reviews the State must ensure that the 
source's emissions will be consistent with making reasonable progress 
toward the national visibility goal referred to in Sec. 51.300(a). The 
State may take into account the costs of compliance, the time necessary 
for compliance, the energy and nonair quality environmental impacts of 
compliance, and the useful life of the source.
    (d) The State may require monitoring of visibility in any Federal 
Class I area near the proposed new stationary source or major 
modification for such purposes and by such means as the State deems 
necessary and appropriate.

[45 FR 80089, Dec. 2, 1980, as amended at 64 FR 35765, 35774, July 1, 
1999]



Sec. 51.308  Regional haze program requirements.

    (a) What is the purpose of this section? This section establishes 
requirements for implementation plans, plan revisions, and periodic 
progress reviews to address regional haze.
    (b) When are the first implementation plans due under the regional 
haze program? Except as provided in Sec. 51.309(c), each State 
identified in Sec. 51.300(b)(3) must submit, for the entire State, an 
implementation plan for regional haze meeting the requirements of 
paragraphs (d) and (e) of this section no later than December 17, 2007.
    (c) [Reserved]
    (d) What are the core requirements for the implementation plan for 
regional haze? The State must address regional haze in each mandatory 
Class I Federal area located within the State and in each mandatory 
Class I Federal area located outside the State which may be affected by 
emissions from within the State. To meet the core requirements for 
regional haze for these areas, the State must submit an implementation 
plan containing the following plan elements and supporting documentation 
for all required analyses:
    (1) Reasonable progress goals. For each mandatory Class I Federal 
area located within the State, the State must establish goals (expressed 
in deciviews) that provide for reasonable progress towards achieving 
natural visibility conditions. The reasonable progress goals must 
provide for an improvement in visibility for the most impaired days over 
the period of the implementation plan and ensure no degradation in 
visibility for the least impaired days over the same period.
    (i) In establishing a reasonable progress goal for any mandatory 
Class I Federal area within the State, the State must:
    (A) Consider the costs of compliance, the time necessary for 
compliance, the energy and non-air quality environmental impacts of 
compliance, and the remaining useful life of any potentially

[[Page 283]]

affected sources, and include a demonstration showing how these factors 
were taken into consideration in selecting the goal.
    (B) Analyze and determine the rate of progress needed to attain 
natural visibility conditions by the year 2064. To calculate this rate 
of progress, the State must compare baseline visibility conditions to 
natural visibility conditions in the mandatory Federal Class I area and 
determine the uniform rate of visibility improvement (measured in 
deciviews) that would need to be maintained during each implementation 
period in order to attain natural visibility conditions by 2064. In 
establishing the reasonable progress goal, the State must consider the 
uniform rate of improvement in visibility and the emission reduction 
measures needed to achieve it for the period covered by the 
implementation plan.
    (ii) For the period of the implementation plan, if the State 
establishes a reasonable progress goal that provides for a slower rate 
of improvement in visibility than the rate that would be needed to 
attain natural conditions by 2064, the State must demonstrate, based on 
the factors in paragraph (d)(1)(i)(A) of this section, that the rate of 
progress for the implementation plan to attain natural conditions by 
2064 is not reasonable; and that the progress goal adopted by the State 
is reasonable. The State must provide to the public for review as part 
of its implementation plan an assessment of the number of years it would 
take to attain natural conditions if visibility improvement continues at 
the rate of progress selected by the State as reasonable.
    (iii) In determining whether the State's goal for visibility 
improvement provides for reasonable progress towards natural visibility 
conditions, the Administrator will evaluate the demonstrations developed 
by the State pursuant to paragraphs (d)(1)(i) and (d)(1)(ii) of this 
section.
    (iv) In developing each reasonable progress goal, the State must 
consult with those States which may reasonably be anticipated to cause 
or contribute to visibility impairment in the mandatory Class I Federal 
area. In any situation in which the State cannot agree with another such 
State or group of States that a goal provides for reasonable progress, 
the State must describe in its submittal the actions taken to resolve 
the disagreement. In reviewing the State's implementation plan 
submittal, the Administrator will take this information into account in 
determining whether the State's goal for visibility improvement provides 
for reasonable progress towards natural visibility conditions.
    (v) The reasonable progress goals established by the State are not 
directly enforceable but will be considered by the Administrator in 
evaluating the adequacy of the measures in the implementation plan to 
achieve the progress goal adopted by the State.
    (vi) The State may not adopt a reasonable progress goal that 
represents less visibility improvement than is expected to result from 
implementation of other requirements of the CAA during the applicable 
planning period.
    (2) Calculations of baseline and natural visibility conditions. For 
each mandatory Class I Federal area located within the State, the State 
must determine the following visibility conditions (expressed in 
deciviews):
    (i) Baseline visibility conditions for the most impaired and least 
impaired days. The period for establishing baseline visibility 
conditions is 2000 to 2004. Baseline visibility conditions must be 
calculated, using available monitoring data, by establishing the average 
degree of visibility impairment for the most and least impaired days for 
each calendar year from 2000 to 2004. The baseline visibility conditions 
are the average of these annual values. For mandatory Class I Federal 
areas without onsite monitoring data for 2000-2004, the State must 
establish baseline values using the most representative available 
monitoring data for 2000-2004, in consultation with the Administrator or 
his or her designee;
    (ii) For an implementation plan that is submitted by 2003, the 
period for establishing baseline visibility conditions for the period of 
the first long-term strategy is the most recent 5-year period for which 
visibility monitoring data are available for the mandatory Class I 
Federal areas addressed by the plan. For mandatory Class I Federal

[[Page 284]]

areas without onsite monitoring data, the State must establish baseline 
values using the most representative available monitoring data, in 
consultation with the Administrator or his or her designee;
    (iii) Natural visibility conditions for the most impaired and least 
impaired days. Natural visibility conditions must be calculated by 
estimating the degree of visibility impairment existing under natural 
conditions for the most impaired and least impaired days, based on 
available monitoring information and appropriate data analysis 
techniques; and
    (iv)(A) For the first implementation plan addressing the 
requirements of paragraphs (d) and (e) of this section, the number of 
deciviews by which baseline conditions exceed natural visibility 
conditions for the most impaired and least impaired days; or
    (B) For all future implementation plan revisions, the number of 
deciviews by which current conditions, as calculated under paragraph 
(f)(1) of this section, exceed natural visibility conditions for the 
most impaired and least impaired days.
    (3) Long-term strategy for regional haze. Each State listed in Sec. 
51.300(b)(3) must submit a long-term strategy that addresses regional 
haze visibility impairment for each mandatory Class I Federal area 
within the State and for each mandatory Class I Federal area located 
outside the State which may be affected by emissions from the State. The 
long-term strategy must include enforceable emissions limitations, 
compliance schedules, and other measures as necessary to achieve the 
reasonable progress goals established by States having mandatory Class I 
Federal areas. In establishing its long-term strategy for regional haze, 
the State must meet the following requirements:
    (i) Where the State has emissions that are reasonably anticipated to 
contribute to visibility impairment in any mandatory Class I Federal 
area located in another State or States, the State must consult with the 
other State(s) in order to develop coordinated emission management 
strategies. The State must consult with any other State having emissions 
that are reasonably anticipated to contribute to visibility impairment 
in any mandatory Class I Federal area within the State.
    (ii) Where other States cause or contribute to impairment in a 
mandatory Class I Federal area, the State must demonstrate that it has 
included in its implementation plan all measures necessary to obtain its 
share of the emission reductions needed to meet the progress goal for 
the area. If the State has participated in a regional planning process, 
the State must ensure it has included all measures needed to achieve its 
apportionment of emission reduction obligations agreed upon through that 
process.
    (iii) The State must document the technical basis, including 
modeling, monitoring and emissions information, on which the State is 
relying to determine its apportionment of emission reduction obligations 
necessary for achieving reasonable progress in each mandatory Class I 
Federal area it affects. The State may meet this requirement by relying 
on technical analyses developed by the regional planning organization 
and approved by all State participants. The State must identify the 
baseline emissions inventory on which its strategies are based. The 
baseline emissions inventory year is presumed to be the most recent year 
of the consolidate periodic emissions inventory.
    (iv) The State must identify all anthropogenic sources of visibility 
impairment considered by the State in developing its long-term strategy. 
The State should consider major and minor stationary sources, mobile 
sources, and area sources.
    (v) The State must consider, at a minimum, the following factors in 
developing its long-term strategy:
    (A) Emission reductions due to ongoing air pollution control 
programs, including measures to address reasonably attributable 
visibility impairment;
    (B) Measures to mitigate the impacts of construction activities;
    (C) Emissions limitations and schedules for compliance to achieve 
the reasonable progress goal;
    (D) Source retirement and replacement schedules;

[[Page 285]]

    (E) Smoke management techniques for agricultural and forestry 
management purposes including plans as currently exist within the State 
for these purposes;
    (F) Enforceability of emissions limitations and control measures; 
and
    (G) The anticipated net effect on visibility due to projected 
changes in point, area, and mobile source emissions over the period 
addressed by the long-term strategy.
    (4) Monitoring strategy and other implementation plan requirements. 
The State must submit with the implementation plan a monitoring strategy 
for measuring, characterizing, and reporting of regional haze visibility 
impairment that is representative of all mandatory Class I Federal areas 
within the State. This monitoring strategy must be coordinated with the 
monitoring strategy required in Sec. 51.305 for reasonably attributable 
visibility impairment. Compliance with this requirement may be met 
through participation in the Interagency Monitoring of Protected Visual 
Environments network. The implementation plan must also provide for the 
following:
    (i) The establishment of any additional monitoring sites or 
equipment needed to assess whether reasonable progress goals to address 
regional haze for all mandatory Class I Federal areas within the State 
are being achieved.
    (ii) Procedures by which monitoring data and other information are 
used in determining the contribution of emissions from within the State 
to regional haze visibility impairment at mandatory Class I Federal 
areas both within and outside the State.
    (iii) For a State with no mandatory Class I Federal areas, 
procedures by which monitoring data and other information are used in 
determining the contribution of emissions from within the State to 
regional haze visibility impairment at mandatory Class I Federal areas 
in other States.
    (iv) The implementation plan must provide for the reporting of all 
visibility monitoring data to the Administrator at least annually for 
each mandatory Class I Federal area in the State. To the extent 
possible, the State should report visibility monitoring data 
electronically.
    (v) A statewide inventory of emissions of pollutants that are 
reasonably anticipated to cause or contribute to visibility impairment 
in any mandatory Class I Federal area. The inventory must include 
emissions for a baseline year, emissions for the most recent year for 
which data are available, and estimates of future projected emissions. 
The State must also include a commitment to update the inventory 
periodically.
    (vi) Other elements, including reporting, recordkeeping, and other 
measures, necessary to assess and report on visibility.
    (e) Best Available Retrofit Technology (BART) requirements for 
regional haze visibility impairment. The State must submit an 
implementation plan containing emission limitations representing BART 
and schedules for compliance with BART for each BART-eligible source 
that may reasonably be anticipated to cause or contribute to any 
impairment of visibility in any mandatory Class I Federal area, unless 
the State demonstrates that an emissions trading program or other 
alternative will achieve greater reasonable progress toward natural 
visibility conditions.
    (1) To address the requirements for BART, the State must submit an 
implementation plan containing the following plan elements and include 
documentation for all required analyses:
    (i) A list of all BART-eligible sources within the State.
    (ii) A determination of BART for each BART-eligible source in the 
State that emits any air pollutant which may reasonably be anticipated 
to cause or contribute to any impairment of visibility in any mandatory 
Class I Federal area. All such sources are subject to BART.
    (A) The determination of BART must be based on an analysis of the 
best system of continuous emission control technology available and 
associated emission reductions achievable for each BART-eligible source 
that is subject to BART within the State. In this analysis, the State 
must take into consideration the technology available, the costs of 
compliance, the energy and nonair quality environmental impacts of 
compliance, any pollution control

[[Page 286]]

equipment in use at the source, the remaining useful life of the source, 
and the degree of improvement in visibility which may reasonably be 
anticipated to result from the use of such technology.
    (B) The determination of BART for fossil-fuel fired power plants 
having a total generating capacity greater than 750 megawatts must be 
made pursuant to the guidelines in appendix Y of this part (Guidelines 
for BART Determinations Under the Regional Haze Rule).
    (C) Exception. A State is not required to make a determination of 
BART for SO2 or for NOX if a BART-eligible source 
has the potential to emit less than 40 tons per year of such 
pollutant(s), or for PM10 if a BART-eligible source emits 
less than 15 tons per year of such pollutant.
    (iii) If the State determines in establishing BART that 
technological or economic limitations on the applicability of 
measurement methodology to a particular source would make the imposition 
of an emission standard infeasible, it may instead prescribe a design, 
equipment, work practice, or other operational standard, or combination 
thereof, to require the application of BART. Such standard, to the 
degree possible, is to set forth the emission reduction to be achieved 
by implementation of such design, equipment, work practice or operation, 
and must provide for compliance by means which achieve equivalent 
results.
    (iv) A requirement that each source subject to BART be required to 
install and operate BART as expeditiously as practicable, but in no 
event later than 5 years after approval of the implementation plan 
revision.
    (v) A requirement that each source subject to BART maintain the 
control equipment required by this subpart and establish procedures to 
ensure such equipment is properly operated and maintained.
    (2) A State may opt to implement an emissions trading program or 
other alternative measure rather than to require sources subject to BART 
to install, operate, and maintain BART. To do so, the State must 
demonstrate that this emissions trading program or other alternative 
measure will achieve greater reasonable progress than would be achieved 
through the installation and operation of BART. To make this 
demonstration, the State must submit an implementation plan containing 
the following plan elements and include documentation for all required 
analyses:
    (i) A demonstration that the emissions trading program or other 
alternative measure will achieve greater reasonable progress than would 
have resulted from the installation and operation of BART at all sources 
subject to BART in the State. This demonstration must be based on the 
following:
    (A) A list of all BART-eligible sources within the State.
    (B) An analysis of the best system of continuous emission control 
technology available and associated emission reductions achievable for 
each source within the State subject to BART. In this analysis, the 
State must take into consideration the technology available, the costs 
of compliance, the energy and nonair quality environmental impacts of 
compliance, any pollution control equipment in use at the source, and 
the remaining useful life of the source. The best system of continuous 
emission control technology and the above factors may be determined on a 
source category basis. The State may elect to consider both source-
specific and category-wide information, as appropriate, in conducting 
its analysis.
    (C) An analysis of the degree of visibility improvement that would 
be achieved in each mandatory Class I Federal area as a result of the 
emission reductions achievable from all such sources subject to BART 
located within the region that contributes to visibility impairment in 
the Class I area, based on the analysis conducted under paragraph 
(e)(2)(i)(B) of this section.
    (ii) A demonstration that the emissions trading program or 
alternative measure will apply, at a minimum, to all BART-eligible 
sources in the State. Those sources having a federally enforceable 
emission limitation determined by the State and approved by EPA as 
meeting BART in accordance with Sec. 51.302(c) or paragraph (e)(1) of 
this section do not need to meet the requirements of the emissions 
trading program or alternative measure, but may choose to participate if 
they meet

[[Page 287]]

the requirements of the emissions trading program or alternative 
measure.
    (iii) A requirement that all necessary emission reductions take 
place during the period of the first long-term strategy for regional 
haze. To meet this requirement, the State must provide a detailed 
description of the emissions trading program or other alternative 
measure, including schedules for implementation, the emission reductions 
required by the program, all necessary administrative and technical 
procedures for implementing the program, rules for accounting and 
monitoring emissions, and procedures for enforcement.
    (iv) A demonstration that the emission reductions resulting from the 
emissions trading program or other alternative measure will be surplus 
to those reductions resulting from measures adopted to meet requirements 
of the CAA as of the baseline date of the SIP.
    (v) At the State's option, a provision that the emissions trading 
program or other alternative measure may include a geographic 
enhancement to the program to address the requirement under Sec. 
51.302(c) related to BART for reasonably attributable impairment from 
the pollutants covered under the emissions trading program or other 
alternative measure.
    (3) A State which opts under 40 CFR 51.308(e)(2) to implement an 
emissions trading program or other alternative measure rather than to 
require sources subject to BART to install, operate, and maintain BART 
may satisfy the final step of the demonstration required by that section 
as follows: If the distribution of emissions is not substantially 
different than under BART, and the alternative measure results in 
greater emission reductions, then the alternative measure may be deemed 
to achieve greater reasonable progress. If the distribution of emissions 
is significantly different, the State must conduct dispersion modeling 
to determine differences in visibility between BART and the trading 
program for each impacted Class I area, for the worst and best 20 
percent of days. The modeling would demonstrate ``greater reasonable 
progress'' if both of the following two criteria are met:
    (i) Visibility does not decline in any Class I area, and
    (ii) There is an overall improvement in visibility, determined by 
comparing the average differences between BART and the alternative over 
all affected Class I areas.
    (4) A State that opts to participate in the Clean Air Interstate 
Rule cap-and-trade and trade program under part 96 AAA-EEE need not 
require affected BART-eligible EGU's to install, operate, and maintain 
BART. A State that chooses this option may also include provisions for a 
geographic enhancement to the program to address the requirement under 
Sec. 51.302(c) related to BART for reasonably attributable impairment 
from the pollutants covered by the CAIR cap-and-trade program.
    (5) After a State has met the requirements for BART or implemented 
emissions trading program or other alternative measure that achieves 
more reasonable progress than the installation and operation of BART, 
BART-eligible sources will be subject to the requirements of paragraph 
(d) of this section in the same manner as other sources.
    (6) Any BART-eligible facility subject to the requirement under 
paragraph (e) of this section to install, operate, and maintain BART may 
apply to the Administrator for an exemption from that requirement. An 
application for an exemption will be subject to the requirements of 
Sec. 51.303(a)(2)-(h).
    (f) Requirements for comprehensive periodic revisions of 
implementation plans for regional haze. Each State identified in Sec. 
51.300(b)(3) must revise and submit its regional haze implementation 
plan revision to EPA by July 31, 2018 and every ten years thereafter. In 
each plan revision, the State must evaluate and reassess all of the 
elements required in paragraph (d) of this section, taking into account 
improvements in monitoring data collection and analysis techniques, 
control technologies, and other relevant factors. In evaluating and 
reassessing these elements, the State must address the following:
    (1) Current visibility conditions for the most impaired and least 
impaired days, and actual progress made towards natural conditions 
during the previous implementation period. The period for calculating 
current visibility

[[Page 288]]

conditions is the most recent five year period preceding the required 
date of the implementation plan submittal for which data are available. 
Current visibility conditions must be calculated based on the annual 
average level of visibility impairment for the most and least impaired 
days for each of these five years. Current visibility conditions are the 
average of these annual values.
    (2) The effectiveness of the long-term strategy for achieving 
reasonable progress goals over the prior implementation period(s); and
    (3) Affirmation of, or revision to, the reasonable progress goal in 
accordance with the procedures set forth in paragraph (d)(1) of this 
section. If the State established a reasonable progress goal for the 
prior period which provided a slower rate of progress than that needed 
to attain natural conditions by the year 2064, the State must evaluate 
and determine the reasonableness, based on the factors in paragraph 
(d)(1)(i)(A) of this section, of additional measures that could be 
adopted to achieve the degree of visibility improvement projected by the 
analysis contained in the first implementation plan described in 
paragraph (d)(1)(i)(B) of this section.
    (g) Requirements for periodic reports describing progress towards 
the reasonable progress goals. Each State identified in Sec. 
51.300(b)(3) must submit a report to the Administrator every 5 years 
evaluating progress towards the reasonable progress goal for each 
mandatory Class I Federal area located within the State and in each 
mandatory Class I Federal area located outside the State which may be 
affected by emissions from within the State. The first progress report 
is due 5 years from submittal of the initial implementation plan 
addressing paragraphs (d) and (e) of this section. The progress reports 
must be in the form of implementation plan revisions that comply with 
the procedural requirements of Sec. 51.102 and Sec. 51.103. Periodic 
progress reports must contain at a minimum the following elements:
    (1) A description of the status of implementation of all measures 
included in the implementation plan for achieving reasonable progress 
goals for mandatory Class I Federal areas both within and outside the 
State.
    (2) A summary of the emissions reductions achieved throughout the 
State through implementation of the measures described in paragraph 
(g)(1) of this section.
    (3) For each mandatory Class I Federal area within the State, the 
State must assess the following visibility conditions and changes, with 
values for most impaired and least impaired days expressed in terms of 
5-year averages of these annual values.
    (i) The current visibility conditions for the most impaired and 
least impaired days;
    (ii) The difference between current visibility conditions for the 
most impaired and least impaired days and baseline visibility 
conditions;
    (iii) The change in visibility impairment for the most impaired and 
least impaired days over the past 5 years;
    (4) An analysis tracking the change over the past 5 years in 
emissions of pollutants contributing to visibility impairment from all 
sources and activities within the State. Emissions changes should be 
identified by type of source or activity. The analysis must be based on 
the most recent updated emissions inventory, with estimates projected 
forward as necessary and appropriate, to account for emissions changes 
during the applicable 5-year period.
    (5) An assessment of any significant changes in anthropogenic 
emissions within or outside the State that have occurred over the past 5 
years that have limited or impeded progress in reducing pollutant 
emissions and improving visibility.
    (6) An assessment of whether the current implementation plan 
elements and strategies are sufficient to enable the State, or other 
States with mandatory Federal Class I areas affected by emissions from 
the State, to meet all established reasonable progress goals.
    (7) A review of the State's visibility monitoring strategy and any 
modifications to the strategy as necessary.
    (h) Determination of the adequacy of existing implementation plan. 
At the same time the State is required to submit any 5-year progress 
report to EPA in accordance with paragraph (g) of this section, the 
State must also take one of the following actions based upon

[[Page 289]]

the information presented in the progress report:
    (1) If the State determines that the existing implementation plan 
requires no further substantive revision at this time in order to 
achieve established goals for visibility improvement and emissions 
reductions, the State must provide to the Administrator a negative 
declaration that further revision of the existing implementation plan is 
not needed at this time.
    (2) If the State determines that the implementation plan is or may 
be inadequate to ensure reasonable progress due to emissions from 
sources in another State(s) which participated in a regional planning 
process, the State must provide notification to the Administrator and to 
the other State(s) which participated in the regional planning process 
with the States. The State must also collaborate with the other State(s) 
through the regional planning process for the purpose of developing 
additional strategies to address the plan's deficiencies.
    (3) Where the State determines that the implementation plan is or 
may be inadequate to ensure reasonable progress due to emissions from 
sources in another country, the State shall provide notification, along 
with available information, to the Administrator.
    (4) Where the State determines that the implementation plan is or 
may be inadequate to ensure reasonable progress due to emissions from 
sources within the State, the State shall revise its implementation plan 
to address the plan's deficiencies within one year.
    (i) What are the requirements for State and Federal Land Manager 
coordination? (1) By November 29, 1999, the State must identify in 
writing to the Federal Land Managers the title of the official to which 
the Federal Land Manager of any mandatory Class I Federal area can 
submit any recommendations on the implementation of this subpart 
including, but not limited to:
    (i) Identification of impairment of visibility in any mandatory 
Class I Federal area(s); and
    (ii) Identification of elements for inclusion in the visibility 
monitoring strategy required by Sec. 51.305 and this section.
    (2) The State must provide the Federal Land Manager with an 
opportunity for consultation, in person and at least 60 days prior to 
holding any public hearing on an implementation plan (or plan revision) 
for regional haze required by this subpart. This consultation must 
include the opportunity for the affected Federal Land Managers to 
discuss their:
    (i) Assessment of impairment of visibility in any mandatory Class I 
Federal area; and
    (ii) Recommendations on the development of the reasonable progress 
goal and on the development and implementation of strategies to address 
visibility impairment.
    (3) In developing any implementation plan (or plan revision), the 
State must include a description of how it addressed any comments 
provided by the Federal Land Managers.
    (4) The plan (or plan revision) must provide procedures for 
continuing consultation between the State and Federal Land Manager on 
the implementation of the visibility protection program required by this 
subpart, including development and review of implementation plan 
revisions and 5-year progress reports, and on the implementation of 
other programs having the potential to contribute to impairment of 
visibility in mandatory Class I Federal areas.

[64 FR 35765, July 1, 1999, as amended at 70 FR 39156, July 6, 2005]



Sec. 51.309  Requirements related to the Grand Canyon Visibility 
Transport Commission.

    (a) What is the purpose of this section? This section establishes 
the requirements for the first regional haze implementation plan to 
address regional haze visibility impairment in the 16 Class I areas 
covered by the Grand Canyon Visibility Transport Commission Report. For 
the years 2003 to 2018, certain States (defined in paragraph (b) of this 
section as Transport Region States) may choose to implement the 
Commission's recommendations within the framework of the national 
regional haze program and applicable requirements of the Act by 
complying with the provisions of this section, as supplemented by an 
approvable Annex to

[[Page 290]]

the Commission Report as required by paragraph (f) of this section. If a 
transport region State submits an implementation plan which is approved 
by EPA as meeting the requirements of this section, it will be deemed to 
comply with the requirements for reasonable progress for the period from 
approval of the plan to 2018.
    (b) Definitions. For the purposes of this section:
    (1) 16 Class I areas means the following mandatory Class I Federal 
areas on the Colorado Plateau: Grand Canyon National Park, Sycamore 
Canyon Wilderness, Petrified Forest National Park, Mount Baldy 
Wilderness, San Pedro Parks Wilderness, Mesa Verde National Park, 
Weminuche Wilderness, Black Canyon of the Gunnison Wilderness, West Elk 
Wilderness, Maroon Bells Wilderness, Flat Tops Wilderness, Arches 
National Park, Canyonlands National Park, Capital Reef National Park, 
Bryce Canyon National Park, and Zion National Park.
    (2) Transport Region State means one of the States that is included 
within the Transport Region addressed by the Grand Canyon Visibility 
Transport Commission (Arizona, California, Colorado, Idaho, Nevada, New 
Mexico, Oregon, Utah, and Wyoming).
    (3) Commission Report means the report of the Grand Canyon 
Visibility Transport Commission entitled ``Recommendations for Improving 
Western Vistas,'' dated June 10, 1996.
    (4) Fire means wildfire, wildland fire (including prescribed natural 
fire), prescribed fire, and agricultural burning conducted and occurring 
on Federal, State, and private wildlands and farmlands.
    (5) Milestone means the maximum level of annual regional sulfur 
dioxide emissions for a given year, assessed annually consistent with 
paragraph (h)(2) of this section beginning in the year 2003.
    (6) Continuous decline in total mobile source emissions means that 
the projected level of emissions from mobile sources of each listed 
pollutant in 2008, 2013, and 2018, are less than the projected level of 
emissions from mobile sources of each listed pollutant for the previous 
period (i.e., 2008 less than 2003; 2013 less than 2008; and 2018 less 
than 2013).
    (7) Geographic enhancement means a method, procedure, or process to 
allow a broad regional strategy, such as a milestone or backstop market 
trading program designed to achieve greater reasonable progress than 
BART for regional haze, to accommodate BART for reasonably attributable 
impairment.
    (8) Base year means the year, generally a year between 1996 and 
1998, for which data for a source included within the program were used 
by the WRAP to calculate base year emissions as a starting point for 
development of the Annex required by paragraph (f) of this section.
    (9) Forecast means the process used by the WRAP to predict future 
emissions for purposes of developing the milestones required by 
paragraph (f) of this section.
    (10) Reforecast means a corrected forecast, based upon reapplication 
of the forecasting process after correction of base year emissions 
estimates.
    (11) BHP San Manuel means:
    (i) The copper smelter located in San Manuel, Arizona which operated 
during 1990, but whose operations were suspended during the year 2000,
    (ii) The same smelter in the event of a change of name or ownership.
    (12) Phelps Dodge Hidalgo means:
    (i) The copper smelter located in Hidalgo, New Mexico which operated 
during 1990, but whose operations were suspended during the year 2000,
    (ii) The same smelter in the event of a change of name or ownership.
    (13) Eligible renewable energy resource, for purposes of 40 CFR 
51.309, means electricity generated by non-nuclear and non-fossil low or 
no air emission technologies.
    (c) Implementation Plan Schedule. Each Transport Region State may 
meet the requirements of Sec. 51.308(b) through (e) by submitting an 
implementation plan that complies with the requirements of this section. 
Each Transport Region State must submit an implementation plan 
addressing regional haze visibility impairment in the 16 Class I areas 
no later than December 31, 2003. Indian Tribes may submit implementation 
plans after the December 31, 2003 deadline. A Transport

[[Page 291]]

Region State that does not submit an implementation plan that complies 
with the requirements of this section (or whose plan does not comply 
with all of the requirements of this section) is subject to the 
requirements of Sec. 51.308 in the same manner and to the same extent 
as any State not included within the Transport Region.
    (d) Requirements of the first implementation plan for States 
electing to adopt all of the recommendations of the Commission Report. 
Except as provided for in paragraph (e) of this section, each Transport 
Region State must submit an implementation plan that meets the following 
requirements:
    (1) Time period covered. The implementation plan must be effective 
for the entire time period between December 31, 2003 and December 31, 
2018.
    (2) Projection of visibility improvement. For each of the 16 
mandatory Class I areas located within the Transport Region State, the 
plan must include a projection of the improvement in visibility 
conditions (expressed in deciviews, and in any additional ambient 
visibility metrics deemed appropriate by the State) expected through the 
year 2018 for the most impaired and least impaired days, based on the 
implementation of all measures as required in the Commission report and 
the provisions in this section. The projection must be made in 
consultation with other Transport Region States with sources which may 
be reasonably anticipated to contribute to visibility impairment in the 
relevant Class I area. The projection may be based on a satisfactory 
regional analysis.
    (3) Treatment of clean-air corridors. The plan must describe and 
provide for implementation of comprehensive emission tracking strategies 
for clean-air corridors to ensure that the visibility does not degrade 
on the least-impaired days at any of the 16 Class I areas. The strategy 
must include:
    (i) An identification of clean-air corridors. The EPA will evaluate 
the State's identification of such corridors based upon the reports of 
the Commission's Meteorology Subcommittee and any future updates by a 
successor organization;
    (ii) Within areas that are clean-air corridors, an identification of 
patterns of growth or specific sites of growth that could cause, or are 
causing, significant emissions increases that could have, or are having, 
visibility impairment at one or more of the 16 Class I areas.
    (iii) In areas outside of clean-air corridors, an identification of 
significant emissions growth that could begin, or is beginning, to 
impair the quality of air in the corridor and thereby lead to visibility 
degradation for the least-impaired days in one or more of the 16 Class I 
areas.
    (iv) If impairment of air quality in clean air corridors is 
identified pursuant to paragraphs (d)(3)(ii) and (iii) of this section, 
an analysis of the effects of increased emissions, including provisions 
for the identification of the need for additional emission reductions 
measures, and implementation of the additional measures where necessary.
    (v) A determination of whether other clean air corridors exist for 
any of the 16 Class I areas. For any such clean air corridors, an 
identification of the necessary measures to protect against future 
degradation of air quality in any of the 16 Class I areas.
    (4) Implementation of stationary source reductions. The first 
implementation plan submission must include:
    (i) Sulfur dioxide milestones consistent with paragraph (h)(1) of 
this section.
    (ii) Monitoring and reporting of sulfur dioxide emissions. The plan 
submission must include provisions requiring the annual monitoring and 
reporting of actual stationary source sulfur dioxide emissions within 
the State. The monitoring and reporting data must be sufficient to 
determine whether a 13 percent reduction in actual emissions has 
occurred between the years 1990 and 2000, and for determining annually 
whether the milestone for each year between 2003 and 2018 is exceeded, 
consistent with paragraph (h) (2) of this section. The plan submission 
must provide for reporting of these data by the State to the 
Administrator and to the regional planning organization consistent with 
paragraph (h)(2) of this section.
    (iii) Criteria and Procedures for a Market Trading Program. The plan

[[Page 292]]

must include the criteria and procedures for activating a market trading 
program consistent with paragraphs (h)(3) and (h)(4) of this section. 
The plan must also provide for implementation plan assessments of the 
program in the years 2008, 2013, and 2018.
    (iv) Provisions for market trading program compliance reporting 
consistent with paragraph (h)(4) of this section.
    (v) Provisions for stationary source NOX and PM. The plan 
submission must include a report which assesses emissions control 
strategies for stationary source NOX and PM, and the degree 
of visibility improvement that would result from such strategies. In the 
report, the State must evaluate and discuss the need to establish 
emission milestones for NOX and PM to avoid any net increase 
in these pollutants from stationary sources within the transport region, 
and to support potential future development and implementation of a 
multipollutant and possibly multisource market-based program. The plan 
submission must provide for an implementation plan revision, containing 
any necessary long-term strategies and BART requirements for stationary 
source PM and NOX (including enforceable limitations, 
compliance schedules, and other measures) by no later than December 31, 
2008.
    (5) Mobile sources. The plan submission must provide for:
    (i) Statewide inventories of onroad and nonroad mobile source 
emissions of VOC, NOX, SO2, PM2.5, 
elemental carbon, and organic carbon for the years 2003, 2008, 2013, and 
2018.
    (A) The inventories must demonstrate a continuous decline in total 
mobile source emissions (onroad plus nonroad; tailpipe and evaporative) 
of VOC, NOX, PM2.5, elemental carbon, and organic 
carbon, evaluated separately. If the inventories show a continuous 
decline in total mobile source emissions of each of these pollutants 
over the period 2003-2018, no further action is required as part of this 
plan to address mobile source emissions of these pollutants. If the 
inventories do not show a continuous decline in mobile source emissions 
of one or more of these pollutants over the period 2003-2018, the plan 
submission must provide for an implementation plan revision by no later 
than December 31, 2008 containing any necessary long-term strategies to 
achieve a continuous decline in total mobile source emissions of the 
pollutant(s), to the extent practicable, considering economic and 
technological reasonableness and federal preemption of vehicle standards 
and fuel standards under title II of the CAA.
    (B) The plan submission must also provide for an implementation plan 
revision by no later than December 31, 2008 containing any long-term 
strategies necessary to reduce emissions of SO2 from nonroad 
mobile sources, consistent with the goal of reasonable progress. In 
assessing the need for such long-term strategies, the State may consider 
emissions reductions achieved or anticipated from any new Federal 
standards for sulfur in nonroad diesel fuel.
    (ii) Interim reports to EPA and the public in years 2003, 2008, 
2013, and 2018 on the implementation status of the regional and local 
strategies recommended by the Commission Report to address mobile source 
emissions.
    (6) Programs related to fire. The plan must provide for:
    (i) Documentation that all Federal, State, and private prescribed 
fire programs within the State evaluate and address the degree 
visibility impairment from smoke in their planning and application. In 
addition the plan must include smoke management programs that include 
all necessary components including, but not limited to, actions to 
minimize emissions, evaluation of smoke dispersion, alternatives to 
fire, public notification, air quality monitoring, surveillance and 
enforcement, and program evaluation.
    (ii) A statewide inventory and emissions tracking system (spatial 
and temporal) of VOC, NOX, elemental and organic carbon, and 
fine particle emissions from fire. In reporting and tracking emissions 
from fire from within the State, States may use information from 
regional data-gathering and tracking initiatives.

[[Page 293]]

    (iii) Identification and removal wherever feasible of any 
administrative barriers to the use of alternatives to burning in 
Federal, State, and private prescribed fire programs within the State.
    (iv) Enhanced smoke management programs for fire that consider 
visibility effects, not only health and nuisance objectives, and that 
are based on the criteria of efficiency, economics, law, emission 
reduction opportunities, land management objectives, and reduction of 
visibility impact.
    (v) Establishment of annual emission goals for fire, excluding 
wildfire, that will minimize emission increases from fire to the maximum 
extent feasible and that are established in cooperation with States, 
tribes, Federal land management agencies, and private entities.
    (7) Area sources of dust emissions from paved and unpaved roads. The 
plan must include an assessment of the impact of dust emissions from 
paved and unpaved roads on visibility conditions in the 16 Class I 
Areas. If such dust emissions are determined to be a significant 
contributor to visibility impairment in the 16 Class I areas, the State 
must implement emissions management strategies to address the impact as 
necessary and appropriate.
    (8) Pollution prevention. The plan must provide for:
    (i) An initial summary of all pollution prevention programs 
currently in place, an inventory of all renewable energy generation 
capacity and production in use, or planned as of the year 2002 
(expressed in megawatts and megawatt-hours), the total energy generation 
capacity and production for the State, the percent of the total that is 
renewable energy, and the State's anticipated contribution toward the 
renewable energy goals for 2005 and 2015, as provided in paragraph 
(d)(8)(vi) of this section.
    (ii) Programs to provide incentives that reward efforts that go 
beyond compliance and/or achieve early compliance with air-pollution 
related requirements.
    (iii) Programs to preserve and expand energy conservation efforts.
    (iv) The identification of specific areas where renewable energy has 
the potential to supply power where it is now lacking and where 
renewable energy is most cost-effective.
    (v) Projections of the short- and long-term emissions reductions, 
visibility improvements, cost savings, and secondary benefits associated 
with the renewable energy goals, energy efficiency and pollution 
prevention activities.
    (vi) A description of the programs relied on to achieve the State's 
contribution toward the Commission's goal that renewable energy will 
comprise 10 percent of the regional power needs by 2005 and 20 percent 
by 2015, and a demonstration of the progress toward achievement of the 
renewable energy goals in the years 2003, 2008, 2013, and 2018. This 
description must include documentation of the potential for renewable 
energy resources, the percentage of renewable energy associated with new 
power generation projects implemented or planned, and the renewable 
energy generation capacity and production in use and planned in the 
State. To the extent that it is not feasible for a State to meet its 
contribution to the regional renewable energy goals, the State must 
identify in the progress reports the measures implemented to achieve its 
contribution and explain why meeting the State's contribution was not 
feasible.
    (9) Implementation of additional recommendations. The plan must 
provide for implementation of all other recommendations in the 
Commission report that can be practicably included as enforceable 
emission limits, schedules of compliance, or other enforceable measures 
(including economic incentives) to make reasonable progress toward 
remedying existing and preventing future regional haze in the 16 Class I 
areas. The State must provide a report to EPA and the public in 2003, 
2008, 2013, and 2018 on the progress toward developing and implementing 
policy or strategy options recommended in the Commission Report.
    (10) Periodic implementation plan revisions. Each Transport Region 
State must submit to the Administrator periodic reports in the years 
2008, 2013, and 2018. The progress reports must be in the form of 
implementation plan revisions that comply with the procedural 
requirements of Sec. 51.102 and Sec. 51.103.

[[Page 294]]

    (i) The report will assess the area for reasonable progress as 
provided in this section for mandatory Class I Federal area(s) located 
within the State and for mandatory Class I Federal area(s) located 
outside the State which may be affected by emissions from within the 
State. This demonstration may be based on assessments conducted by the 
States and/or a regional planning body. The progress reports must 
contain at a minimum the following elements:
    (A) A description of the status of implementation of all measures 
included in the implementation plan for achieving reasonable progress 
goals for mandatory Class I Federal areas both within and outside the 
State.
    (B) A summary of the emissions reductions achieved throughout the 
State through implementation of the measures described in paragraph 
(d)(10)(i)(A) of this section.
    (C) For each mandatory Class I Federal area within the State, an 
assessment of the following: the current visibility conditions for the 
most impaired and least impaired days; the difference between current 
visibility conditions for the most impaired and least impaired days and 
baseline visibility conditions; the change in visibility impairment for 
the most impaired and least impaired days over the past 5 years.
    (D) An analysis tracking the change over the past 5 years in 
emissions of pollutants contributing to visibility impairment from all 
sources and activities within the State. Emissions changes should be 
identified by type of source or activity. The analysis must be based on 
the most recent updated emissions inventory, with estimates projected 
forward as necessary and appropriate, to account for emissions changes 
during the applicable 5-year period.
    (E) An assessment of any significant changes in anthropogenic 
emissions within or outside the State that have occurred over the past 5 
years that have limited or impeded progress in reducing pollutant 
emissions and improving visibility.
    (F) An assessment of whether the current implementation plan 
elements and strategies are sufficient to enable the State, or other 
States with mandatory Federal Class I areas affected by emissions from 
the State, to meet all established reasonable progress goals.
    (G) A review of the State's visibility monitoring strategy and any 
modifications to the strategy as necessary.
    (ii) At the same time the State is required to submit any 5-year 
progress report to EPA in accordance with paragaph (d)(10)(i) of this 
section, the State must also take one of the following actions based 
upon the information presented in the progress report:
    (A) If the State determines that the existing implementation plan 
requires no further substantive revision at this time in order to 
achieve established goals for visibility improvement and emissions 
reductions, the State must provide to the Administrator a negative 
declaration that further revision of the existing implementation plan is 
not needed at this time.
    (B) If the State determines that the implementation plan is or may 
be inadequate to ensure reasonable progress due to emissions from 
sources in another State(s) which participated in a regional planning 
process, the State must provide notification to the Administrator and to 
the other State(s) which participated in the regional planning process 
with the States. The State must also collaborate with the other State(s) 
through the regional planning process for the purpose of developing 
additional strategies to address the plan's deficiencies.
    (C) Where the State determines that the implementation plan is or 
may be inadequate to ensure reasonable progress due to emissions from 
sources in another country, the State shall provide notification, along 
with available information, to the Administrator.
    (D) Where the State determines that the implementation plan is or 
may be inadequate to ensure reasonable progress due to emissions from 
within the State, the State shall develop additional strategies to 
address the plan deficiencies and revise the implementation plan no 
later than one year from the date that the progress report was due.
    (11) State planning and interstate coordination. In complying with 
the requirements of this section, States may include emission reductions 
strategies

[[Page 295]]

that are based on coordinated implementation with other States. Examples 
of these strategies include economic incentive programs and 
transboundary emissions trading programs. The implementation plan must 
include documentation of the technical and policy basis for the 
individual State apportionment (or the procedures for apportionment 
throughout the trans-boundary region), the contribution addressed by the 
State's plan, how it coordinates with other State plans, and compliance 
with any other appropriate implementation plan approvability criteria. 
States may rely on the relevant technical, policy and other analyses 
developed by a regional entity (such as the Western Regional Air 
Partnership) in providing such documentation. Conversely, States may 
elect to develop their own programs without relying on work products 
from a regional entity.
    (12) Tribal implementation. Consistent with 40 CFR Part 49, tribes 
within the Transport Region may implement the required visibility 
programs for the 16 Class I areas, in the same manner as States, 
regardless of whether such tribes have participated as members of a 
visibility transport commission.
    (e) States electing not to implement the commission recommendations. 
Any Transport Region State may elect not to implement the Commission 
recommendations set forth in paragraph (d) of this section. Such States 
are required to comply with the timelines and requirements of Sec. 
51.308. Any Transport Region State electing not to implement the 
Commission recommendations must advise the other States in the Transport 
Region of the nature of the program and the effect of the program on 
visibility-impairing emissions, so that other States can take this 
information into account in developing programs under this section.
    (f) Annex to the Commission Report. (1) A Transport Region State may 
choose to comply with the provisions of this section and by doing so 
shall satisfy the requirements of Sec. 51.308(b) through (e) only if 
the Grand Canyon Visibility Transport Commission (or a regional planning 
body formed to implement the Commission recommendations) submits a 
satisfactory annex to the Commission Report no later than October 1, 
2000. To be satisfactory, the Annex must contain the following elements:
    (i) The annex must contain quantitative emissions milestones for 
stationary source sulfur dioxide emissions for the reporting years 2003, 
2008, 2013 and 2018. The milestones must provide for steady and 
continuing emissions reductions for the 2003-2018 time period consistent 
with the Commission's definition of reasonable progress, its goal of 50 
to 70 percent reduction in sulfur dioxide emissions from 1990 actual 
emission levels by 2040, applicable requirements under the CAA, and the 
timing of implementation plan assessments of progress and identification 
of deficiencies which will be due in the years 2008, 2013, and 2018. The 
milestones must be shown to provide for greater reasonable progress than 
would be achieved by application of best available retrofit technology 
(BART) pursuant to Sec. 51.308(e)(2) and would be approvable in lieu of 
BART.
    (ii) The annex must contain documentation of the market trading 
program or other programs to be implemented pursuant to paragraph (d)(4) 
of this section if current programs and voluntary measures are not 
sufficient to meet the required emission reduction milestones. This 
documentation must include model rules, memoranda of understanding, and 
other documentation describing in detail how emission reduction progress 
will be monitored, what conditions will require the market trading 
program to be activated, how allocations will be performed, and how the 
program will operate.
    (2) The Commission may elect, at the same time it submits the annex, 
to make recommendations intended to demonstrate reasonable progress for 
other mandatory Class I areas (beyond the original 16) within the 
Transport Region States, including the technical and policy 
justification for these additional mandatory Class I Federal areas in 
accordance with the provisions of paragraph (g) of this section.
    (3) The EPA will publish the annex upon receipt. If EPA finds that 
the annex meets the requirements of paragraph (f)(1) of this section and 
assures reasonable progress, then, after public

[[Page 296]]

notice and comment, EPA will amend the requirements of this section to 
incorporate the provisions of the annex. If EPA finds that the annex 
does not meet the requirements of paragraph (f)(1) of this section, or 
does not assure reasonable progress, or if EPA finds that the annex is 
not received, then each Transport Region State must submit an 
implementation plan for regional haze meeting all of the requirements of 
Sec. 51.308.
    (4) In accordance with the provisions under paragraph (f)(1) of this 
section, the annex may include a geographic enhancement to the program 
provided for in paragraph (d)(4) of this section to address the 
requirement under Sec. 51.302(c) related to Best Available Retrofit 
Technology for reasonably attributable impairment from the pollutants 
covered by the milestones or the backstop market trading program. The 
geographic enhancement program may include an appropriate level of 
reasonably attributable impairment which may require additional emission 
reductions over and above those achieved under the milestones defines in 
paragraph (f)(1)(i) of this section.
    (g) Additional Class I areas. The following submittals must be made 
by Transport Region States implementing the provisions of this section 
as the basis for demonstrating reasonable progress for additional Class 
I areas in the Transport Region States. If a Transport Region State 
submits an implementation plan which is approved by EPA as meeting the 
requirements of this section, it will be deemed to comply with the 
requirements for reasonable progress for the period from approval of the 
plan to 2018.
    (1) In the plan submitted for the 16 Class I areas no later than 
December 31, 2003, a declaration indicating whether other Class I areas 
will be addressed under Sec. 51.308 or paragraphs (g)(2) and (3) of 
this section.
    (2) In a plan submitted no later than December 31, 2008, provide a 
demonstration of expected visibility conditions for the most impaired 
and least impaired days at the additional mandatory Class I Federal 
area(s) based on emissions projections from the long-term strategies in 
the implementation plan. This demonstration may be based on assessments 
conducted by the States and/or a regional planning body.
    (3) In a plan submitted no later than December 31, 2008, provide 
revisions to the plan submitted under paragraph (c) of this section, 
including provisions to establish reasonable progress goals and 
implement any additional measures necessary to demonstrate reasonable 
progress for the additional mandatory Federal Class I areas. These 
revisions must comply with the provisions of Sec. 51.308(d)(1) through 
(4).
    (4) The following provisions apply for Transport Region States 
establishing reasonable progress goals and adopting any additional 
measures for Class I areas other than the 16 Class I areas under 
paragraphs (g)(2) and (3) of this section.
    (i) In developing long-term strategies pursuant to Sec. 
51.308(d)(3), the State may build upon the strategies implemented under 
paragraph (d) of this section, and take full credit for the visibility 
improvement achieved through these strategies.
    (ii) The requirement under Sec. 51.308(e) related to Best Available 
Retrofit Technology for regional haze is deemed to be satisfied for 
pollutants addressed by the milestones and backstop trading program if, 
in establishing the emission reductions milestones under paragraph (f) 
of this section, it is shown that greater reasonable progress will be 
achieved for these Class I areas than would be achieved through the 
application of source-specific BART emission limitations under Sec. 
51.308(e)(1).
    (iii) The Transport Region State may consider whether any strategies 
necessary to achieve the reasonable progress goals required by paragraph 
(g)(3) of this section are incompatible with the strategies implemented 
under paragraph (d) of this section to the extent the State adequately 
demonstrates that the incompatibility is related to the costs of the 
compliance, the time necessary for compliance, the energy and no air 
quality environmental impacts of compliance, or the remaining useful 
life of any existing source subject to such requirements.
    (h) Emissions Reduction Program for Major Industrial Sources of 
Sulfur Dioxide. The first implementation plan submission must include a 
stationary

[[Page 297]]

source emissions reductions program for major industrial sources of 
sulfur dioxide that meets the following requirements:
    (1) Regional sulfur dioxide milestones. The plan must include the 
milestones in Table 1, and provide for the adjustments in paragraphs 
(h)(1)(i) through (iv) of this section. Table 1 follows:

              Table 1--Sulfur Dioxide Emissions Milestones
------------------------------------------------------------------------
     Column 1           Column 2          Column 3          Column 4
------------------------------------------------------------------------
                                      . . . if neither    . . . and the
                    . . . if BHP San   BHP San Manuel       emission
                       Manuel and     nor Phelps Dodge   inventories for
                      Phelps Dodge     Hidalgo resumes  these years will
For the year . . .   Hidalgo resume    operation, the       determine
                     operation, the   minimum regional       whether
                    maximum regional   sulfur dioxide     emissions are
                     sulfur dioxide   milestone is . .   greater than or
                    milestone is . .          .           less than the
                            .                              milestone:
------------------------------------------------------------------------
2003..............  720,000 tons....  682,000 tons....  2003.
2004..............  720,000 tons....  682,000 tons....  Average of 2003
                                                         and 2004.
2005..............  720,000 tons....  682,000 tons....  Average of 2003,
                                                         2004 and 2005.
2006..............  720,000 tons....  682,000 tons....  Average of 2004,
                                                         2005 and 2006.
2007..............  720,000 tons....  682,000 tons....  Average of 2005,
                                                         2006 and 2007.
2008..............  718,333 tons....  680,333 tons....  Average of 2006,
                                                         2007 and 2008.
2009..............  716,667 tons....  678,667 tons....  Average of 2007,
                                                         2008 and 2009.
2010..............  715,000 tons....  677,000 tons....  Average of 2008,
                                                         2009 and 2010.
2011..............  715,000 tons....  677,000 tons....  Average of 2009,
                                                         2010 and 2011.
2012..............  715,000 tons....  677,000 tons....  Average of 2010,
                                                         2011 and 2012.
2013..............  695,000 tons....  659,667 tons....  Average of 2011,
                                                         2012 and 2013.
2014..............  675,000 tons....  642,333 tons....  Average of 2012,
                                                         2013 and 2014.
2015..............  655,000 tons....  625,000 tons....  Average of 2013,
                                                         2014 and 2015.
2016..............  655,000 tons....  625,000 tons....  Average of 2014,
                                                         2015 and 2016.
2017..............  655,000 tons....  625,000 tons....  Average of 2015,
                                                         2016 and 2017.
2018..............  510,000 tons....  480,000 tons....  Year 2018 only.
Each year after     no more than      no more than      3-year average
 2018.               510,000 tons      480,000 tons      of the year and
                     unless the        unless the        the two
                     milestones are    milestones are    previous years,
                     replaced with a   replaced with a   or any
                     different         different         alternative
                     program that      program that      provided in any
                     meets any BART    meets any BART    future plan
                     and reasonable    and reasonable    revisions under
                     progress          progress          Sec.
                     requirements      requirements      51.308(f).
                     established in    established in
                     Sec.  51.309.    Sec.  51.309.
------------------------------------------------------------------------

    (i) Adjustment for States and Tribes Which Choose Not to Participate 
in the Program, and for Tribes that opt into the program after the 2003 
deadline. If a State or Tribe chooses not to submit an implementation 
plan under the option provided in Sec. 51.309, or if EPA has not 
approved a State or Tribe's implementation plan by the date of the draft 
determination required by Sec. 51.309(h)(3)(ii), the amounts for that 
State or Tribe which are listed in Table 2 must be subtracted from the 
milestones that are included in the implementation plans for the 
remaining States and Tribes. For Tribes that opt into the program after 
2003, the amounts in Table 2 or 4 will be automatically added to the 
milestones that are included in the implementation plans for the 
participating States and Tribes, beginning with the first year after the 
tribal implementation plan implementing Sec. 51.309 is approved by the 
Administrator. The amounts listed in Table 2 are for purposes of 
adjusting the milestones only, and they do not represent amounts that 
must be allocated under any future trading program. Table 2 follows:

            Table 2--Amounts Subtracted From the Milestones for States and Tribes Which Do Not Exercise the Option Provided by Sec.  51.309
--------------------------------------------------------------------------------------------------------------------------------------------------------
                         State or tribe                              2003       2004       2005       2006       2007       2008       2009       2010
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. Arizona......................................................    117,372    117,372    117,372    117,372    117,372    117,941    118,511    119,080
2. California...................................................     37,343     37,343     37,343     37,784     37,343     36,363     35,382     34,402
3. Colorado.....................................................     98,897     98,897     98,897     98,897     98,897     98,443     97,991     97,537
4. Idaho........................................................     18,016     18,016     18,016     18,016     18,016     17,482     16,948     16,414
5. Nevada.......................................................     20,187     20,187     20,187     20,187     20,187     20,282     20,379     20,474
6. New Mexico...................................................     84,624     84,624     84,624     84,624     84,624     84,143     83,663     83,182
7. Oregon.......................................................     26,268     26,268     26,268     26,268     26,268     26,284     26,300     26,316
8. Utah.........................................................     42,782     42,782     42,782     42,782     42,782     42,795     42,806     42,819
9. Wyoming......................................................    155,858    155,858    155,858    155,858    155,858    155,851    155,843    155,836

[[Page 298]]

 
10. Navajo Nation...............................................     53,147     53,147     53,147     53,147     53,147     53,240     53,334     53,427
11. Shoshone-Bannock Tribe of the Fort Hall Reservation.........      4,994      4,994      4,994      4,994      4,994      4,994      4,994      4,994
12. Ute Indian Tribe of the Uintahand Ouray Reservation.........      1,129      1,129      1,129      1,129      1,129      1,131      1,133      1,135
13. Wind River Reservation......................................      1,384      1,384      1,384      1,384      1,384      1,384      1,384      1,384


--------------------------------------------------------------------------------------------------------------------------------------------------------
                         State or tribe                              2011       2012       2013       2014       2015       2016       2017       2018
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. Arizona......................................................    119,080    119,080    116,053    113,025    109,998    109,998    109,998     82,302
2. California...................................................     34,402     34,402     33,265     32,128     30,991     30,991     30,991     27,491
3. Colorado.....................................................     97,537     97,537     94,456     91,375     88,294     88,294     88,294     57,675
4. Idaho........................................................     16,414     16,414     15,805     15,197     14,588     14,588     14,588     13,227
5. Nevada.......................................................     20,474     20,474     20,466     20,457     20,449     20,449     20,449     20,232
6. New Mexico...................................................     83,182     83,182     81,682     80,182     78,682     78,682     78,682     70,000
7. Oregon.......................................................     26,316     26,316     24,796     23,277     21,757     21,757     21,757      8,281
8. Utah.........................................................     42,819     42,819     41,692     40,563     39,436     39,436     39,436     30,746
9. Wyoming......................................................    155,836    155,836    151,232    146,629    142,025    142,025    142,025     97,758
10. Navajo Nation...............................................     53,427     53,427     52,707     51,986     51,266     51,266     51,266     44,772
11. Shoshone-Bannock Tribe of the Fort Hall Reservation.........      4,994      4,994      4,994      4,994      4,994      4,994      4,994      4,994
12. Ute Indian Tribe of the Uintahand Ouray Reservation.........      1,135      1,135      1,135      1,135      1,135      1,135      1,135      1,135
13. Northern Arapaho and Shoshone Tribes of the Wind River            1,384      1,384      1,384      1,384      1,384      1,384      1,384      1,384
 Reservation....................................................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (ii) Adjustment for Future Operation of Copper Smelters.
    (A) The plan must provide for adjustments to the milestones in the 
event that Phelps Dodge Hidalgo and/or BHP San Manuel resume operations 
or that other smelters increase their operations.
    (B) The plan must provide for adjustments to the milestones 
according to Tables 3a and 3b except that if either the Hidalgo or San 
Manuel smelters resumes operation and is required to obtain a permit 
under 40 CFR 52.21 or 40 CFR 51.166, the adjustment to the milestone 
must be based upon the levels allowed by the permit. In no instance may 
the adjustment to the milestone be greater than 22,000 tons for the 
Phelps Dodge Hidalgo, greater than 16,000 tons for BHP San Manuel, or 
more than 30,000 tons for the combination of the Phelps Dodge Hidalgo 
and BHP San Manuel smelters for the years 2013 through 2018. Tables 3a 
and 3b follow:

 Table 3a--Adjustments to the Milestones for Future Operations of Copper
                                Smelters
------------------------------------------------------------------------
                                                          . . . then you
                                                          calculate the
                                                           milestone by
      Scenario        If this happens  and this happens    adding this
                           . . .             . . .        amount to the
                                                         value in column
                                                           3 of Table 1
------------------------------------------------------------------------
1..................  Phelps Dodge      Phelps Dodge      A. Beginning
                      Hidalgo resumes   Hidalgo resumes   with the year
                      operation, but    production        that
                      BHP San Manuel    consistent with   production
                      does not.         past operations   resumes, and
                                        and emissions.    for each year
                                                          up to the year
                                                          2012, the
                                                          milestone
                                                          increases by:
                                                         (1) 22,000 tons
                                                          PLUS
                                                         (2) Any amounts
                                                          identified in
                                                          Table 3b.
                                                         B. For the
                                                          years 2013
                                                          through 2018,
                                                          the milestone
                                                          increases by
                                                          this amount or
                                                          by 30,000
                                                          tons,
                                                          whichever is
                                                          less.

[[Page 299]]

 
2..................  Phelps Dodge      Phelps Dodge      A. Beginning
                      Hidalgo resumes   Hidalgo resumes   with the year
                      operation, but    operation in a    that
                      BHP San Manuel    substantially     production
                      does not.         different         resumes, and
                                        manner such       for each year
                                        that emissions    up to the year
                                        will be less      2012, the
                                        than for past     milestone
                                        operations (an    increases by:
                                        example would    (1) Expected
                                        be running only   emissions for
                                        one portion of    Phelps Dodge
                                        the plant to      Hidalgo (not
                                        produce sulfur    to exceed
                                        acid only).       22,000 tons),
                                                          PLUS
                                                         (2) Any amounts
                                                          identified in
                                                          Table 3b.
                                                         B. For the
                                                          years 2013
                                                          through 2018,
                                                          the milestone
                                                          increases by
                                                          this amount or
                                                          by 30,000
                                                          tons,
                                                          whichever is
                                                          less.
3..................  BHP San Manuel    BHP San Manuel    A. 16,000 tons
                      Manuel resumes    resumes           PLUS
                      operation, but    production       B. Any amounts
                      Phelps Dodge      consistent with   identified in
                      Hidalgo does      past operations   Table 3b.
                      not.              and emissions.
4..................  BHP San Manuel    BHP San Manuel    A. Expected
                      resumes           resumes           emissions for
                      operation, but    operations in a   BHP (not to
                      Phelps Dodge      substantially     exceed 16,000
                      Hidalgo does      different         tons) PLUS
                      not.              manner such      B. Any amounts
                                        that emissions    identified in
                                        will be less      Table 3b.
                                        than for past
                                        operations (an
                                        example would
                                        be running only
                                        one portion of
                                        the plant to
                                        produce sulfur
                                        acid only).
5..................  Both Phelps       Both smelters     A. Beginning
                      Dodge Hidalgo     resume            with the year
                      and BHP San       production        that
                      Manuel resume     consistent with   production
                      operations.       past operations   resumes, and
                                        and emissions.    for each year
                                                          up to the year
                                                          2012, the
                                                          milestone
                                                          increase by
                                                          38,000 tons.
                                                         B. For the
                                                          years 2013
                                                          through 2018,
                                                          the milestone
                                                          increases by
                                                          30,000 tons.
6..................  Both Phelps       Phelps Dodge      A. For the year
                      Dodge Hidalgo     Hidalgo resumes   that
                      and BHP San       production        production
                      Manuel resume     consistent with   resumes, and
                      operations.       past operations   for each year
                                        and emissions,    up to the year
                                        but BHP San       2012, the
                                        Manuel resumes    milestone
                                        operations in a   increases by:
                                        substantially    (1) 22,000 PLUS
                                        different        (2) Expected
                                        manner such       emissions for
                                        that emissions    San Manuel
                                        will be less      (not to exceed
                                        than for past     16,000 tons).
                                        operations (an   B. For the
                                        example would     years 2013
                                        be running only   though 2018,
                                        one portion of    the milestone
                                        the plant to      increases by
                                        produce sulfur    this same
                                        acid only).       amount, or by
                                                          30,000 tons,
                                                          whichever is
                                                          less.
7..................  Both Phelps       BHP San Manuel    A. For the year
                      Dodge Hidalgo     resume            that
                      and BHP San       production        production
                      Manuel resumes    consistent with   resumes, and
                      operations.       the past          for each year
                                        operations and    up to the year
                                        emissions, but    2012,
                                        Phelps Dodge      milestone
                                        Hidalgo resumes   increases by:
                                        operations in a  (1) 16,000 PLUS
                                        substantially    (2) Expected
                                        different         Hidalgo
                                        manner such       emissions (not
                                        that emissions    to exceed
                                        will be less      22,000 tons).
                                        than for past    B. For the
                                        operations (an    years 2013
                                        example would     though 2018,
                                        be running only   the milestone
                                        one portion of    increases by
                                        the plant to      this same
                                        produce sulfur    amount, or by
                                        acid only).       30,000 tons,
                                                          whichever is
                                                          less.
8..................  Both Phelps       ................  A. Any amounts
                      Dodge Hidalgo                       identified in
                      and BHP San                         Table 3b.
                      Manuel do not
                      resume
                      operations.
------------------------------------------------------------------------


[[Page 300]]


  Table 3b--Adjustments for Certain Copper Smelters Which Operate Above
                             Baseline Levels
                                [In tons]
------------------------------------------------------------------------
                                                             . . . the
                                           complies with     milestone
                                             existing      increases by
                                            permits but   the difference
                                            has actual    between actual
  Where it applies in table 3a, if the        annual       emissions and
         following smelter . . .          emissions that   the baseline
                                            exceed the     level, or the
                                             following       following
                                          baseline level      amount,
                                               . . .       whichever is
                                                               less
------------------------------------------------------------------------
Asarco Hayden...........................          23,000           3,000
BHP San Manuel..........................          16,000           1,500
Kennecott Salt Lake.....................           1,000             100
Phelps Dodge Chino......................          16,000           3,000
Phelps Dodge Hidalgo....................          22,000           4,000
Phelps Dodge Miami......................           8,000           2,000
------------------------------------------------------------------------

    (iii) Adjustments for changes in emission monitoring or calculation 
methods. The plan must provide for adjustments to the milestones to 
reflect changes in sulfur dioxide emission monitoring or measurement 
methods for a source that is included in the program, including changes 
identified under paragraph (h)(2)(iii)(D) of this section. Any such 
adjustment based upon changes to emissions monitoring or measurement 
methods must be made in the form of an implementation plan revision that 
complies with the procedural requirements of Sec. 51.102 and Sec. 
51.103. The implementation plan revision must be submitted to the 
Administrator no later than the first due date for a periodic report 
under paragraph (d)(10) of this section following the change in emission 
monitoring or measurement method.
    (iv) Adjustments for changes in flow rate measurement methods for 
affected sources under 40 CFR 72.1. For the years between 2003 and 2017, 
the implementation plan must provide for adjustments to the milestones 
for sources using the methods contained in 40 CFR part 60, appendix A, 
Methods 2F, 2G, and 2H. For any year for which such an adjustment has 
not yet been made to the milestone, the implementation plan must provide 
for an adjustment to the emissions reporting to ensure consistency. The 
implementation plan must provide for adjustments to the milestones by no 
later than the date of the periodic plan revision required under Sec. 
51.309(d)(10).
    (v) Adjustments due to enforcement actions arising from settlements. 
The implementation plan must provide for adjustments to the milestones, 
as specified in paragraph (h)(1)(vii) and (viii) of this section, if:
    (A) An agreement to settle an action, arising from allegations of a 
failure of an owner or operator of an emissions unit at a source in the 
program to comply with applicable regulations which were in effect 
during the base year, is reached between the parties to the action;
    (B) The alleged failure to comply with applicable regulations 
affects the assumptions that were used in calculating the source's base 
year and forecasted sulfur dioxide emissions; and
    (C) The settlement includes or recommends an adjustment to the 
milestones.
    (vi) Adjustments due to enforcement actions arising from 
administrative or judicial orders. The implementation plan must also 
provide for adjustments to the milestones as directed by any final 
administrative or judicial order, as specified in paragraph (h)(1)(vii) 
and (viii) of this section. Where the final administrative or judicial 
order does not include a reforecast of the source's baseline, the State 
or Tribe shall evaluate whether a reforecast of the source's baseline 
emissions is appropriate.

[[Page 301]]

    (vii) Adjustments for enforcement actions. The plan must provide 
that, based on paragraph (h)(1)(v) and (vi) of this section, the 
milestone must be decreased by an appropriate amount based on a 
reforecast of the source's decreased sulfur dioxide emissions. The 
adjustments do not become effective until after the source has reduced 
its sulfur dioxide emissions as required in the settlement agreement, or 
administrative or judicial order. All adjustments based upon enforcement 
actions must be made in the form of an implementation plan revision that 
complies with the procedural requirements of Sec. Sec. 51.102 and 
51.103.
    (viii) Documentation of adjustments for enforcement actions. In the 
periodic plan revision required under 51.309(d)(10), the State or Tribe 
shall include the following documentation of any adjustment due to an 
enforcement action:
    (A) Identification of each source under the State or Tribe's 
jurisdiction which has reduced sulfur dioxide emissions pursuant to a 
settlement agreement, or an administrative or judicial order;
    (B) For each source identified, a statement indicating whether the 
milestones were adjusted in response to the enforcement action;
    (C) Discussion of the rationale for the State or Tribe's decision to 
adjust or not to adjust the milestones; and
    (D) If extra SO2 emissions reductions (over and above 
those reductions needed for compliance with the applicable regulations) 
were part of an agreement to settle an action, a statement indicating 
whether such reductions resulted in any adjustment to the milestones or 
allowance allocations, and a discussion of the rationale for the State 
or Tribe's decision on any such adjustment.
    (ix) Adjustment based upon program audits. The plan must provide for 
appropriate adjustments to the milestones based upon the results of 
program audits. Any such adjustment based upon audits must be made in 
the form of an implementation plan revision that complies with the 
procedural requirements of Sec. Sec. 51.102 and 51.103. The 
implementation plan revision must be submitted to the Administrator no 
later than the first due date after the audit for a periodic report 
under paragraph (d)(10) of this section.
    (x) Adjustment for individual sources opting into the program. The 
plan may provide for adjustments to the milestones for any source 
choosing to participate in the program even though the source does not 
meet the 100 tons per year criterion for inclusion. Any such adjustments 
must be made in the form of an implementation plan revision that 
complies with the procedural requirements of Sec. Sec. 51.102 and 
51.103.
    (2) Requirements for monitoring, recordkeeping and reporting of 
actual annual emissions of sulfur dioxide--(i) Sources included in the 
program. The implementation plan must provide for annual emission 
monitoring and reporting, beginning with calendar year 2003, for all 
sources with actual emissions of sulfur dioxide of 100 tons per year or 
more as of 2003, and all sources with actual emissions of 100 tons or 
more per year in any subsequent year. States and Tribes may include 
other sources in the program, if the implementation plan provides for 
the same procedures and monitoring as for other sources in a way that is 
federally enforceable.
    (ii) Documentation of emissions calculation methods. The 
implementation plan must provide documentation of the specific 
methodology used to calculate emissions for each emitting unit included 
in the program during the base year. The implementation plan must also 
provide for documentation of any change to the specific methodology used 
to calculate emissions at any emitting unit for any year after the base 
year.
    (iii) Recordkeeping. The implementation plan must provide for the 
retention of records for at least 10 years from the establishment of the 
record. If a record will be the basis for an adjustment to the milestone 
as provided for in paragraph (h)(1) of this section, that record must be 
retained for at least 10 years from the establishment of the record, or 
5 years after the date of the implementation plan revision which 
reflects the adjustment, whichever is longer.
    (iv) Completion and submission of emissions reports. The 
implementation plan must provide for the annual collection

[[Page 302]]

of emissions data for sources included within the program, quality 
assurance of the data, public review of the data, and submission of 
emissions reports to the Administrator and to each State and Tribe which 
has submitted an implementation plan under this section. The 
implementation plan must provide for submission of the emission reports 
by no later than September 30 of each year, beginning with reports due 
September 30, 2004 for emissions from calendar year 2003. For sources 
for which changes in emission quantification methods require adjustments 
under paragraph (h)(1)(iii) of this section, the emissions reports must 
reflect the method in place before the change, for each year until the 
milestone has been adjusted. If each of the States which have submitted 
an implementation plan under this section have identified a regional 
planning organization to coordinate the annual comparison of regional 
SO2 emissions against the appropriate milestone, the 
implementation plan must provide for reporting of this information to 
the regional planning body.
    (v) Exceptions reports. The emissions report submitted by each State 
and Tribe under paragraph (h)(2)(ii) of this section must provide for 
exceptions reports containing the following:
    (A) Identification of any new or additional sulfur dioxide sources 
greater than 100 tons per year that were not contained in the previous 
year emissions report;
    (B) Identification of sources shut down or removed from the previous 
year emissions report;
    (C) Explanation for emissions variations at any covered source that 
exceed plus or minus 20 percent from the previous year's emissions 
report;
    (D) Identification and explanation of changed emissions monitoring 
and reporting methods at any source. The use of any changed emission 
monitoring or reporting methods requires an adjustment to the milestones 
according to paragraph (h)(1)(iii) of this section.
    (vi) Reporting of emissions for the Mohave Generating Station for 
the years 2003 through 2006. For the years 2003, 2004, 2005, and for any 
part of the year 2006 before installation and operation of sulfur 
dioxide controls at the Mohave Generating Station, emissions from the 
Mohave Generating Station will be calculated using a sulfur dioxide 
emission factor of 0.15 pounds per million BTU.
    (vii) Special provision for the year 2013. The implementation plan 
must provide that in the emissions report for calendar year 2012, which 
is due by September 30, 2013 under paragraph (h)(2)(iv) of this section, 
each State has the option of including calendar year 2018 emission 
projections for each source, in addition to the actual emissions for 
each source for calendar year 2012.
    (3) Annual comparison of emissions to the milestone--(i) The 
implementation plan must provide for a comparison each year of annual 
SO2 emissions for the region against the appropriate 
milestone. In making this comparison, the State or Tribe must make the 
comparison, using its annual emissions report and emissions reports from 
other States and Tribes reported under paragraph (h)(2)(iv) of this 
section.
    (ii) The implementation plan must provide for the State or Tribe to 
make available to the public a draft report comparing annual emissions 
to the milestone by December 31 of each year. The first draft report, 
comparing annual emissions in 2003 to the year 2003 milestone will be 
due December 31, 2004.
    (iii) The implementation plan must provide for the State or Tribe to 
submit to the Administrator a final determination of annual emissions by 
March 31 of the following year. The final determination must state 
whether or not the annual emissions for the year exceed the appropriate 
milestone.
    (iv) A State or Tribe may delegate its responsibilities to prepare 
draft reports and reports supporting the final determinations under 
paragraphs (h)(3)(i) through (iii) of this section to a regional 
planning organization designated by each State or Tribe submitting an 
approvable plan under this section.
    (v) Special considerations for year 2012 report. If each State or 
Tribe submitting an approvable plan under this section has included 
calendar year 2018 emission projections under paragraph (h)(2)(vii) of 
this section, then the report for the year 2012 milestone which

[[Page 303]]

is due by December 31, 2013 under paragraph (h)(3)(ii) of this section 
may also include a comparison of the regional year 2018 emissions 
projection with the milestone for calendar year 2018. If the report 
indicates that the year 2018 milestone will be exceeded, then the State 
or Tribe may choose to implement the market trading program beginning in 
the year 2018, if each State or Tribe submitting an approvable plan 
under this section agrees.
    (vi) Independent review. The implementation plan must provide for 
reviews of the annual emissions reporting program by an independent 
third party. This independent review is not required if a determination 
has been made under paragraph (h)(3)(iii) of this section to implement 
the market trading program. The independent review shall be completed by 
the end of 2006, and every 5 years thereafter, and shall include an 
analysis of:
    (A) The uncertainty of the reported emissions data;
    (B) Whether the uncertainty of the reported emissions data is likely 
to have an adverse impact on the annual determination of emissions 
relative to the milestone; and,
    (C) Whether there are any necessary improvements for the annual 
administrative process for collecting the emissions data, reporting the 
data, and obtaining public review of the data.
    (4) Market trading program. The implementation plan must provide for 
implementation of a market trading program if the determination required 
by paragraph (h)(3)(iii) of this section indicates that a milestone has 
been exceeded. The implementation plan must provide for the option of 
implementation of a market trading program if a report under paragraph 
(h)(3)(v) of this section indicates that projected emissions for the 
year 2018 will exceed the year 2018 milestone. The implementation plan 
must provide for a market trading program whose provisions are 
substantively the same for each State or Tribe submitting an approvable 
plan under this section. The implementation plan must include the 
following market trading program provisions:
    (i) Allowances. For each source in the program, the implementation 
plan must either identify the specific allocation of allowances, on a 
tons per year basis, for each calendar year from 2009 to 2018 or the 
formula or methodology that will be used to calculate the allowances if 
the program is triggered. The implementation plan must provide that 
eligible renewable energy resources that begin operation after October 
1, 2000 will receive 2.5 tons of SO2 allowances per megawatt 
of installed nameplate capacity per year. Allowance allocations for 
renewable energy resources that begin operation prior to the program 
trigger will be retroactive to the time of initial operation. The 
implementation plan may provide for an upper limit on the number of 
allowances provided for eligible renewable energy resources. The total 
of the tons per year allowances across all participating States and 
Tribes, including the renewable energy allowances, may not exceed the 
amounts in Table 4 of this paragraph, less a 20,000 ton amount that must 
be set aside for use by Tribes. The implementation plan may include 
procedures for redistributing the allowances in future years, if as the 
amounts in Table 4 of this paragraph, less a 20,000 ton amount, are not 
exceeded. The implementation plan must provide that any adjustment for a 
calendar year applied to the milestones under paragraphs (h)(1)(i) 
through (vii) of this section must also be applied to the amounts in 
Table 4. Table 4 follows:

[[Page 304]]



               Table 4--Total Amount of Allowances by Year
------------------------------------------------------------------------
                                            If the two      If the two
                                             smelters       smelters do
                                              resume        not resume
                                            operations,     operations,
                                             the total       the total
                                             number of       number of
             For this year:                 allowances      allowances
                                             issued by       issued by
                                            States and      States and
                                          Tribes may not  Tribes may not
                                            exceed this     exceed this
                                              amount:         amount:
------------------------------------------------------------------------
2009....................................         715,000         677,000
2010....................................         715,000         677,000
2011....................................         715,000         677,000
2012....................................         715,000         677,000
2013....................................         655,000         625,000
2014....................................         655,000         625,000
2015....................................         655,000         625,000
2016....................................         655,000         625,000
2017....................................         655,000         625,000
2018....................................         510,000         480,000
------------------------------------------------------------------------

    (ii) Compliance with allowances. The implementation plan must 
provide that, beginning with the compliance period 6 years following the 
calendar year for which emissions exceeded the milestone and for each 
compliance period thereafter, the owner or operator of each source in 
the program must hold allowances for each ton of sulfur dioxide emitted 
by the source.
    (iii) Emissions quantification protocols. The implementation plan 
must include specific emissions quantification protocols for each source 
category included within the program, including the identification of 
sources subject to part 75 of this chapter. For sources subject to part 
75 of this chapter, the implementation plan may rely on the emissions 
quantification protocol in part 75. For source categories with sources 
in more than one State or tribal area submitting an implementation plan 
under this section, each State or Tribe should use the same protocol to 
quantify emissions for sources in the source category. The protocols 
must provide for reliability (repeated application obtains results 
equivalent to EPA-approved test methods), and replicability (different 
users obtain the same or equivalent results that are independently 
verifiable). The protocols must include procedures for addressing 
missing data, which provide for conservative calculations of emissions 
and provide sufficient incentives for sources to comply with the 
monitoring provisions. If the protocols are not the same for sources 
within a given source category, and where the protocols are not based 
upon part 75 or equivalent methods, the State or Tribes must provide a 
demonstration that each such protocol meets all of the criteria of this 
paragraph.
    (iv) Monitoring and Recordkeeping. The implementation plan must 
include monitoring provisions which are consistent with the emissions 
quantification protocol. Monitoring required by these provisions must be 
timely and of sufficient frequency to ensure the enforceability of the 
program. The implementation plan must also include requirements that the 
owner or operator of each source in the program keep records consistent 
with the emissions quantification protocols, and keep all records used 
to determine compliance for at least 5 years. For source owners or 
operators which use banked allowances, all records relating to the 
banked allowance must be kept for at least 5 years after the banked 
allowances are used.
    (v) Tracking system. The implementation plan must provide for 
submitting data to a centralized system for the tracking of allowances 
and emissions. The implementation plan must provide that all necessary 
information regarding emissions, allowances, and transactions is 
publicly available in a secure, centralized data base. In the system, 
each allowance must be uniquely identified. The system must allow for

[[Page 305]]

frequent updates and include enforceable procedures for recording data.
    (vi) Authorized account representative. The implementation plan must 
include provisions requiring the owner or operator of each source in the 
program to identify an authorized account representative. The 
implementation plan must provide that all matters pertaining to the 
account, including, but not limited to, the deduction and transfer of 
allowances in the account, and certifications of the completeness and 
accuracy of emissions and allowances transactions required in the annual 
report under paragraph (h)(4)(vii) of this section shall be undertaken 
only by the authorized account representative.
    (vii) Annual report. The implementation plan must include provisions 
requiring the authorized account representative for each source in the 
program to demonstrate and report within a specified time period 
following the end of each calendar year that the source holds allowances 
for each ton per year of SO2 emitted in that year. The 
implementation plan must require the authorized account representative 
to submit the report within 60 days after the end of each calendar year, 
unless an alternative deadline is specified consistent with emission 
monitoring and reporting procedures.
    (viii) Allowance transfers. The implementation plan must include 
provisions detailing the process for transferring allowances between 
parties.
    (ix) Emissions banking. The implementation plan may provide for the 
banking of unused allowances. Any such provisions must state whether 
unused allowances may be kept for use in future years and describe any 
restrictions on the use of any such allowances. Allowances kept for use 
in future years may be used in calendar year 2018 only if the 
implementation plan ensures that such allowances would not interfere 
with the achievement of the year 2018 amount in Table 4 in paragraph 
(c)(4)(i) of this section.
    (x) Penalties. The implementation plan must:
    (A) Provide that if emissions from a source in the program exceed 
the allowances held by the source, the source's allowances will be 
reduced by an amount equal to two times the source's tons of excess 
emissions,
    (B) Provide for appropriate financial penalties for excess 
emissions, either $5000 per ton (year 2000 dollars) or an alternative 
amount that is the same for each participating State and Tribe and that 
substantially exceeds the expected cost of allowances,
    (C) Ensure that failure to comply with any program requirements 
(including monitoring, recordkeeping, and reporting requirements) are 
violations which are subject to civil and criminal remedies provided 
under applicable State or tribal law and the Clean Air Act, that each 
day of the control period is a separate violation, and that each ton of 
excess emissions is a separate violation. Any allowance reduction or 
penalty assessment required under paragraphs (h)(4)(x)(A) and (B) of 
this section shall not affect the liability of the source for remedies 
under this paragraph.
    (xi) Provisions for periodic evaluation of the trading program. The 
implementation plan must provide for an evaluation of the trading 
program no later than 3 years following the first full year of the 
trading program, and at least every 5 years thereafter. Any changes 
warranted by the evaluation should be incorporated into the next 
periodic implementation plan revision required under paragraph (d)(10) 
of this section. The evaluation must be conducted by an independent 
third party and must include an analysis of:
    (A) Whether the total actual emissions could exceed the values in 
Sec. 51.309(h)(4)(i), even though sources comply with their allowances;
    (B) Whether the program achieved the overall emission milestone it 
was intended to reach;
    (C) The effectiveness of the compliance, enforcement and penalty 
provisions;
    (D) A discussion of whether States and Tribes have enough resources 
to implement the trading program;
    (E) Whether the trading program resulted in any unexpected 
beneficial effects, or any unintended detrimental effects;
    (F) Whether the actions taken to reduce sulfur dioxide have led to 
any unintended increases in other pollutants;

[[Page 306]]

    (G) Whether there are any changes needed in emissions monitoring and 
reporting protocols, or in the administrative procedures for program 
administration and tracking; and
    (H) The effectiveness of the provisions for interstate trading, and 
whether there are any procedural changes needed to make the interstate 
nature of the program more effective.
    (5) Other provisions--(i) Permitting of affected sources. The 
implementation plan must provide that for sources subject to part 70 or 
part 71 of this chapter, the implementation plan requirements for 
emissions reporting and for the trading program under paragraph (h) of 
this section must be incorporated into the part 70 or part 71 permit. 
For sources not subject to part 70 or part 71 of this chapter, the 
requirements must be incorporated into a permit that is enforceable as a 
practical matter by the Administrator, and by citizens to the extent 
permitted under the Clean Air Act.
    (ii) Integration with other programs. The implementation plan must 
provide that in addition to the requirements of paragraph (h) of this 
section, any applicable restrictions of Federal, State, and tribal law 
remain in place. No provision of paragraph (h) of this section should be 
interpreted as exempting any source from compliance with any other 
provision of Federal, State, tribal or local law, including an approved 
implementation plan, a Federally enforceable permit, or any other 
Federal regulations.

[64 FR 35769, July 1, 1999, as amended at 68 FR 33784, June 5, 2003; 68 
FR 39846, July 3, 2003; 68 FR 61369, Oct. 28, 2003; 68 FR 71014, Dec. 
22, 2003]



                            Subpart Q_Reports

    Authority: Secs. 110, 301(a), 313, 319, Clean Air Act (42 U.S.C. 
7410, 7601(a), 7613, 7619).

    Source: 44 FR 27569, May 10, 1979, unless otherwise noted.

                       Air Quality Data Reporting



Sec. 51.320  Annual air quality data report.

    The requirements for reporting air quality data collected for 
purposes of the plan are located in subpart C of part 58 of this 
chapter.

               Source Emissions and State Action Reporting



Sec. 51.321  Annual source emissions and State action report.

    The State agency shall report to the Administrator (through the 
appropriate Regional Office) information as specified in Sec. Sec. 
51.322 through 51.326.

[67 FR 39615, June 10, 2002]



Sec. 51.322  Sources subject to emissions reporting.

    The requirements for reporting emissions data under the plan are in 
subpart A of this part 51.

[67 FR 39615, June 10, 2002]



Sec. 51.323  Reportable emissions data and information.

    The requirements for reportable emissions data and information under 
the plan are in subpart A of this part 51.

[67 FR 39615, June 10, 2002]



Sec. 51.324  Progress in plan enforcement.

    (a) For each point source, the State shall report any achievement 
made during the reporting period of any increment of progress of 
compliance schedules required by:
    (1) The applicable plan, or
    (2) Any enforcement order or other State action required to be 
submitted pursuant to Sec. 51.327.
    (b) For each point source, the State shall report any enforcement 
action taken during the reporting period and not submitted under Sec. 
51.327 which results in civil or criminal penalties.



Sec. 51.326  Reportable revisions.

    The State shall identify and describe all substantive plan revisions 
during the reporting period of the applicable plan other than revisions 
to rules and regulations or compliance schedules submitted in accordance 
with Sec. 51.6(d). Substantive revisions shall include but are not 
limited to changes in stack-test procedures for determining compliance 
with applicable regulations, modifications in the projected total

[[Page 307]]

manpower needs to carry out the approved plan, and all changes in 
responsibilities given to local agencies to carry out various portions 
of the plan.



Sec. 51.327  Enforcement orders and other State actions.

    (a) Any State enforcement order, including any State court order, 
must be submitted to the Administrator within 60 days of its issuance or 
adoption by the State.
    (b) A State enforcement order or other State action must be 
submitted as a revision to the applicable implementation plan pursuant 
to Sec. 51.104 and approved by the Administrator in order to be 
considered a revision to such plan.

[36 FR 22398, Nov. 25, 1971, as amended at 51 FR 40675, Nov. 7, 1986]



Sec. 51.328  [Reserved]



                          Subpart R_Extensions



Sec. 51.341  Request for 18-month extension.

    (a) Upon request of the State made in accordance with this section, 
the Administrator may, whenever he determines necessary, extend, for a 
period not to exceed 18 months, the deadline for submitting that portion 
of a plan that implements a secondary standard.
    (b) Any such request must show that attainment of the secondary 
standards will require emission reductions exceeding those which can be 
achieved through the application of reasonably available control 
technology.
    (c) Any such request for extension of the deadline with respect to 
any State's portion of an interstate region must be submitted jointly 
with requests for such extensions from all other States within the 
region or must show that all such States have been notified of such 
request.
    (d) Any such request must be submitted sufficiently early to permit 
development of a plan prior to the deadline in the event that such 
request is denied.

[51 FR 40675, Nov. 7, 1986]



          Subpart S_Inspection/Maintenance Program Requirements

    Source: 57 FR 52987, Nov. 5, 1992, unless otherwise noted.



Sec. 51.350  Applicability.

    Inspection/maintenance (I/M) programs are required in both ozone and 
carbon monoxide (CO) nonattainment areas, depending upon population and 
nonattainment classification or design value.
    (a) Nonattainment area classification and population criteria. (1) 
States or areas within an ozone transport region shall implement 
enhanced I/M programs in any metropolitan statistical area (MSA), or 
portion of an MSA, within the State or area with a 1990 population of 
100,000 or more as defined by the Office of Management and Budget (OMB) 
regardless of the area's attainment classification. In the case of a 
multi-state MSA, enhanced I/M shall be implemented in all ozone 
transport region portions if the sum of these portions has a population 
of 100,000 or more, irrespective of the population of the portion in the 
individual ozone transport region State or area.
    (2) Apart from those areas described in paragraph (a)(1) of this 
section, any area classified as serious or worse ozone nonattainment, or 
as moderate or serious CO nonattainment with a design value greater than 
12.7 ppm, and having a 1980 Bureau of Census-defined (Census-defined) 
urbanized area population of 200,000 or more, shall implement enhanced 
I/M in the 1990 Census-defined urbanized area.
    (3) Any area classified, as of November 5, 1992, as marginal ozone 
nonattainment or moderate CO nonattainment with a design value of 12.7 
ppm or less shall continue operating I/M programs that were part of an 
approved State Implementation Plan (SIP) as of November 15, 1990, and 
shall update those programs as necessary to meet the basic I/M program 
requirements of this subpart. Any such area required by the Clean Air 
Act, as in effect prior to November 15, 1990, as interpreted in EPA 
guidance, to have an I/M program shall also implement a basic I/M 
program. Serious, severe and extreme

[[Page 308]]

ozone areas and CO areas over 12.7 ppm shall also continue operating 
existing I/M programs and shall upgrade such programs, as appropriate, 
pursuant to this subpart.
    (4) Any area classified as moderate ozone nonattainment, and not 
required to implement enhanced I/M under paragraph (a)(1) of this 
section, shall implement basic I/M in any 1990 Census-defined urbanized 
area with a population of 200,000 or more.
    (5) [Reserved]
    (6) If the boundaries of a moderate ozone nonattainment area are 
changed pursuant to section 107(d)(4)(A)(i)-(ii) of the Clean Air Act, 
such that the area includes additional urbanized areas with a population 
of 200,000 or more, then a basic I/M program shall be implemented in 
these additional urbanized areas.
    (7) If the boundaries of a serious or worse ozone nonattainment area 
or of a moderate or serious CO nonattainment area with a design value 
greater than 12.7 ppm are changed any time after enactment pursuant to 
section 107(d)(4)(A) such that the area includes additional urbanized 
areas, then an enhanced I/M program shall be implemented in the newly 
included 1990 Census-defined urbanized areas, if the 1980 Census-defined 
urban area population is 200,000 or more.
    (8) If a marginal ozone nonattainment area, not required to 
implement enhanced I/M under paragraph (a)(1) of this section, is 
reclassified to moderate, a basic I/M program shall be implemented in 
the 1990 Census-defined urbanized area(s) with a population of 200,000 
or more. If the area is reclassified to serious or worse, an enhanced I/
M program shall be implemented in the 1990 Census-defined urbanized 
area, if the 1980 Census-defined urban area population is 200,000 or 
more.
    (9) If a moderate ozone or CO nonattainment area is reclassified to 
serious or worse, an enhanced I/M program shall be implemented in the 
1990 Census-defined urbanized area, if the 1980 Census-defined 
population is 200,000 or more.
    (b) Extent of area coverage. (1) In an ozone transport region, the 
program shall cover all counties within subject MSAs or subject portions 
of MSAs, as defined by OMB in 1990, except largely rural counties having 
a population density of less than 200 persons per square mile based on 
the 1990 Census and counties with less than 1% of the population in the 
MSA may be excluded provided that at least 50% of the MSA population is 
included in the program. This provision does not preclude the voluntary 
inclusion of portions of an excluded county. Non-urbanized islands not 
connected to the mainland by roads, bridges, or tunnels may be excluded 
without regard to population.
    (2) Outside of ozone transport regions, programs shall nominally 
cover at least the entire urbanized area, based on the 1990 census. 
Exclusion of some urban population is allowed as long as an equal number 
of non-urban residents of the MSA containing the subject urbanized area 
are included to compensate for the exclusion.
    (3) Emission reduction benefits from expanding coverage beyond the 
minimum required urban area boundaries can be applied toward the 
reasonable further progress requirements or can be used for offsets, 
provided the covered vehicles are operated in the nonattainment area, 
but not toward the enhanced I/M performance standard requirement.
    (4) In a multi-state urbanized area with a population of 200,000 or 
more that is required under paragraph (a) of this section to implement 
I/M, any State with a portion of the area having a 1990 Census-defined 
population of 50,000 or more shall implement an I/M program. The other 
coverage requirements in paragraph (b) of this section shall apply in 
multi-state areas as well.
    (5) Notwithstanding the limitation in paragraph (b)(3) of this 
section, in an ozone transport region, States which opt for a program 
which meets the performance standard described in Sec. 51.351(h) and 
claim in their SIP less emission reduction credit than the basic 
performance standard for one or more pollutants, may apply a geographic 
bubble covering areas in the State not otherwise subject to an I/M 
requirement to achieve emission reductions from other measures equal to 
or greater than what would have been achieved if the low enhanced 
performance standard were met in the subject

[[Page 309]]

I/M areas. Emissions reductions from non-I/M measures shall not be 
counted towards the OTR low enhanced performance standard.
    (c) Requirements after attainment. All I/M programs shall provide 
that the program will remain effective, even if the area is redesignated 
to attainment status or the standard is otherwise rendered no longer 
applicable, until the State submits and EPA approves a SIP revision 
which convincingly demonstrates that the area can maintain the relevant 
standard(s) without benefit of the emission reductions attributable to 
the I/M program. The State shall commit to fully implement and enforce 
the program until such a demonstration can be made and approved by EPA. 
At a minimum, for the purposes of SIP approval, legislation authorizing 
the program shall not sunset prior to the attainment deadline for the 
applicable National Ambient Air Quality Standards (NAAQS).
    (d) SIP requirements. The SIP shall describe the applicable areas in 
detail and, consistent with Sec. 51.372 of this subpart, shall include 
the legal authority or rules necessary to establish program boundaries.

[57 FR 52987, Nov. 5, 1992, as amended at 60 FR 48034, Sept. 18, 1995; 
61 FR 39036, July 25, 1996; 65 FR 45532, July 24, 2000]



Sec. 51.351  Enhanced I/M performance standard.

    (a) [Reserved]
    (b) On-road testing. The performance standard shall include on-road 
testing (including out-of-cycle repairs in the case of confirmed 
failures) of at least 0.5% of the subject vehicle population, or 20,000 
vehicles whichever is less, as a supplement to the periodic inspection 
required in paragraphs (f), (g), and (h) of this section. Specific 
requirements are listed in Sec. 51.371 of this subpart.
    (c) On-board diagnostics (OBD). For those areas required to 
implement an enhanced I/M program prior to the effective date of 
designation and classifications under the 8-hour ozone standard, the 
performance standard shall include inspection of all model year 1996 and 
later light-duty vehicles and light-duty trucks equipped with certified 
on-board diagnostic systems, and repair of malfunctions or system 
deterioration identified by or affecting OBD systems as specified in 
Sec. 51.357, and assuming a start date of 2002 for such testing. For 
areas required to implement enhanced I/M as a result of designation and 
classification under the 8-hour ozone standard, the performance standard 
defined in paragraph (i) of this section shall include inspection of all 
model year 2001 and later light-duty vehicles and light-duty trucks 
equipped with certified on-board diagnostic systems, and repair of 
malfunctions or system deterioration identified by or affecting OBD 
systems as specified in Sec. 51.357, and assuming a start date of 4 
years after the effective date of designation and classification under 
the 8-hour ozone standard.
    (d) Modeling requirements. Equivalency of the emission levels which 
will be achieved by the I/M program design in the SIP to those of the 
model program described in this section shall be demonstrated using the 
most current version of EPA's mobile source emission model, or an 
alternative approved by the Administrator, using EPA guidance to aid in 
the estimation of input parameters. States may adopt alternative 
approaches that meet this performance standard. States may do so through 
program design changes that affect normal I/M input parameters to the 
mobile source emission factor model, or through program changes (such as 
the accelerated retirement of high emitting vehicles) that reduce in-use 
mobile source emissions. If the Administrator finds, under section 
182(b)(1)(A)(i) of the Act pertaining to reasonable further progress 
demonstrations or section 182(f)(1) of the Act pertaining to provisions 
for major stationary sources, that NOX emission reductions 
are not beneficial in a given ozone nonattainment area, then 
NOX emission reductions are not required of the enhanced I/M 
program, but the program shall be designed to offset NOX 
increases resulting from the repair of HC and CO failures.
    (e) [Reserved]
    (f) High Enhanced Performance Standard. Enhanced I/M programs shall 
be designed and implemented to meet or exceed a minimum performance 
standard, which is expressed as emission levels in area-wide average 
grams per mile

[[Page 310]]

(gpm), achieved from highway mobile sources as a result of the program. 
The emission levels achieved by the State's program design shall be 
calculated using the most current version, at the time of submittal, of 
the EPA mobile source emission factor model or an alternative model 
approved by the Administrator, and shall meet the minimum performance 
standard both in operation and for SIP approval. Areas shall meet the 
performance standard for the pollutants which cause them to be subject 
to enhanced I/M requirements. In the case of ozone nonattainment areas 
subject to enhanced I/M and subject areas in the Ozone Transport Region, 
the performance standard must be met for both oxides of nitrogen (NOx) 
and volatile organic compounds (VOCs), except as provided in paragraph 
(d) of this section. Except as provided in paragraphs (g) and (h) of 
this section, the model program elements for the enhanced I/M 
performance standard shall be as follows:
    (1) Network type. Centralized testing.
    (2) Start date. For areas with existing I/M programs, 1983. For 
areas newly subject, 1995.
    (3) Test frequency. Annual testing.
    (4) Model year coverage. Testing of 1968 and later vehicles.
    (5) Vehicle type coverage. Light duty vehicles, and light duty 
trucks, rated up to 8,500 pounds Gross Vehicle Weight Rating (GVWR).
    (6) Exhaust emission test type. Transient mass-emission testing on 
1986 and later model year vehicles using the IM240 driving cycle, two-
speed testing (as described in appendix B of this subpart S) of 1981-
1985 vehicles, and idle testing (as described in appendix B of this 
subpart S) of pre-1981 vehicles is assumed.
    (7) Emission standards. (i) Emission standards for 1986 through 1993 
model year light duty vehicles, and 1994 and 1995 light-duty vehicles 
not meeting Tier 1 emission standards, of 0.80 gpm hydrocarbons (HC), 20 
gpm CO, and 2.0 gpm NOX;
    (ii) Emission standards for 1986 through 1993 light duty trucks less 
than 6000 pounds gross vehicle weight rating (GVWR), and 1994 and 1995 
trucks not meeting Tier 1 emission standards, of 1.2 gpm HC, 20 gpm CO, 
and 3.5 gpm NOX;
    (iii) Emission standards for 1986 through 1993 light duty trucks 
greater than 6000 pounds GVWR, and 1994 and 1995 trucks not meeting the 
Tier 1 emission standards, of 1.2 gpm HC, 20 gpm CO, and 3.5 gpm 
NOX;
    (iv) Emission standards for 1994 and later light duty vehicles 
meeting Tier 1 emission standards of 0.70 gpm HC, 15 gpm CO, and 1.4 gpm 
NOX;
    (v) Emission standards for 1994 and later light duty trucks under 
6000 pounds GVWR and meeting Tier 1 emission standards of 0.70 gpm HC, 
15 gpm CO, and 2.0 gpm NOX;
    (vi) Emission standards for 1994 and later light duty trucks greater 
than 6000 pounds GVWR and meeting Tier 1 emission standards of 0.80 gpm 
HC, 15 gpm CO and 2.5 gpm NOX;
    (vii) Emission standards for 1981-1985 model year vehicles of 1.2% 
CO, and 220 gpm HC for the idle, two-speed tests and loaded steady-state 
tests (as described in appendix B of this subpart S); and
    (viii) Maximum exhaust dilution measured as no less than 6% CO plus 
carbon dioxide (CO2) on vehicles subject to a steady-state 
test (as described in appendix B of this subpart S); and
    (viii) Maximum exhaust dilution measured as no less than 6% CO plus 
carbon dioxide (CO2) on vehicles subject to a steady-state 
test (as described in appendix B of this subpart S).
    (8) Emission control device inspections. (i) Visual inspection of 
the catalyst and fuel inlet restrictor on all 1984 and later model year 
vehicles.
    (ii) Visual inspection of the positive crankcase ventilation valve 
on 1968 through 1971 model years, inclusive, and of the exhaust gas 
recirculation valve on 1972 through 1983 model year vehicles, inclusive.
    (9) Evaporative system function checks. Evaporative system integrity 
(pressure) test on 1983 and later model year vehicles and an evaporative 
system transient purge test on 1986 and later model year vehicles.
    (10) Stringency. A 20% emission test failure rate among pre-1981 
model year vehicles.
    (11) Waiver rate. A 3% waiver rate, as a percentage of failed 
vehicles.

[[Page 311]]

    (12) Compliance rate. A 96% compliance rate.
    (13) Evaluation date. Enhanced I/M program areas subject to the 
provisions of this paragraph shall be shown to obtain the same or lower 
emission levels as the model program described in this paragraph by 
January 1, 2002 to within 0.02 gpm. Subject 
programs shall demonstrate through modeling the ability to maintain this 
level of emission reduction (or better) through their attainment 
deadline for the applicable NAAQS standard(s).
    (g) Alternate Low Enhanced I/M Performance Standard. An enhanced I/M 
area which is either not subject to or has an approved State 
Implementation Plan pursuant to the requirements of the Clean Air Act 
Amendments of 1990 for Reasonable Further Progress in 1996, and does not 
have a disapproved plan for Reasonable Further Progress for the period 
after 1996 or a disapproved plan for attainment of the air quality 
standards for ozone or CO, may select the alternate low enhanced I/M 
performance standard described below in lieu of the standard described 
in paragraph (f) of this section. The model program elements for this 
alternate low enhanced I/M performance standard are:
    (1) Network type. Centralized testing.
    (2) Start date. For areas with existing I/M programs, 1983. For 
areas newly subject, 1995.
    (3) Test frequency. Annual testing.
    (4) Model year coverage. Testing of 1968 and newer vehicles.
    (5) Vehicle type coverage. Light duty vehicles, and light duty 
trucks, rated up to 8,500 pounds GVWR.
    (6) Exhaust emission test type. Idle testing of all covered vehicles 
(as described in appendix B of subpart S).
    (7) Emission standards. Those specified in 40 CFR part 85, subpart 
W.
    (8) Emission control device inspections. Visual inspection of the 
positive crankcase ventilation valve on all 1968 through 1971 model year 
vehicles, inclusive, and of the exhaust gas recirculation valve on all 
1972 and newer model year vehicles.
    (9) Evaporative system function checks. None.
    (10) Stringency. A 20% emission test failure rate among pre-1981 
model year vehicles.
    (11) Waiver rate. A 3% waiver rate, as a percentage of failed 
vehicles.
    (12) Compliance rate. A 96% compliance rate.
    (13) Evaluation date. Enhanced I/M program areas subject to the 
provisions of this paragraph (g) shall be shown to obtain the same or 
lower emission levels as the model program described in this paragraph 
by January 1, 2002 to within 0.02 gpm. Subject 
programs shall demonstrate through modeling the ability to maintain this 
level of emission reduction (or better) through their attainment 
deadline for the applicable NAAQS standard(s).
    (h) Ozone Transport Region Low-Enhanced Performance Standard. An 
attainment area, marginal ozone area, or moderate ozone area with a 1980 
Census population of less than 200,000 in the urbanized area, in an 
ozone transport region, that is required to implement enhanced I/M under 
section 184(b)(1)(A) of the Clean Air Act, but was not previously 
required to or did not in fact implement basic I/M under the Clean Air 
Act as enacted prior to 1990 and is not subject to the requirements for 
basic I/M programs in this subpart, may select the performance standard 
described below in lieu of the standard described in paragraph (f) or 
(g) of this section as long as the difference in emission reductions 
between the program described in paragraph (g) and this paragraph are 
made up with other measures, as provided in Sec. 51.350(b)(5). 
Offsetting measures shall not include those otherwise required by the 
Clean Air Act in the areas from which credit is bubbled. The program 
elements for this alternate OTR enhanced I/M performance standard are:
    (1) Network type. Centralized testing.
    (2) Start date. January 1, 1999.
    (3) Test frequency. Annual testing.
    (4) Model year coverage. Testing of 1968 and newer vehicles.
    (5) Vehicle type coverage. Light duty vehicles, and light duty 
trucks, rated up to 8,500 pounds GVWR.
    (6) Exhaust emission test type. Remote sensing measurements on 1968-
1995 vehicles; on-board diagnostic system checks on 1996 and newer 
vehicles.

[[Page 312]]

    (7) Emission standards. For remote sensing measurements, a carbon 
monoxide standard of 7.5% (with at least two separate readings above 
this level to establish a failure).
    (8) Emission control device inspections. Visual inspection of the 
catalytic converter on 1975 and newer vehicles and visual inspection of 
the positive crankcase ventilation valve on 1968-1974 vehicles.
    (9) Waiver rate. A 3% waiver rate, as a percentage of failed 
vehicles.
    (10) Compliance rate. A 96% compliance rate.
    (11) Evaluation date. Enhanced I/M program areas subject to the 
provisions of this paragraph shall be shown to obtain the same or lower 
VOC and NOx emission levels as the model program described in this 
paragraph (h) by January 1, 2002 to within 0.02 
gpm. Subject programs shall demonstrate through modeling the ability to 
maintain this level of emission reduction (or better) through their 
attainment deadline for the applicable NAAQS standard(s). Equality of 
substituted emission reductions to the benefits of the low enhanced 
performance standard must be demonstrated for the same evaluation date.
    (i) Enhanced performance standard for areas designated and 
classified under the 8-hour ozone standard. Areas required to implement 
an enhanced I/M program as a result of being designated and classified 
under the 8-hour ozone standard, must meet or exceed the HC and 
NOX emission reductions achieved by the model program defined 
as follows:
    (1) Network type. Centralized testing.
    (2) Start date. 4 years after the effective date of designation and 
classification under the 8-hour ozone standard.
    (3) Test frequency. Annual testing.
    (4) Model year coverage. Testing of 1968 and newer vehicles.
    (5) Vehicle type coverage. Light duty vehicles, and light duty 
trucks, rated up to 8,500 pounds GVWR.
    (6) Emission test type. Idle testing (as described in appendix B of 
this subpart) for 1968-2000 vehicles; onboard diagnostic checks on 2001 
and newer vehicles.
    (7) Emission standards. Those specified in 40 CFR part 85, subpart 
W.
    (8) Emission control device inspections. Visual inspection of the 
positive crankcase ventilation valve on all 1968 through 1971 model year 
vehicles, inclusive, and of the exhaust gas recirculation valve on all 
1972 and newer model year vehicles.
    (9) Evaporative system function checks. None, with the exception of 
those performed by the OBD system on vehicles so-equipped and only for 
model year 2001 and newer vehicles.
    (10) Stringency. A 20% emission test failure rate among pre-1981 
model year vehicles.
    (11) Waiver rate. A 3% waiver rate, as a percentage of failed 
vehicles.
    (12) Compliance rate. A 96% compliance rate.
    (13) Evaluation date. Enhanced I/M program areas subject to the 
provisions of this paragraph (i) shall be shown to obtain the same or 
lower emission levels for HC and NOX as the model program 
described in this paragraph assuming an evaluation date set 6 years 
after the effective date of designation and classification under the 8-
hour ozone standard (rounded to the nearest July) to within 0.02 gpm. Subject programs shall demonstrate through 
modeling the ability to maintain this percent level of emission 
reduction (or better) through their applicable attainment date for the 
8-hour ozone standard, also rounded to the nearest July.

[57 FR 52987, Nov. 5, 1992, as amended at 58 FR 59367, Nov. 9, 1993; 59 
FR 32343, June 23, 1994; 60 FR 48035, Sept. 18, 1995; 61 FR 39036, July 
25, 1996; 61 FR 40945, Aug. 6, 1996; 63 FR 24433, May 4, 1998; 65 FR 
45532, July 24, 2000; 66 FR 18176, Apr. 5, 2001; 71 FR 17710, Apr. 7, 
2006]



Sec. 51.352  Basic I/M performance standard.

    (a) Basic I/M programs shall be designed and implemented to meet or 
exceed a minimum performance standard, which is expressed as emission 
levels achieved from highway mobile sources as a result of the program. 
The performance standard shall be established using the following model 
I/M program inputs and local characteristics, such as vehicle mix and 
local fuel controls. Similarly, the emission reduction benefits of the 
State's program design

[[Page 313]]

shall be estimated using the most current version of the EPA mobile 
source emission model, and shall meet the minimum performance standard 
both in operation and for SIP approval.
    (1) Network type. Centralized testing.
    (2) Start date. For areas with existing I/M programs, 1983. For 
areas newly subject, 1994.
    (3) Test frequency. Annual testing.
    (4) Model year coverage. Testing of 1968 and later model year 
vehicles.
    (5) Vehicle type coverage. Light duty vehicles.
    (6) Exhaust emission test type. Idle test.
    (7) Emission standards. No weaker than specified in 40 CFR part 85, 
subpart W.
    (8) Emission control device inspections. None.
    (9) Stringency. A 20% emission test failure rate among pre-1981 
model year vehicles.
    (10) Waiver rate. A 0% waiver rate.
    (11) Compliance rate. A 100% compliance rate.
    (12) Evaluation date. Basic I/M programs shall be shown to obtain 
the same or lower emission levels as the model inputs by 1997 for ozone 
nonattainment areas and 1996 for CO nonattainment areas; and, for 
serious or worse ozone nonattainment areas, on each applicable milestone 
and attainment deadline, thereafter.
    (b) Oxides of nitrogen. Basic I/M testing in ozone nonattainment 
areas shall be designed such that no increase in NOX 
emissions occurs as a result of the program. If the Administrator finds, 
under section 182(b)(1)(A)(i) of the Act pertaining to reasonable 
further progress demonstrations or section 182(f)(1) of the Act 
pertaining to provisions for major stationary sources, that 
NOX emission reductions are not beneficial in a given ozone 
nonattainment area, then the basic I/M NOX requirement may be 
omitted. States shall implement any required NOX controls 
within 12 months of implementation of the program deadlines required in 
Sec. 51.373 of this subpart, except that newly implemented I/M programs 
shall include NOX controls from the start.
    (c) On-board diagnostics (OBD). For those areas required to 
implement a basic I/M program prior to the effective date of designation 
and classification under the 8-hour ozone standard, the performance 
standard shall include inspection of all model year 1996 and later 
light-duty vehicles equipped with certified on-board diagnostic systems, 
and repair of malfunctions or system deterioration identified by or 
affecting OBD systems as specified in Sec. 51.357, and assuming a start 
date of 2002 for such testing. For areas required to implement basic I/M 
as a result of designation and classification under the 8-hour ozone 
standard, the performance standard defined in paragraph (e) of this 
section shall include inspection of all model year 2001 and later light-
duty vehicles equipped with certified on-board diagnostic systems, and 
repair of malfunctions or system deterioration identified by or 
affecting OBD systems as specified in Sec. 51.357, and assuming a start 
date of 4 years after the effective date of designation and 
classification under the 8-hour ozone standard.
    (d) Modeling requirements. Equivalency of emission levels which will 
be achieved by the I/M program design in the SIP to those of the model 
program described in this section shall be demonstrated using the most 
current version of EPA's mobile source emission model and EPA guidance 
on the estimation of input parameters. Areas required to implement basic 
I/M programs shall meet the performance standard for the pollutants 
which cause them to be subject to basic requirements. Areas subject as a 
result of ozone nonattainment shall meet the standard for VOCs and shall 
demonstrate no NOX increase, as required in paragraph (b) of 
this section.
    (e) Basic performance standard for areas designated non-attainment 
for the 8-hour ozone standard. Areas required to implement a basic I/M 
program as a result of being designated and classified under the 8-hour 
ozone standard, must meet or exceed the emission reductions achieved by 
the model program defined for the applicable ozone precursor(s):
    (1) Network type. Centralized testing.
    (2) Start date. 4 years after the effective date of designation and 
classification under the 8-hour ozone standard.
    (3) Test frequency. Annual testing.
    (4) Model year coverage. Testing of 1968 and newer vehicles.

[[Page 314]]

    (5) Vehicle type coverage. Light duty vehicles.
    (6) Emission test type. Idle testing (as described in appendix B of 
this subpart) for 1968-2000 vehicles; onboard diagnostic checks on 2001 
and newer vehicles.
    (7) Emission standards. Those specified in 40 CFR part 85, subpart 
W.
    (8) Emission control device inspections. None.
    (9) Evaporative system function checks. None, with the exception of 
those performed by the OBD system on vehicles so-equipped and only for 
model year 2001 and newer vehicles.
    (10) Stringency. A 20% emission test failure rate among pre-1981 
model year vehicles.
    (11) Waiver rate. A 0% waiver rate, as a percentage of failed 
vehicles.
    (12) Compliance rate. A 100% compliance rate.
    (13) Evaluation date. Basic I/M program areas subject to the 
provisions of this paragraph (e) shall be shown to obtain the same or 
lower emission levels as the model program described in this paragraph 
by an evaluation date set 6 years after the effective date of 
designation and classification under the 8-hour ozone standard (rounded 
to the nearest July) for the applicable ozone precursor(s).

[57 FR 52987, Nov. 5, 1992, as amended at 61 FR 40945, Aug. 6, 1996; 63 
FR 24433, May 4, 1998; 66 FR 18177, Apr. 5, 2001; 71 FR 17711, Apr. 7, 
2006]



Sec. 51.353  Network type and program evaluation.

    Basic and enhanced I/M programs can be centralized, decentralized, 
or a hybrid of the two at the State's discretion, but shall be 
demonstrated to achieve the same (or better) level of emission reduction 
as the applicable performance standard described in either Sec. 51.351 
or 51.352 of this subpart. For decentralized programs other than those 
meeting the design characteristics described in paragraph (a) of this 
section, the State must demonstrate that the program is achieving the 
level of effectiveness claimed in the plan within 12 months of the 
plan's final conditional approval before EPA can convert that approval 
to a final full approval. The adequacy of these demonstrations will be 
judged by the Administrator on a case-by-case basis through notice-and-
comment rulemaking.
    (a) Presumptive equivalency. A decentralized network consisting of 
stations that only perform official I/M testing (which may include 
safety-related inspections) and in which owners and employees of those 
stations, or companies owning those stations, are contractually or 
legally barred from engaging in motor vehicle repair or service, motor 
vehicle parts sales, and motor vehicle sale and leasing, either directly 
or indirectly, and are barred from referring vehicle owners to 
particular providers of motor vehicle repair services (except as 
provided in Sec. 51.369(b)(1) of this subpart) shall be considered 
presumptively equivalent to a centralized, test-only system including 
comparable test elements. States may allow such stations to engage in 
the full range of sales not covered by the above prohibition, including 
self-serve gasoline, pre-packaged oil, or other, non-automotive, 
convenience store items. At the State's discretion, such stations may 
also fulfill other functions typically carried out by the State such as 
renewal of vehicle registration and driver's licenses, or tax and fee 
collections.
    (b) [Reserved]
    (c) Program evaluation. Enhanced I/M programs shall include an 
ongoing evaluation to quantify the emission reduction benefits of the 
program, and to determine if the program is meeting the requirements of 
the Clean Air Act and this subpart.
    (1) The State shall report the results of the program evaluation on 
a biennial basis, starting two years after the initial start date of 
mandatory testing as required in Sec. 51.373 of this subpart.
    (2) The evaluation shall be considered in establishing actual 
emission reductions achieved from I/M for the purposes of satisfying the 
requirements of sections 182(g)(1) and 182(g)(2) of the Clean Air Act, 
relating to reductions in emissions and compliance demonstration.
    (3) The evaluation program shall consist, at a minimum, of those 
items described in paragraph (b)(1) of this section and program 
evaluation data

[[Page 315]]

using a sound evaluation methodology, as approved by EPA, and 
evaporative system checks, specified in Sec. 51.357(a) (9) and (10) of 
this subpart, for model years subject to those evaporative system test 
procedures. The test data shall be obtained from a representative, 
random sample, taken at the time of initial inspection (before repair) 
on a minimum of 0.1 percent of the vehicles subject to inspection in a 
given year. Such vehicles shall receive a State administered or 
monitored test, as specified in this paragraph (c)(3), prior to the 
performance of I/M-triggered repairs during the inspection cycle under 
consideration.
    (4) The program evaluation test data shall be submitted to EPA and 
shall be capable of providing accurate information about the overall 
effectiveness of an I/M program, such evaluation to begin no later than 
1 year after program start-up.
    (5) Areas that qualify for and choose to implement an OTR low 
enhanced I/M program, as established in Sec. 51.351(h), and that claim 
in their SIP less emission reduction credit than the basic performance 
standard for one or more pollutants, are exempt from the requirements of 
paragraphs (c)(1) through (c)(4) of this section. The reports required 
under Sec. 51.366 of this part shall be sufficient in these areas to 
satisfy the requirements of Clean Air Act for program reporting.
    (d) SIP requirements. (1) The SIP shall include a description of the 
network to be employed, the required legal authority, and, in the case 
of areas making claims under paragraph (b) of this section, the required 
demonstration.
    (2) The SIP shall include a description of the evaluation schedule 
and protocol, the sampling methodology, the data collection and analysis 
system, the resources and personnel for evaluation, and related details 
of the evaluation program, and the legal authority enabling the 
evaluation program.

[57 FR 52987, Nov. 5, 1992, as amended at 58 FR 59367, Nov. 9, 1993; 61 
FR 39037, July 25, 1996; 63 FR 1368, Jan. 9, 1998; 65 FR 45532, July 24, 
2000; 71 FR 17711, Apr. 7, 2006]



Sec. 51.354  Adequate tools and resources.

    (a) Administrative resources. The program shall maintain the 
administrative resources necessary to perform all of the program 
functions including quality assurance, data analysis and reporting, and 
the holding of hearings and adjudication of cases. A portion of the test 
fee or a separately assessed per vehicle fee shall be collected, placed 
in a dedicated fund and retained, to be used to finance program 
oversight, management, and capital expenditures. Alternatives to this 
approach shall be acceptable if the State can demonstrate that adequate 
funding of the program can be maintained in some other fashion (e.g., 
through contractual obligation along with demonstrated past 
performance). Reliance on future uncommitted annual or biennial 
appropriations from the State or local General Fund is not acceptable, 
unless doing otherwise would be a violation of the State's constitution. 
This section shall in no way require the establishment of a test fee if 
the State chooses to fund the program in some other manner.
    (b) Personnel. The program shall employ sufficient personnel to 
effectively carry out the duties related to the program, including but 
not limited to administrative audits, inspector audits, data analysis, 
program oversight, program evaluation, public education and assistance, 
and enforcement against stations and inspectors as well as against 
motorists who are out of compliance with program regulations and 
requirements.
    (c) Equipment. The program shall possess equipment necessary to 
achieve the objectives of the program and meet program requirements, 
including but not limited to a steady supply of vehicles for covert 
auditing, test equipment and facilities for program evaluation, and 
computers capable of data processing, analysis, and reporting. Equipment 
or equivalent services may be contractor supplied or owned by the State 
or local authority.
    (d) SIP requirements. The SIP shall include a description of the 
resources that will be used for program operation, and discuss how the 
performance standard will be met.

[[Page 316]]

    (1) The SIP shall include a detailed budget plan which describes the 
source of funds for personnel, program administration, program 
enforcement, purchase of necessary equipment (such as vehicles for 
undercover audits), and any other requirements discussed throughout, for 
the period prior to the next biennial self-evaluation required in Sec. 
51.366 of this subpart.
    (2) The SIP shall include a description of personnel resources. The 
plan shall include the number of personnel dedicated to overt and covert 
auditing, data analysis, program administration, enforcement, and other 
necessary functions and the training attendant to each function.



Sec. 51.355  Test frequency and convenience.

    (a) The performance standards for I/M programs assume an annual test 
frequency; other schedules may be approved if the required emission 
targets are achieved. The SIP shall describe the test schedule in 
detail, including the test year selection scheme if testing is other 
than annual. The SIP shall include the legal authority necessary to 
implement and enforce the test frequency requirement and explain how the 
test frequency will be integrated with the enforcement process.
    (b) In enhanced I/M programs, test systems shall be designed in such 
a way as to provide convenient service to motorists required to get 
their vehicles tested. The SIP shall demonstrate that the network of 
stations providing test services is sufficient to insure short waiting 
times to get a test and short driving distances. Stations shall be 
required to adhere to regular testing hours and to test any subject 
vehicle presented for a test during its test period.



Sec. 51.356  Vehicle coverage.

    The performance standard for enhanced I/M programs assumes coverage 
of all 1968 and later model year light duty vehicles and light duty 
trucks up to 8,500 pounds GVWR, and includes vehicles operating on all 
fuel types. The standard for basic I/M programs does not include light 
duty trucks. Other levels of coverage may be approved if the necessary 
emission reductions are achieved. Vehicles registered or required to be 
registered within the I/M program area boundaries and fleets primarily 
operated within the I/M program area boundaries and belonging to the 
covered model years and vehicle classes comprise the subject vehicles.
    (a) Subject vehicles. (1) All vehicles of a covered model year and 
vehicle type shall be tested according to the applicable test schedule, 
including leased vehicles whose registration or titling is in the name 
of an equity owner other than the lessee or user.
    (2) All subject fleet vehicles shall be inspected. Fleets may be 
officially inspected outside of the normal I/M program test facilities, 
if such alternatives are approved by the program administration, but 
shall be subject to the same test requirements using the same quality 
control standards as non-fleet vehicles. If all vehicles in a particular 
fleet are tested during one part of the cycle, then the quality control 
requirements shall be met during the time of testing only. Any vehicle 
available for rent in the I/M area or for use in the I/M area shall be 
subject. Fleet vehicles not being tested in normal I/M test facilities 
in enhanced I/M programs, however, shall be inspected in independent, 
test-only facilities, according to the requirements of Sec. 51.353(a) 
of this subpart.
    (3) Subject vehicles which are registered in the program area but 
are primarily operated in another I/M area shall be tested, either in 
the area of primary operation, or in the area of registration. Alternate 
schedules may be established to permit convenient testing of these 
vehicles (e.g., vehicles belonging to students away at college should be 
rescheduled for testing during a visit home). I/M programs shall make 
provisions for providing official testing to vehicles registered 
elsewhere.
    (4) Vehicles which are operated on Federal installations located 
within an I/M program area shall be tested, regardless of whether the 
vehicles are registered in the State or local I/M area. This requirement 
applies to all employee-owned or leased vehicles (including vehicles 
owned, leased, or operated by civilian and military personnel on Federal 
installations) as well as

[[Page 317]]

agency-owned or operated vehicles, except tactical military vehicles, 
operated on the installation. This requirement shall not apply to 
visiting agency, employee, or military personnel vehicles as long as 
such visits do not exceed 60 calendar days per year. In areas without 
test fees collected in the lane, arrangements shall be made by the 
installation with the I/M program for reimbursement of the costs of 
tests provided for agency vehicles, at the discretion of the I/M agency. 
The installation shall provide documentation of proof of compliance to 
the I/M agency. The documentation shall include a list of subject 
vehicles and shall be updated periodically, as determined by the I/M 
program administrator, but no less frequently than each inspection 
cycle. The installation shall use one of the following methods to 
establish proof of compliance:
    (i) Presentation of a valid certificate of compliance from the local 
I/M program, from any other I/M program at least as stringent as the 
local program, or from any program deemed acceptable by the I/M program 
administrator.
    (ii) Presentation of proof of vehicle registration within the 
geographic area covered by the I/M program, except for any program whose 
enforcement is not through registration denial.
    (iii) Another method approved by the State or local I/M program 
administrator.
    (5) Special exemptions may be permitted for certain subject vehicles 
provided a demonstration is made that the performance standard will be 
met.
    (6) States may also exempt MY 1996 and newer OBD-equipped vehicles 
that receive an OBD-I/M inspection from the tailpipe, purge, and fill-
neck pressure tests (where applicable) without any loss of emission 
reduction credit.
    (b) SIP requirements. (1) The SIP shall include a detailed 
description of the number and types of vehicles to be covered by the 
program, and a plan for how those vehicles are to be identified, 
including vehicles that are routinely operated in the area but may not 
be registered in the area.
    (2) The SIP shall include a description of any special exemptions 
which will be granted by the program, and an estimate of the percentage 
and number of subject vehicles which will be impacted. Such exemptions 
shall be accounted for in the emission reduction analysis.
    (3) The SIP shall include the legal authority or rule necessary to 
implement and enforce the vehicle coverage requirement.

[57 FR 52987, Nov. 5, 1992, as amended at 66 FR 18177, Apr. 5, 2001]



Sec. 51.357  Test procedures and standards.

    Written test procedures and pass/fail standards shall be established 
and followed for each model year and vehicle type included in the 
program.
    (a) Test procedure requirements. Emission tests and functional tests 
shall be conducted according to good engineering practices to assure 
test accuracy.
    (1) Initial tests (i.e., those occurring for the first time in a 
test cycle) shall be performed without repair or adjustment at the 
inspection facility, prior to the test, except as provided in paragraph 
(a)(10)(i) of this section.
    (2) The vehicle owner or driver shall have access to the test area 
such that observation of the entire official inspection process on the 
vehicle is permitted. Such access may be limited but shall in no way 
prevent full observation.
    (3) An official test, once initiated, shall be performed in its 
entirety regardless of intermediate outcomes except in the case of 
invalid test condition, unsafe conditions, fast pass/fail algorithms, 
or, in the case of the on-board diagnostic (OBD) system check, unset 
readiness codes.
    (4) Tests involving measurement shall be performed with program-
approved equipment that has been calibrated according to the quality 
procedures contained in appendix A to this subpart.
    (5) Vehicles shall be rejected from testing if the exhaust system is 
missing or leaking, or if the vehicle is in an unsafe condition for 
testing. Coincident with mandatory OBD-I/M testing and repair of 
vehicles so equipped, MY 1996 and newer vehicles shall be rejected from 
testing if a scan of the OBD system reveals a ``not ready'' code for any 
component of the OBD system. At

[[Page 318]]

a state's option it may choose alternatively to reject MY 1996-2000 
vehicles only if three or more ``not ready'' codes are present and to 
reject MY 2001 and later model years only if two or more ``not ready'' 
codes are present. This provision does not release manufacturers from 
the obligations regarding readiness status set forth in 40 CFR 86.094-
17(e)(1): ``Control of Air Pollution From New Motor Vehicles and New 
Motor Vehicle Engines: Regulations RequiringOn-Board Diagnostic Systems 
on 1994 and Later Model Year Light-Duty Vehicles and Light-Duty 
Trucks.'' Once the cause for rejection has been corrected, the vehicle 
must return for testing to continue the testing process. Failure to 
return for testing in a timely manner after rejection shall be 
considered non-compliance with the program, unless the motorist can 
prove that the vehicle has been sold, scrapped, or is otherwise no 
longer in operation within the program area.
    (6) Vehicles shall be retested after repair for any portion of the 
inspection that is failed on the previous test to determine if repairs 
were effective. To the extent that repair to correct a previous failure 
could lead to failure of another portion of the test, that portion shall 
also be retested. Evaporative system repairs shall trigger an exhaust 
emissions retest (in programs which conduct an exhaust emission test as 
part of the initial inspection).
    (7) Steady-state testing. Steady-state tests shall be performed in 
accordance with the procedures contained in appendix B to this subpart.
    (8) Emission control device inspection. Visual emission control 
device checks shall be performed through direct observation or through 
indirect observation using a mirror, video camera or other visual aid. 
These inspections shall include a determination as to whether each 
subject device is present and appears to be properly connected and 
appears to be the correct type for the certified vehicle configuration.
    (9) Evaporative system purge test procedure. The purge test 
procedure shall consist of measuring the total purge flow (in standard 
liters) occurring in the vehicle's evaporative system during the 
transient dynamometer emission test specified in paragraph (a)(11) of 
this section. The purge flow measurement system shall be connected to 
the purge portion of the evaporative system in series between the 
canister and the engine, preferably near the canister. The inspector 
shall be responsible for ensuring that all items that are disconnected 
in the conduct of the test procedure are properly re-connected at the 
conclusion of the test procedure. Alternative procedures may be used if 
they are shown to be equivalent or better to the satisfaction of the 
Administrator. Except in the case of government-run test facilities 
claiming sovereign immunity, any damage done to the evaporative emission 
control system during this test shall be repaired at the expense of the 
inspection facility.
    (10) Evaporative system integrity test procedure. The test sequence 
shall consist of the following steps:
    (i) Test equipment shall be connected to the fuel tank canister hose 
at the canister end. The gas cap shall be checked to ensure that it is 
properly, but not excessively tightened, and shall be tightened if 
necessary.
    (ii) The system shall be pressurized to 14 0.5 
inches of water without exceeding 26 inches of water system pressure.
    (iii) Close off the pressure source, seal the evaporative system and 
monitor pressure decay for up to two minutes.
    (iv) Loosen the gas cap after a maximum of two minutes and monitor 
for a sudden pressure drop, indicating that the fuel tank was 
pressurized.
    (v) The inspector shall be responsible for ensuring that all items 
that are disconnected in the conduct of the test procedure are properly 
re-connected at the conclusion of the test procedure.
    (vi) Alternative procedures may be used if they are shown to be 
equivalent or better to the satisfaction of the Administrator. Except in 
the case of government-run test facilities claiming sovereign immunity, 
any damage done to the evaporative emission control system during this 
test shall be repaired at the expense of the inspection facility.
    (11) Transient emission test. The transient emission test shall 
consist of

[[Page 319]]

mass emission measurement using a constant volume sampler (or an 
Administrator-approved alternative methodology for accounting for 
exhaust volume) while the vehicle is driven through a computer-monitored 
driving cycle on a dynamometer. The driving cycle shall include 
acceleration, deceleration, and idle operating modes as specified in 
appendix E to this subpart (or an approved alternative). The driving 
cycle may be ended earlier using approved fast pass or fast fail 
algorithms and multiple pass/fail algorithms may be used during the test 
cycle to eliminate false failures. The transient test procedure, 
including algorithms and other procedural details, shall be approved by 
the Administrator prior to use in an I/M program.
    (12) On-board diagnostic checks. Beginning January 1, 2002, 
inspection of the on-board diagnostic (OBD) system on MY 1996 and newer 
light-duty vehicles and light-duty trucks shall be conducted according 
to the procedure described in 40 CFR 85.2222, at a minimum. This 
inspection may be used in lieu of tailpipe, purge, and fill-neck 
pressure testing. Alternatively, states may elect to phase-in OBD-I/M 
testing for one test cycle by using the OBD-I/M check to screen clean 
vehicles from tailpipe testing and require repair and retest for only 
those vehicles which proceed to fail the tailpipe test. An additional 
alternative is also available to states with regard to the deadline for 
mandatory testing, repair, and retesting of vehicles based upon the OBD-
I/M check. Under this third option, if a state can show good cause (and 
the Administrator takes notice-and-comment action to approve this good 
cause showing as a revision to the State's Implementation Plan), up to 
an additional 12 months' extensionmay be granted, establishing an 
alternative start date for such states of no later than January 1, 2003. 
States choosing to make this showing will also have available to them 
the phase-in approach described in this section, with the one-cycle time 
limit to begin coincident with the alternative start date established by 
Administrator approval of the showing, but no later than January 1, 
2003. The showing of good cause (and its approval or disapproval) will 
be addressed on a case-by-case basis by the Administrator.
    (13) Approval of alternative tests. Alternative test procedures may 
be approved if the Administrator finds that such procedures show a 
reasonable correlation with the Federal Test Procedure and are capable 
of identifying comparable emission reductions from the I/M program as a 
whole, in combination with other program elements, as would be 
identified by the test(s) which they are intended to replace.
    (b) Test standards--(1) Emissions standards. HC, CO, and 
CO+CO2 (or CO2 alone) emission standards shall be 
applicable to all vehicles subject to the program with the exception of 
MY 1996 and newer OBD-equipped light-duty vehicles and light-duty 
trucks, which will be held to the requirements of 40 CFR 85.2207, at a 
minimum. Repairs shall be required for failure of any standard 
regardless of the attainment status of the area. NOX emission 
standards shall be applied to vehicles subject to a loaded mode test in 
ozone nonattainment areas and in an ozone transport region, unless a 
waiver of NOX controls is provided to the State under Sec. 
51.351(d).
    (i) Steady-state short tests. The steady-state short test emission 
standards for 1981 and later model year light duty vehicles and light 
duty trucks shall be at least as stringent as those in appendix C to 
this subpart.
    (ii) Transient test. Transient test emission standards shall be 
established for HC, CO, CO2, and NOX for subject 
vehicles based on model year and vehicle type.
    (2) Visual equipment inspection standards. (i) Vehicles shall fail 
visual inspections of subject emission control devices if such devices 
are part of the original certified configuration and are found to be 
missing, modified, disconnected, or improperly connected.
    (ii) Vehicles shall fail visual inspections of subject emission 
control devices if such devices are found to be incorrect for the 
certified vehicle configuration under inspection. Aftermarket parts, as 
well as original equipment manufacture parts, may be considered correct 
if they are proper for the certified vehicle configuration. Where an EPA 
aftermarket approval or self-certification program exists for a

[[Page 320]]

particular class of subject parts, vehicles shall fail visual equipment 
inspections if the part is neither original equipment manufacture nor 
from an approved or self-certified aftermarket manufacturer.
    (3) Functional test standards--(i) Evaporative system integrity 
test. Vehicles shall fail the evaporative system pressure test if the 
system cannot maintain a system pressure above eight inches of water for 
up to two minutes after being pressurized to 14 0.5 inches of water or if no pressure drop is detected 
when the gas cap is loosened as described in paragraph (a)(10)(iv) of 
this section. Additionally, vehicles shall fail the evaporative test if 
the canister is missing or obviously damaged, if hoses are missing or 
obviously disconnected, or if the gas cap is missing.
    (ii) Evaporative canister purge test. Vehicles with a total purge 
system flow measuring less than one liter, over the course of the 
transient test required in paragraph (a)(9) of this section, shall fail 
the evaporative purge test.
    (4) On-board diagnostic test standards. Vehicles shall fail the on-
board diagnostic test if they fail to meet the requirements of 40 CFR 
85.2207, at a minimum. Failure of the on-board diagnostic test need not 
result in failure of the vehicle inspection/maintenance test until 
January 1, 2002. Alternatively, states may elect to phase-in OBD-I/M 
testing for one test cycle by using the OBD- I/M check to screen clean 
vehicles from tailpipe testing and require repair and retest for only 
those vehicles which proceed to fail the tailpipe test. An additional 
alternative is also available to states with regard to the deadline for 
mandatory testing, repair, and retesting of vehicles based upon the OBD-
I/M check. Under this third option, if a state can show good cause (and 
the Administrator takes notice-and-comment action to approve this good 
cause showing), up to an additional 12 months' extension may be granted, 
establishing an alternative start date for such states of no later than 
January 1, 2003. States choosing to make this showing will also have 
available to them the phase-in approach described in this section, with 
the one-cycle time limit to begin coincident with the alternative start 
date established by Administrator approval of the showing, but no later 
than January 1, 2003. The showing of good cause (and its approval or 
disapproval) will be addressed on a case-by-case basis.
    (c) Fast test algorithms and standards. Special test algorithms and 
pass/fail algorithms may be employed to reduce test time when the test 
outcome is predictable with near certainty, if the Administrator 
approves by letter the equivalency to full procedure testing.
    (d) Applicability. In general, section 203(a)(3)(A) of the Clean Air 
Act prohibits altering a vehicle's configuration such that it changes 
from a certified to a non-certified configuration. In the inspection 
process, vehicles that have been altered from their original certified 
configuration are to be tested in the same manner as other subject 
vehicles with the exception of MY 1996 and newer, OBD-equipped vehicles 
on which the data link connector is missing, has been tampered with or 
which has been altered in such a way as to make OBD system testing 
impossible. Such vehicles shall be failed for the on-board diagnostics 
portion of the test and are expected to be repaired so that the vehicle 
is testable. Failure to return for retesting in a timely manner after 
failure and repair shall be considered non-compliance with the program, 
unless the motorist can prove that the vehicle has been sold, scrapped, 
or is otherwise no longer in operation within the program area.
    (1) Vehicles with engines other than the engine originally installed 
by the manufacturer or an identical replacement of such engine shall be 
subject to the test procedures and standards for the chassis type and 
model year including visual equipment inspections for all parts that are 
part of the original or now-applicable certified configuration and part 
of the normal inspection. States may choose to require vehicles with 
such engines to be subject to the test procedures and standards for the 
engine model year if it is newer than the chassis model year.
    (2) Vehicles that have been switched from an engine of one fuel type 
to another fuel type that is subject to the program (e.g., from a diesel 
engine to a gasoline engine) shall be subject to the

[[Page 321]]

test procedures and standards for the current fuel type, and to the 
requirements of paragraph (d)(1) of this section.
    (3) Vehicles that are switched to a fuel type for which there is no 
certified configuration shall be tested according to the most stringent 
emission standards established for that vehicle type and model year. 
Emission control device requirements may be waived if the program 
determines that the alternatively fueled vehicle configuration would 
meet the new vehicle standards for that model year without such devices.
    (4) Mixing vehicle classes (e.g., light-duty with heavy-duty) and 
certification types (e.g., California with Federal) within a single 
vehicle configuration shall be considered tampering.
    (e) SIP requirements. The SIP shall include a description of each 
test procedure used. The SIP shall include the rule, ordinance or law 
describing and establishing the test procedures.

[57 FR 52987, Nov. 5, 1992, as amended at 61 FR 40945, Aug. 6, 1996; 63 
FR 24433, May 4, 1998; 65 FR 45533, July 24, 2000; 66 FR 18178, Apr. 5, 
2001]



Sec. 51.358  Test equipment.

    Computerized emission test systems are required for performing an 
official emissions test on subject vehicles.
    (a) Performance features of computerized emission test systems. The 
emission test equipment shall be certified by the program, and newly 
acquired emission test systems shall be subjected to acceptance test 
procedures to ensure compliance with program specifications.
    (1) Emission test equipment shall be capable of testing all subject 
vehicles and shall be updated from time to time to accommodate new 
technology vehicles as well as changes to the program. In the case of 
OBD-based testing, the equipment used to access the onboard computer 
shall be capable of testing all MY 1996 and newer, OBD-equipped light-
duty vehicles and light-duty trucks.
    (2) At a minimum, emission test equipment:
    (i) Shall make automatic pass/fail decisions;
    (ii) Shall be secured from tampering and/or abuse;
    (iii) Shall be based upon written specifications; and
    (iv) Shall be capable of simultaneously sampling dual exhaust 
vehicles in the case of tailpipe-based emission test equipment.
    (3) The vehicle owner or driver shall be provided with a record of 
test results, including all of the items listed in 40 CFR part 85, 
subpart W as being required on the test record (as applicable). The test 
report shall include:
    (i) A vehicle description, including license plate number, vehicle 
identification number, and odometer reading;
    (ii) The date and time of test;
    (iii) The name or identification number of the individual(s) 
performing the tests and the location of the test station and lane;
    (iv) The type(s) of test(s) performed;
    (v) The applicable test standards;
    (vi) The test results, by test, and, where applicable, by pollutant;
    (vii) A statement indicating the availability of warranty coverage 
as required in section 207 of the Clean Air Act;
    (viii) Certification that tests were performed in accordance with 
the regulations and, in the case of decentralized programs, the 
signature of the individual who performed the test; and
    (ix) For vehicles that fail the emission test, information on the 
possible cause(s) of the failure.
    (b) Functional characteristics of computerized emission test 
systems. The test system is composed of motor vehicle test equipment 
controlled by a computerized processor and shall make automatic pass/
fail decisions.
    (1) [Reserved]
    (2) Test systems in enhanced I/M programs shall include a real-time 
data link to a host computer that prevents unauthorized multiple initial 
tests on the same vehicle in a test cycle and to insure test record 
accuracy. For areas which have demonstrated the ability to meet their 
other, non-I/M Clean Air Act requirements without relying on emission 
reductions from the I/M program (and which have also elected to employ 
stand-alone test equipment as part of the I/M program), such areas

[[Page 322]]

may adopt alternative methods for preventing multiple initial tests, 
subject to approval by the Administrator.
    (3) [Reserved]
    (4) On-board diagnostic test equipment requirements. The test 
equipment used to perform on-board diagnostic inspections shall function 
as specified in 40 CFR 85.2231.
    (c) SIP requirements. The SIP shall include written technical 
specifications for all test equipment used in the program and shall 
address each of the above requirements (as applicable). The 
specifications shall describe the testing process, the necessary test 
equipment, the required features, and written acceptance testing 
criteria and procedures.

[57 FR 52987, Nov. 5, 1992, as amended at 61 FR 40945, Aug. 6, 1996; 65 
FR 45533, July 24, 2000; 66 FR 18178, Apr. 5, 2001]



Sec. 51.359  Quality control.

    Quality control measures shall insure that emission testing 
equipment is calibrated and maintained properly, and that inspection, 
calibration records, and control charts are accurately created, recorded 
and maintained (where applicable).
    (a) General requirements. (1) The practices described in this 
section and in appendix A to this subpart shall be followed for those 
tests (or portions of tests) which fall into the testing categories 
identified. Alternatives or exceptions to these procedures or 
frequencies may be approved by the Administrator based on a 
demonstration of comparable performance.
    (2) Preventive maintenance on all inspection equipment necessary to 
insure accurate and repeatable operation shall be performed on a 
periodic basis.
    (3) [Reserved]
    (b) Requirements for steady-state emissions testing equipment. (1) 
Equipment shall be maintained according to demonstrated good engineering 
practices to assure test accuracy. The calibration and adjustment 
requirements in appendix A to this subpart shall apply to all steady-
state test equipment. States may adjust calibration schedules and other 
quality control frequencies by using statistical process control to 
monitor equipment performance on an ongoing basis.
    (2) For analyzers that use ambient air as zero air, provision shall 
be made to draw the air from outside the inspection bay or lane in which 
the analyzer is situated.
    (3) The analyzer housing shall be constructed to protect the 
analyzer bench and electrical components from ambient temperature and 
humidity fluctuations that exceed the range of the analyzer's design 
specifications.
    (4) Analyzers shall automatically purge the analytical system after 
each test.
    (c) Requirements for transient exhaust emission test equipment. 
Equipment shall be maintained according to demonstrated good engineering 
practices to assure test accuracy. Computer control of quality assurance 
checks and quality control charts shall be used whenever possible. 
Exceptions to the procedures and the frequency of the checks described 
in appendix A of this subpart may be approved by the Administrator based 
on a demonstration of comparable performance.
    (d) Requirements for evaporative system functional test equipment. 
Equipment shall be maintained according to demonstrated good engineering 
practices to assure test accuracy. Computer control of quality assurance 
checks and quality control charts shall be used whenever possible. 
Exceptions to the procedures and the frequency of the checks described 
in appendix A of this subpart may be approved by the Administrator based 
on a demonstration of comparable performance.
    (e) Document security. Measures shall be taken to maintain the 
security of all documents by which compliance with the inspection 
requirement is established including, but not limited to inspection 
certificates, waiver certificates, license plates, license tabs, and 
stickers. This section shall in no way require the use of paper 
documents but shall apply if they are used by the program for these 
purposes.
    (1) Compliance documents shall be counterfeit resistant. Such 
measures as the use of special fonts, water marks, ultra-violet inks, 
encoded magnetic strips, unique bar-coded identifiers, and difficult to 
acquire materials may be used to accomplish this requirement.

[[Page 323]]

    (2) All inspection certificates, waiver certificates, and stickers 
shall be printed with a unique serial number and an official program 
seal.
    (3) Measures shall be taken to ensure that compliance documents 
cannot be stolen or removed without being damaged.
    (f) SIP requirements. The SIP shall include a description of quality 
control and record keeping procedures. The SIP shall include the 
procedure manual, rule, ordinance or law describing and establishing the 
quality control procedures and requirements.

[57 FR 52987, Nov. 5, 1992, as amended at 58 FR 59367, Nov. 9, 1993; 65 
FR 45533, July 24, 2000]



Sec. 51.360  Waivers and compliance via diagnostic inspection.

    The program may allow the issuance of a waiver, which is a form of 
compliance with the program requirements that allows a motorist to 
comply without meeting the applicable test standards, as long as the 
prescribed criteria described below are met.
    (a) Waiver issuance criteria. The waiver criteria shall include the 
following at a minimum.
    (1) Waivers shall be issued only after a vehicle has failed a retest 
performed after all qualifying repairs have been completed. Qualifying 
repairs include repairs of the emission control components, listed in 
paragraph (a)(5) of this section, performed within 60 days of the test 
date.
    (2) Any available warranty coverage shall be used to obtain needed 
repairs before expenditures can be counted towards the cost limits in 
paragraphs (a)(5) and (a)(6) of this section. The operator of a vehicle 
within the statutory age and mileage coverage under section 207(b) of 
the Clean Air Act shall present a written denial of warranty coverage 
from the manufacturer or authorized dealer for this provision to be 
waived for approved tests applicable to the vehicle.
    (3) Waivers shall not be issued to vehicles for tampering-related 
repairs. The cost of tampering-related repairs shall not be applicable 
to the minimum expenditure in paragraphs (a)(5) and (a)(6) of this 
section. States may issue exemptions for tampering-related repairs if it 
can be verified that the part in question or one similar to it is no 
longer available for sale.
    (4) Repairs shall be appropriate to the cause of the test failure, 
and a visual check shall be made to determine if repairs were actually 
made if, given the nature of the repair, it can be visually confirmed. 
Receipts shall be submitted for review to further verify that qualifying 
repairs were performed.
    (5) General repairs shall be performed by a recognized repair 
technician (i.e., one professionally engaged in vehicle repair, employed 
by a going concern whose purpose is vehicle repair, or possessing 
nationally recognized certification for emission-related diagnosis and 
repair) in order to qualify for a waiver. I/M programs may allow the 
cost of parts (not labor) utilized by non-technicians (e.g., owners) to 
apply toward the waiver limit. The waiver would apply to the cost of 
parts for the repair or replacement of the following list of emission 
control components: oxygen sensor, catalytic converter, thermal reactor, 
EGR valve, fuel filler cap, evaporative canister, PCV valve, air pump, 
distributor, ignition wires, coil, and spark plugs. The cost of any 
hoses, gaskets, belts, clamps, brackets or other accessories directly 
associated with these components may also be applied to the waiver 
limit.
    (6) In basic programs, a minimum of $75 for pre-81 vehicles and $200 
for 1981 and newer vehicles shall be spent in order to qualify for a 
waiver. These model year cutoffs and the associated dollar limits shall 
be in full effect by January 1, 1998, or coincident with program start-
up, whichever is later. Prior to January 1, 1998, States may adopt any 
minimum expenditure commensurate with the waiver rate committed to for 
the purposes of modeling compliance with the basic I/M performance 
standard.
    (7) Beginning on January 1, 1998, enhanced I/M programs shall 
require the motorist to make an expenditure of at least $450 in repairs 
to qualify for a waiver. The I/M program shall provide that the $450 
minimum expenditure shall be adjusted in January of each year by the 
percentage, if any, by which the Consumer Price Index for the preceding 
calendar year differs

[[Page 324]]

from the Consumer Price Index of 1989. Prior to January 1, 1998, States 
may adopt any minimum expenditure commensurate with the waiver rate 
committed to for the purposes of modeling compliance with the relevant 
enhanced I/M performance standard.
    (i) The Consumer Price Index for any calendar year is the average of 
the Consumer Price Index for all-urban consumers published by the 
Department of Labor, as of the close of the 12-month period ending on 
August 31 of each calendar year. A copy of the current Consumer Price 
Index may be obtained from the Emission Planning and Strategies 
Division, U.S. Environmental Protection Agency, 2565 Plymouth Road, Ann 
Arbor, Michigan 48105.
    (ii) The revision of the Consumer Price Index which is most 
consistent with the Consumer Price Index for calendar year 1989 shall be 
used.
    (8) States may establish lower minimum expenditures if a program is 
established to scrap vehicles that do not meet standards after the lower 
expe nditure is made.
    (9) A time extension, not to exceed the period of the inspection 
frequency, may be granted to obtain needed repairs on a vehicle in the 
case of economic hardship when waiver requirements have not been met. 
After having received a time extension, a vehicle must fully pass the 
applicable test standards before becoming eligible for another time 
extension. The extension for a vehicle shall be tracked and reported by 
the program.
    (b) Compliance via diagnostic inspection. Vehicles subject to a 
transient IM240 emission test at the cutpoints established in Sec. Sec. 
51.351 (f)(7) and (g)(7) of this subpart may be issued a certificate of 
compliance without meeting the prescribed emission cutpoints, if, after 
failing a retest on emissions, a complete, documented physical and 
functional diagnosis and inspection performed by the I/M agency or a 
contractor to the I/M agency show that no additional emission-related 
repairs are needed. Any such exemption policy and procedures shall be 
subject to approval by the Administrator.
    (c) Quality control of waiver issuance. (1) Enhanced programs shall 
control waiver issuance and processing by establishing a system of 
agency-issued waivers. The State may delegate this authority to a single 
contractor but inspectors in stations and lanes shall not issue waivers. 
Basic programs may permit inspector-issued waivers as long as quality 
assurance efforts include a comprehensive review of waiver issuance.
    (2) The program shall include methods of informing vehicle owners or 
lessors of potential warranty coverage, and ways to obtain warranty 
repairs.
    (3) The program shall insure that repair receipts are authentic and 
cannot be revised or reused.
    (4) The program shall insure that waivers are only valid for one 
test cycle.
    (5) The program shall track, manage, and account for time extensions 
or exemptions so that owners or lessors cannot receive or retain a 
waiver improperly.
    (d) SIP requirements. (1) The SIP shall include a maximum waiver 
rate expressed as a percentage of initially failed vehicles. This waiver 
rate shall be used for estimating emission reduction benefits in the 
modeling analysis.
    (2) The State shall take corrective action if the waiver rate 
exceeds that committed to in the SIP or revise the SIP and the emission 
reductions claimed.
    (3) The SIP shall describe the waiver criteria and procedures, 
including cost limits, quality assurance methods and measures, and 
administration.
    (4) The SIP shall include the necessary legal authority, ordinance, 
or rules to issue waivers, set and adjust cost limits as required in 
paragraph (a)(5) of this section, and carry out any other functions 
necessary to administer the waiver system, including enforcement of the 
waiver provisions.

[57 FR 52987, Nov. 5, 1992, as amended at 58 FR 59367, Nov. 9, 1993; 60 
FR 48036, Sept. 18, 1995; 71 FR 17711, Apr. 7, 2006]



Sec. 51.361  Motorist compliance enforcement.

    Compliance shall be ensured through the denial of motor vehicle 
registration in enhanced I/M programs unless an exception for use of an 
existing alternative is approved. An enhanced I/M area may use an 
existing alternative if

[[Page 325]]

it demonstrates that the alternative has been more effective than 
registration denial. An enforcement mechanism may be considered an 
``existing alternative'' only in States that, for some area in the 
State, had an I/M program with that mechanism in operation prior to 
passage of the 1990 Amendments to the Act. A basic I/M area may use an 
alternative enforcement mechanism if it demonstrates that the 
alternative will be as effective as registration denial. Two other types 
of enforcement programs may qualify for enhanced I/M programs if 
demonstrated to have been more effective than enforcement of the 
registration requirement in the past: Sticker-based enforcement programs 
and computer-matching programs. States that did not adopt an I/M program 
for any area of the State before November 15, 1990, may not use an 
enforcement alternative in connection with an enhanced I/M program 
required to be adopted after that date.
    (a) Registration denial. Registration denial enforcement is defined 
as rejecting an application for initial registration or reregistration 
of a used vehicle (i.e., a vehicle being registered after the initial 
retail sale and associated registration) unless the vehicle has complied 
with the I/M requirement prior to granting the application. Pursuant to 
section 207(g)(3) of the Act, nothing in this subpart shall be construed 
to require that new vehicles shall receive emission testing prior to 
initial retail sale. In designing its enforcement program, the State 
shall:
    (1) Provide an external, readily visible means of determining 
vehicle compliance with the registration requirement to facilitate 
enforcement of the program;
    (2) Adopt a schedule of testing (either annual or biennial) that 
clearly determines when a vehicle shall comply prior to registration;
    (3) Design a testing certification mechanism (either paper-based or 
electronic) that shall be used for registration purposes and clearly 
indicates whether the certification is valid for purposes of 
registration, including:
    (i) Expiration date of the certificate;
    (ii) Unambiguous vehicle identification information; and
    (iii) Whether the vehicle passed or received a waiver;
    (4) Routinely issue citations to motorists with expired or missing 
license plates, with either no registration or an expired registration, 
and with no license plate decals or expired decals, and provide for 
enforcement officials other than police to issue citations (e.g., 
parking meter attendants) to parked vehicles in noncompliance;
    (5) Structure the penalty system to deter non-compliance with the 
registration requirement through the use of mandatory minimum fines 
(meaning civil, monetary penalties, in this subpart) constituting a 
meaningful deterrent and through a requirement that compliance be 
demonstrated before a case can be closed;
    (6) Ensure that evidence of testing is available and checked for 
validity at the time of a new registration of a used vehicle or 
registration renewal;
    (7) Prevent owners or lessors from avoiding testing through 
manipulation of the title or registration system; title transfers may 
re-start the clock on the inspection cycle only if proof of current 
compliance is required at title transfer;
    (8) Prevent the fraudulent initial classification or 
reclassification of a vehicle from subject to non-subject or exempt by 
requiring proof of address changes prior to registration record 
modification, and documentation from the testing program (or delegate) 
certifying based on a physical inspection that the vehicle is exempt;
    (9) Limit and track the use of time extensions of the registration 
requirement to prevent repeated extensions;
    (10) Provide for meaningful penalties for cases of registration 
fraud;
    (11) Limit and track exemptions to prevent abuse of the exemption 
policy for vehicles claimed to be out-of-state; and
    (12) Encourage enforcement of vehicle registration transfer 
requirements when vehicle owners move into the I/M area by coordinating 
with local and State enforcement agencies and structuring other 
activities (e.g., drivers license issuance) to effect registration 
transfers.

[[Page 326]]

    (b) Alternative enforcement mechanisms--(1) General requirements. 
The program shall demonstrate that a non-registration-based enforcement 
program is currently more effective than registration-denial enforcement 
in enhanced I/M programs or, prospectively, as effective as registration 
denial in basic programs. The following general requirements shall 
apply:
    (i) For enhanced I/M programs, the area in question shall have had 
an operating I/M program using the alternative mechanism prior to 
enactment of the Clean Air Act Amendments of 1990. While modifications 
to improve compliance may be made to the program that was in effect at 
the time of enactment, the expected change in effectiveness cannot be 
considered in determining acceptability;
    (ii) The State shall assess the alternative program's effectiveness, 
as well as the current effectiveness of the registration system, 
including the following:
    (A) Determine the number and percentage of vehicles subject to the 
I/M program that were in compliance with the program over the course of 
at least one test cycle; and
    (B) Determine the number and fraction of the same group of vehicles 
as in paragraph (b)(1)(ii)(A) of this section that were in compliance 
with the registration requirement over the same period. Late 
registration shall not be considered non-compliance for the purposes of 
this determination. The precise definition of late registration versus a 
non-complying vehicle shall be explained and justified in the SIP;
    (iii) An alternative mechanism shall be considered more effective if 
the fraction of vehicles complying with the existing program, as 
determined according to the requirements of this section, is greater 
than the fraction of vehicles complying with the registration 
requirement. An alternative mechanism is as effective if the fraction 
complying with the program is at least equal to the fraction complying 
with the registration requirement.
    (2) Sticker-based enforcement. In addition to the general 
requirements, a sticker-based enforcement program shall demonstrate that 
the enforcement mechanism will swiftly and effectively prevent operation 
of subject vehicles that fail to comply. Such demonstration shall 
include the following:
    (i) An assessment of the current extent of the following forms of 
non-compliance and demonstration that mechanisms exist to keep such non-
compliance within acceptable limits:
    (A) Use of stolen, counterfeit, or fraudulently obtained stickers;
    (B) In States with safety inspections, the use of ``Safety 
Inspection Only'' stickers on vehicles that should be subject to the I/M 
requirement as well; and
    (C) Operation of vehicles with expired stickers, including a 
stratification of non-compliance by length of noncompliance and model 
year.
    (ii) The program as currently implemented or as proposed to be 
improved shall also:
    (A) Require an easily observed external identifier such as the 
county name on the license plate, an obviously unique license plate tab, 
or other means that shows whether or not a vehicle is subject to the I/M 
requirement;
    (B) Require an easily observed external identifier, such as a 
windshield sticker or license plate tab that shows whether a subject 
vehicle is in compliance with the inspection requirement;
    (C) Impose monetary fines at least as great as the estimated cost of 
compliance with I/M requirements (e.g., test fee plus minimum waiver 
expenditure) for the absence of such identifiers;
    (D) Require that such identifiers be of a quality that makes them 
difficult to counterfeit, difficult to remove without destroying once 
installed, and durable enough to last until the next inspection without 
fading, peeling, or other deterioration;
    (E) Perform surveys in a variety of locations and at different times 
for the presence of the required identifiers such that at least 10% of 
the vehicles or 10,000 vehicles (whichever is less) in the subject 
vehicle population are sampled each year;
    (F) Track missing identifiers for all inspections performed at each 
station, with stations being held accountable for all such identifiers 
they are issued; and
    (G) Assess and collect significant fines for each identifier that is 
unaccounted for by a station.

[[Page 327]]

    (3) Computer matching. In addition to the general requirements, 
computer-matching programs shall demonstrate that the enforcement 
mechanism will swiftly and effectively prevent operation of subject 
vehicles that fail to comply. Such demonstration shall:
    (i) Require an expeditious system that results in at least 90% of 
the subject vehicles in compliance within 4 months of the compliance 
deadline;
    (ii) Require that subject vehicles be given compliance deadlines 
based on the regularly scheduled test date, not the date of previous 
compliance;
    (iii) Require that motorists pay monetary fines at least as great as 
the estimated cost of compliance with I/M requirements (e.g., test fee 
plus minimum waiver expenditure) for the continued operation of a 
noncomplying vehicle beyond 4 months of the deadline;
    (iv) Require that continued non-compliance will eventually result in 
preventing operation of the non-complying vehicle (no later than the 
date of the next test cycle) through, at a minimum, suspension of 
vehicle registration and subsequent denial of reregistration;
    (v) Demonstrate that the computer system currently in use is 
adequate to store and manipulate the I/M vehicle database, generate 
computerized notices, and provide regular backup to said system while 
maintaining auxiliary storage devices to insure ongoing operation of the 
system and prevent data losses;
    (vi) Track each vehicle through the steps taken to ensure 
compliance, including:
    (A) The compliance deadline;
    (B) The date of initial notification;
    (C) The dates warning letters are sent to non-complying vehicle 
owners;
    (D) The dates notices of violation or other penalty notices are 
sent; and
    (E) The dates and outcomes of other steps in the process, including 
the final compliance date;
    (vii) Compile and report monthly summaries including statistics on 
the percentage of vehicles at each stage in the enforcement process; and
    (viii) Track the number and percentage of vehicles initially 
identified as requiring testing but which are never tested as a result 
of being junked, sold to a motorist in a non-I/M program area, or for 
some other reason.
    (c) SIP requirements. (1) The SIP shall provide information 
concerning the enforcement process, including:
    (i) A description of the existing compliance mechanism if it is to 
be used in the future and the demonstration that it is as effective or 
more effective than registration-denial enforcement;
    (ii) An identification of the agencies responsible for performing 
each of the applicable activities in this section;
    (iii) A description of and accounting for all classes of exempt 
vehicles; and
    (iv) A description of the plan for testing fleet vehicles, rental 
car fleets, leased vehicles, and any other subject vehicles, e.g., those 
operated in (but not necessarily registered in) the program area.
    (2) The SIP shall include a determination of the current compliance 
rate based on a study of the system that includes an estimate of 
compliance losses due to loopholes, counterfeiting, and unregistered 
vehicles. Estimates of the effect of closing such loopholes and 
otherwise improving the enforcement mechanism shall be supported with 
detailed analyses.
    (3) The SIP shall include the legal authority to implement and 
enforce the program.
    (4) The SIP shall include a commitment to an enforcement level to be 
used for modeling purposes and to be maintained, at a minimum, in 
practice.

[57 FR 52987, Nov. 5, 1992, as amended at 61 FR 49682, Sept. 23, 1996]



Sec. 51.362  Motorist compliance enforcement program oversight.

    The enforcement program shall be audited regularly and shall follow 
effective program management practices, including adjustments to improve 
operation when necessary.
    (a) Quality assurance and quality control. A quality assurance 
program shall be implemented to insure effective overall performance of 
the enforcement system. Quality control procedures are required to 
instruct individuals in the enforcement process regarding how to 
properly conduct their activities. At a minimum, the quality control and 
quality assurance program shall include:

[[Page 328]]

    (1) Verification of exempt vehicle status by inspecting and 
confirming such vehicles by the program or its delegate;
    (2) Facilitation of accurate critical test data and vehicle 
identifier collection through the use of automatic data capture systems 
such as bar-code scanners or optical character readers, or through 
redundant data entry (where applicable);
    (3) Maintenance of an audit trail to allow for the assessment of 
enforcement effectiveness;
    (4) Establishment of written procedures for personnel directly 
engaged in I/M enforcement activities;
    (5) Establishment of written procedures for personnel engaged in I/M 
document handling and processing, such as registration clerks or 
personnel involved in sticker dispensing and waiver processing, as well 
as written procedures for the auditing of their performance;
    (6) Follow-up validity checks on out-of-area or exemption-triggering 
registration changes;
    (7) Analysis of registration-change applications to target potential 
violators;
    (8) A determination of enforcement program effectiveness through 
periodic audits of test records and program compliance documentation;
    (9) Enforcement procedures for disciplining, retraining, or removing 
enforcement personnel who deviate from established requirements, or in 
the case of non-government entities that process registrations, for 
defranchising, revoking or otherwise discontinuing the activity of the 
entity issuing registrations; and
    (10) The prevention of fraudulent procurement or use of inspection 
documents by controlling and tracking document distribution and 
handling, and making stations financially liable for missing or 
unaccounted for documents by assessing monetary fines reflecting the 
``street value'' of these documents (i.e., the test fee plus the minimum 
waiver expenditure).
    (b) Information management. In establishing an information base to 
be used in characterizing, evaluating, and enforcing the program, the 
State shall:
    (1) Determine the subject vehicle population;
    (2) Permit EPA audits of the enforcement process;
    (3) Assure the accuracy of registration and other program document 
files;
    (4) Maintain and ensure the accuracy of the testing database through 
periodic internal and/or third-party review;
    (5) Compare the testing database to the registration database to 
determine program effectiveness, establish compliance rates, and to 
trigger potential enforcement action against non-complying motorists; 
and
    (6) Sample the fleet as a determination of compliance through 
parking lot surveys, road-side pull-overs, or other in-use vehicle 
measurements.
    (c) SIP requirements. The SIP shall include a description of 
enforcement program oversight and information management activities.

[57 FR 52987, Nov. 5, 1992, as amended at 65 FR 45534, July 24, 2000]



Sec. 51.363  Quality assurance.

    An ongoing quality assurance program shall be implemented to 
discover, correct and prevent fraud, waste, and abuse and to determine 
whether procedures are being followed, are adequate, whether equipment 
is measuring accurately, and whether other problems might exist which 
would impede program performance. The quality assurance and quality 
control procedures shall be periodically evaluated to assess their 
effectiveness and relevance in achieving program goals.
    (a) Performance audits. Performance audits shall be conducted on a 
regular basis to determine whether inspectors are correctly performing 
all tests and other required functions. Performance audits shall be of 
two types: overt and covert, and shall include:
    (1) Performance audits based upon written procedures and results 
shall be reported using either electronic or written forms to be 
retained in the inspector and station history files, with sufficient 
detail to support either an administrative or civil hearing;
    (2) Performance audits in addition to regularly programmed audits 
for stations employing inspectors suspected of violating regulations as 
a result of

[[Page 329]]

audits, data analysis, or consumer complaints;
    (3) Overt performance audits shall be performed at least twice per 
year for each lane or test bay and shall include:
    (i) A check for the observance of appropriate document security;
    (ii) A check to see that required record keeping practices are being 
followed;
    (iii) A check for licenses or certificates and other required 
display information; and
    (iv) Observation and written evaluation of each inspector's ability 
to properly perform an inspection;
    (4) Covert performance audits shall include:
    (i) Remote visual observation of inspector performance, which may 
include the use of aids such as binoculars or video cameras, at least 
once per year per inspector in high-volume stations (i.e., those 
performing more than 4000 tests per year);
    (ii) Site visits at least once per year per number of inspectors 
using covert vehicles set to fail (this requirement sets a minimum level 
of activity, not a requirement that each inspector be involved in a 
covert audit);
    (iii) For stations that conduct both testing and repairs, at least 
one covert vehicle visit per station per year including the purchase of 
repairs and subsequent retesting if the vehicle is initially failed for 
tailpipe emissions (this activity may be accomplished in conjunction 
with paragraph (a)(4)(ii) of this section but must involve each station 
at least once per year);
    (iv) Documentation of the audit, including vehicle condition and 
preparation, sufficient for building a legal case and establishing a 
performance record;
    (v) Covert vehicles covering the range of vehicle technology groups 
(e.g., carbureted and fuel-injected vehicles) included in the program, 
including a full range of introduced malfunctions covering the emission 
test, the evaporative system tests, and emission control component 
checks (as applicable);
    (vi) Sufficient numbers of covert vehicles and auditors to allow for 
frequent rotation of both to prevent detection by station personnel; and
    (vii) Where applicable, access to on-line inspection databases by 
State personnel to permit the creation and maintenance of covert vehicle 
records.
    (b) Record audits. Station and inspector records shall be reviewed 
or screened at least monthly to assess station performance and identify 
problems that may indicate potential fraud or incompetence. Such review 
shall include:
    (1) Automated record analysis to identify statistical 
inconsistencies, unusual patterns, and other discrepancies;
    (2) Visits to inspection stations to review records not already 
covered in the electronic analysis (if any); and
    (3) Comprehensive accounting for all official forms that can be used 
to demonstrate compliance with the program.
    (c) Equipment audits. During overt site visits, auditors shall 
conduct quality control evaluations of the required test equipment, 
including (where applicable):
    (1) A gas audit using gases of known concentrations at least as 
accurate as those required for regular equipment quality control and 
comparing these concentrations to actual readings;
    (2) A check for tampering, worn instrumentation, blocked filters, 
and other conditions that would impede accurate sampling;
    (3) A check for critical flow in critical flow CVS units;
    (4) A check of the Constant Volume Sampler flow calibration;
    (5) A check for the optimization of the Flame Ionization Detection 
fuel-air ratio using methane;
    (6) A leak check;
    (7) A check to determine that station gas bottles used for 
calibration purposes are properly labelled and within the relevant 
tolerances;
    (8) Functional dynamometer checks addressing coast-down, roll speed 
and roll distance, inertia weight selection, and power absorption;
    (9) A check of the system's ability to accurately detect background 
pollutant concentrations;
    (10) A check of the pressure monitoring devices used to perform the 
evaporative canister pressure test(s); and

[[Page 330]]

    (11) A check of the purge flow metering system.
    (d) Auditor training and proficiency. (1) Auditors shall be formally 
trained and knowledgeable in:
    (i) The use of test equipment and/or procedures;
    (ii) Program rules and regulations;
    (iii) The basics of air pollution control;
    (iv) Basic principles of motor vehicle engine repair, related to 
emission performance;
    (v) Emission control systems;
    (vi) Evidence gathering;
    (vii) State administrative procedures laws;
    (viii) Quality assurance practices; and
    (ix) Covert audit procedures.
    (2) Auditors shall themselves be audited at least once annually.
    (3) The training and knowledge requirements in paragraph (d)(1) of 
this section may be waived for temporary auditors engaged solely for the 
purpose of conducting covert vehicle runs.
    (e) SIP requirements. The SIP shall include a description of the 
quality assurance program, and written procedures manuals covering both 
overt and covert performance audits, record audits, and equipment 
audits. This requirement does not include materials or discussion of 
details of enforcement strategies that would ultimately hamper the 
enforcement process.

[57 FR 52987, Nov. 5, 1992, as amended at 65 FR 45534, July 24, 2000]



Sec. 51.364  Enforcement against contractors, stations and inspectors.

    Enforcement against licensed stations or contractors, and inspectors 
shall include swift, sure, effective, and consistent penalties for 
violation of program requirements.
    (a) Imposition of penalties. A penalty schedule shall be developed 
that establishes minimum penalties for violations of program rules and 
procedures.
    (1) The schedule shall categorize and list violations and the 
minimum penalties to be imposed for first, second, and subsequent 
violations and for multiple violation of different requirements. In the 
case of contracted systems, the State may use compensation retainage in 
lieu of penalties.
    (2) Substantial penalties or retainage shall be imposed on the first 
offense for violations that directly affect emission reduction benefits. 
At a minimum, in test-and-repair programs inspector and station license 
suspension shall be imposed for at least 6 months whenever a vehicle is 
intentionally improperly passed for any required portion of the test. In 
test-only programs, inspectors shall be removed from inspector duty for 
at least 6 months (or a retainage penalty equivalent to the inspector's 
salary for that period shall be imposed).
    (3) All findings of serious violations of rules or procedural 
requirements shall result in mandatory fines or retainage. In the case 
of gross neglect, a first offense shall result in a fine or retainage of 
no less than $100 or 5 times the inspection fee, whichever is greater, 
for the contractor or the licensed station, and the inspector if 
involved.
    (4) Any finding of inspector incompetence shall result in mandatory 
training before inspection privileges are restored.
    (5) License or certificate suspension or revocation shall mean the 
individual is barred from direct or indirect involvement in any 
inspection operation during the term of the suspension or revocation.
    (b) Legal authority. (1) The quality assurance officer shall have 
the authority to temporarily suspend station and inspector licenses or 
certificates (after approval of a superior) immediately upon finding a 
violation or equipment failure that directly affects emission reduction 
benefits, pending a hearing when requested. In the case of immediate 
suspension, a hearing shall be held within fourteen calendar days of a 
written request by the station licensee or the inspector. Failure to 
hold a hearing within 14 days when requested shall cause the suspension 
to lapse. In the event that a State's constitution precludes such a 
temporary license suspension, the enforcement system shall be designed 
with adequate resources and mechanisms to hold a hearing to suspend or 
revoke the station or inspector license within three station business 
days of the finding.
    (2) The oversight agency shall have the authority to impose 
penalties

[[Page 331]]

against the licensed station or contractor, as well as the inspector, 
even if the licensee or contractor had no direct knowledge of the 
violation but was found to be careless in oversight of inspectors or has 
a history of violations. Contractors and licensees shall be held fully 
responsible for inspector performance in the course of duty.
    (c) Recordkeeping. The oversight agency shall maintain records of 
all warnings, civil fines, suspensions, revocations, and violations and 
shall compile statistics on violations and penalties on an annual basis.
    (d) SIP requirements. (1) The SIP shall include the penalty schedule 
and the legal authority for establishing and imposing penalties, civil 
fines, license suspension, and revocations.
    (2) In the case of State constitutional impediments to immediate 
suspension authority, the State Attorney General shall furnish an 
official opinion for the SIP explaining the constitutional impediment as 
well as relevant case law.
    (3) The SIP shall describe the administrative and judicial 
procedures and responsibilities relevant to the enforcement process, 
including which agencies, courts, and jurisdictions are involved; who 
will prosecute and adjudicate cases; and other aspects of the 
enforcement of the program requirements, the resources to be allocated 
to this function, and the source of those funds. In States without 
immediate suspension authority, the SIP shall demonstrate that 
sufficient resources, personnel, and systems are in place to meet the 
three day case management requirement for violations that directly 
affect emission reductions.
    (e) Alternative quality assurance procedures or frequencies that 
achieve equivalent or better results may be approved by the 
Administrator. Statistical process control shall be used whenever 
possible to demonstrate the efficacy of alternatives.
    (f) Areas that qualify for and choose to implement an OTR low 
enhanced I/M program, as established in Sec. 51.351(h), and that claim 
in their SIP less emission reduction credit than the basic performance 
standard for one or more pollutants, are not required to meet the 
oversight specifications of this section.

[57 FR 52987, Nov. 5, 1992, as amended at 61 FR 39037, July 25, 1996]



Sec. 51.365  Data collection.

    Accurate data collection is essential to the management, evaluation, 
and enforcement of an I/M program. The program shall gather test data on 
individual vehicles, as well as quality control data on test equipment 
(with the exception of test procedures for which either no testing 
equipment is required or those test procedures relying upon a vehicle's 
OBD system).
    (a) Test data. The goal of gathering test data is to unambiguously 
link specific test results to a specific vehicle, I/M program 
registrant, test site, and inspector, and to determine whether or not 
the correct testing parameters were observed for the specific vehicle in 
question. In turn, these data can be used to distinguish complying and 
noncomplying vehicles as a result of analyzing the data collected and 
comparing it to the registration database, to screen inspection stations 
and inspectors for investigation as to possible irregularities, and to 
help establish the overall effectiveness of the program. At a minimum, 
the program shall collect the following with respect to each test 
conducted:
    (1) Test record number;
    (2) Inspection station and inspector numbers;
    (3) Test system number (where applicable);
    (4) Date of the test;
    (5) Emission test start time and the time final emission scores are 
determined;
    (6) Vehicle Identification Number;
    (7) License plate number;
    (8) Test certificate number;
    (9) Gross Vehicle Weight Rating (GVWR);
    (10) Vehicle model year, make, and type;
    (11) Number of cylinders or engine displacement;
    (12) Transmission type;
    (13) Odometer reading;
    (14) Category of test performed (i.e., initial test, first retest, 
or subsequent retest);

[[Page 332]]

    (15) Fuel type of the vehicle (i.e., gas, diesel, or other fuel);
    (16) Type of vehicle preconditioning performed (if any);
    (17) Emission test sequence(s) used;
    (18) Hydrocarbon emission scores and standards for each applicable 
test mode;
    (19) Carbon monoxide emission scores and standards for each 
applicable test mode;
    (20) Carbon dioxide emission scores (CO+CO2) and 
standards for each applicable test mode;
    (21) Nitrogen oxides emission scores and standards for each 
applicable test mode;
    (22) Results (Pass/Fail/Not Applicable) of the applicable visual 
inspections for the catalytic converter, air system, gas cap, 
evaporative system, positive crankcase ventilation (PCV) valve, fuel 
inlet restrictor, and any other visual inspection for which emission 
reduction credit is claimed;
    (23) Results of the evaporative system pressure test(s) expressed as 
a pass or fail;
    (24) Results of the evaporative system purge test expressed as a 
pass or fail along with the total purge flow in liters achieved during 
the test (where applicable); and
    (25) Results of the on-board diagnostic check expressed as a pass or 
fail along with the diagnostic trouble codes revealed (where 
applicable).
    (b) Quality control data. At a minimum, the program shall gather and 
report the results of the quality control checks required under Sec. 
51.359 of this subpart, identifying each check by station number, system 
number, date, and start time. The data report shall also contain the 
concentration values of the calibration gases used to perform the gas 
characterization portion of the quality control checks (where 
applicable).

[ 57 FR 52987, Nov. 5, 1992, as amended at 61 FR 40945, Aug. 6, 1996; 65 
FR 45534, July 24, 2000]



Sec. 51.366  Data analysis and reporting.

    Data analysis and reporting are required to allow for monitoring and 
evaluation of the program by program management and EPA, and shall 
provide information regarding the types of program activities performed 
and their final outcomes, including summary statistics and effectiveness 
evaluations of the enforcement mechanism, the quality assurance system, 
the quality control program, and the testing element. Initial submission 
of the following annual reports shall commence within 18 months of 
initial implementation of the program as required by Sec. 51.373 of 
this subpart. The biennial report shall commence within 30 months of 
initial implementation of the program as required by Sec. 51.373 of 
this subpart.
    (a) Test data report. The program shall submit to EPA by July of 
each year a report providing basic statistics on the testing program for 
January through December of the previous year, including:
    (1) The number of vehicles tested by model year and vehicle type;
    (2) By model year and vehicle type, the number and percentage of 
vehicles:
    (i) Failing initially, per test type;
    (ii) Failing the first retest per test type;
    (iii) Passing the first retest per test type;
    (iv) Initially failed vehicles passing the second or subsequent 
retest per test type;
    (v) Initially failed vehicles receiving a waiver; and
    (vi) Vehicles with no known final outcome (regardless of reason).
    (vii)-(x) [Reserved]
    (xi) Passing the on-board diagnostic check;
    (xii) Failing the on-board diagnostic check;
    (xiii) Failing the on-board diagnostic check and passing the 
tailpipe test (if applicable);
    (xiv) Failing the on-board diagnostic check and failing the tailpipe 
test (if applicable);
    (xv) Passing the on-board diagnostic check and failing the I/M gas 
cap evaporative system test (if applicable);
    (xvi) Failing the on-board diagnostic check and passing the I/M gas 
cap evaporative system test (if applicable);
    (xvii) Passing both the on-board diagnostic check and I/M gas cap 
evaporative system test (if applicable);

[[Page 333]]

    (xviii) Failing both the on-board diagnostic check and I/M gas cap 
evaporative system test (if applicable);
    (xix) MIL is commanded on and no codes are stored;
    (xx) MIL is not commanded on and codes are stored;
    (xxi) MIL is commanded on and codes are stored;
    (xxii) MIL is not commanded on and codes are not stored;
    (xxiii) Readiness status indicates that the evaluation is not 
complete for any module supported by on-board diagnostic systems;
    (3) The initial test volume by model year and test station;
    (4) The initial test failure rate by model year and test station; 
and
    (5) The average increase or decrease in tailpipe emission levels for 
HC, CO, and NOX (if applicable) after repairs by model year 
and vehicle type for vehicles receiving a mass emissions test.
    (b) Quality assurance report. The program shall submit to EPA by 
July of each year a report providing basic statistics on the quality 
assurance program for January through December of the previous year, 
including:
    (1) The number of inspection stations and lanes:
    (i) Operating throughout the year; and
    (ii) Operating for only part of the year;
    (2) The number of inspection stations and lanes operating throughout 
the year:
    (i) Receiving overt performance audits in the year;
    (ii) Not receiving overt performance audits in the year;
    (iii) Receiving covert performance audits in the year;
    (iv) Not receiving covert performance audits in the year; and
    (v) That have been shut down as a result of overt performance 
audits;
    (3) The number of covert audits:
    (i) Conducted with the vehicle set to fail per test type;
    (ii) Conducted with the vehicle set to fail any combination of two 
or more test types;
    (iii) Resulting in a false pass per test type;
    (iv) Resulting in a false pass for any combination of two or more 
test types;
    (v)-(viii) [Reserved]
    (4) The number of inspectors and stations:
    (i) That were suspended, fired, or otherwise prohibited from testing 
as a result of covert audits;
    (ii) That were suspended, fired, or otherwise prohibited from 
testing for other causes; and
    (iii) That received fines;
    (5) The number of inspectors licensed or certified to conduct 
testing;
    (6) The number of hearings:
    (i) Held to consider adverse actions against inspectors and 
stations; and
    (ii) Resulting in adverse actions against inspectors and stations;
    (7) The total amount collected in fines from inspectors and stations 
by type of violation;
    (8) The total number of covert vehicles available for undercover 
audits over the year; and
    (9) The number of covert auditors available for undercover audits.
    (c) Quality control report. The program shall submit to EPA by July 
of each year a report providing basic statistics on the quality control 
program for January through December of the previous year, including:
    (1) The number of emission testing sites and lanes in use in the 
program;
    (2) The number of equipment audits by station and lane;
    (3) The number and percentage of stations that have failed equipment 
audits; and
    (4) Number and percentage of stations and lanes shut down as a 
result of equipment audits.
    (d) Enforcement report. (1) All varieties of enforcement programs 
shall, at a minimum, submit to EPA by July of each year a report 
providing basic statistics on the enforcement program for January 
through December of the previous year, including:
    (i) An estimate of the number of vehicles subject to the inspection 
program, including the results of an analysis of the registration data 
base;
    (ii) The percentage of motorist compliance based upon a comparison 
of the number of valid final tests with the number of subject vehicles;
    (iii) The total number of compliance documents issued to inspection 
stations;

[[Page 334]]

    (iv) The number of missing compliance documents;
    (v) The number of time extensions and other exemptions granted to 
motorists; and
    (vi) The number of compliance surveys conducted, number of vehicles 
surveyed in each, and the compliance rates found.
    (2) Registration denial based enforcement programs shall provide the 
following additional information:
    (i) A report of the program's efforts and actions to prevent 
motorists from falsely registering vehicles out of the program area or 
falsely changing fuel type or weight class on the vehicle registration, 
and the results of special studies to investigate the frequency of such 
activity; and
    (ii) The number of registration file audits, number of registrations 
reviewed, and compliance rates found in such audits.
    (3) Computer-matching based enforcement programs shall provide the 
following additional information:
    (i) The number and percentage of subject vehicles that were tested 
by the initial deadline, and by other milestones in the cycle;
    (ii) A report on the program's efforts to detect and enforce against 
motorists falsely changing vehicle classifications to circumvent program 
requirements, and the frequency of this type of activity; and
    (iii) The number of enforcement system audits, and the error rate 
found during those audits.
    (4) Sticker-based enforcement systems shall provide the following 
additional information:
    (i) A report on the program's efforts to prevent, detect, and 
enforce against sticker theft and counterfeiting, and the frequency of 
this type of activity;
    (ii) A report on the program's efforts to detect and enforce against 
motorists falsely changing vehicle classifications to circumvent program 
requirements, and the frequency of this type of activity; and
    (iii) The number of parking lot sticker audits conducted, the number 
of vehicles surveyed in each, and the noncompliance rate found during 
those audits.
    (e) Additional reporting requirements. In addition to the annual 
reports in paragraphs (a) through (d) of this section, programs shall 
submit to EPA by July of every other year, biennial reports addressing:
    (1) Any changes made in program design, funding, personnel levels, 
procedures, regulations, and legal authority, with detailed discussion 
and evaluation of the impact on the program of all such changes; and
    (2) Any weaknesses or problems identified in the program within the 
two-year reporting period, what steps have already been taken to correct 
those problems, the results of those steps, and any future efforts 
planned.
    (f) SIP requirements. The SIP shall describe the types of data to be 
collected.

[ 57 FR 52987, Nov. 5, 1992, as amended at 61 FR 40945, Aug. 6, 1996; 65 
FR 45534, July 24, 2000; 66 FR 18178, Apr. 5, 2001]



Sec. 51.367  Inspector training and licensing or certification.

    All inspectors shall receive formal training and be licensed or 
certified to perform inspections.
    (a) Training. (1) Inspector training shall impart knowledge of the 
following:
    (i) The air pollution problem, its causes and effects;
    (ii) The purpose, function, and goal of the inspection program;
    (iii) Inspection regulations and procedures;
    (iv) Technical details of the test procedures and the rationale for 
their design;
    (v) Emission control device function, configuration, and inspection;
    (vi) Test equipment operation, calibration, and maintenance (with 
the exception of test procedures which either do not require the use of 
special equipment or which rely upon a vehicle's OBD system);
    (vii) Quality control procedures and their purpose;
    (viii) Public relations; and
    (ix) Safety and health issues related to the inspection process.
    (2) If inspector training is not administered by the program, the 
responsible State agency shall monitor and evaluate the training program 
delivery.

[[Page 335]]

    (3) In order to complete the training requirement, a trainee shall 
pass (i.e., a minimum of 80% of correct responses or lower if an 
occupational analysis justifies it) a written test covering all aspects 
of the training. In addition, a hands-on test shall be administered in 
which the trainee demonstrates without assistance the ability to conduct 
a proper inspection and to follow other required procedures. Inability 
to properly conduct all test procedures shall constitute failure of the 
test. The program shall take appropriate steps to insure the security 
and integrity of the testing process.
    (b) Licensing and certification. (1) All inspectors shall be either 
licensed by the program (in the case of test-and-repair systems that do 
not use contracts with stations) or certified by an organization other 
than the employer (in test-only programs and test-and-repair programs 
that require station owners to enter into contracts with the State) in 
order to perform official inspections.
    (2) Completion of inspector training and passing required tests 
shall be a condition of licensing or certification.
    (3) Inspector licenses and certificates shall be valid for no more 
than 2 years, at which point refresher training and testing shall be 
required prior to renewal. Alternative approaches based on more 
comprehensive skill examination and determination of inspector 
competency may be used.
    (4) Licenses or certificates shall not be considered a legal right 
but rather a privilege bestowed by the program conditional upon 
adherence to program requirements.
    (c) SIP requirements. The SIP shall include a description of the 
training program, the written and hands-on tests, and the licensing or 
certification process.

[57 FR 52987, Nov. 5, 1992, as amended at 65 FR 45534, July 24, 2000]



Sec. 51.368  Public information and consumer protection.

    (a) Public awareness. The SIP shall include a plan for informing the 
public on an ongoing basis throughout the life of the I/M program of the 
air quality problem, the requirements of Federal and State law, the role 
of motor vehicles in the air quality problem, the need for and benefits 
of an inspection program, how to maintain a vehicle in a low-emission 
condition, how to find a qualified repair technician, and the 
requirements of the I/M program. Motorists that fail the I/M test in 
enhanced I/M areas shall be offered a list of repair facilities in the 
area and information on the results of repairs performed by repair 
facilities in the area, as described in Sec. 51.369(b)(1) of this 
subpart. Motorists that fail the I/M test shall also be provided with 
information concerning the possible cause(s) for failing the particular 
portions of the test that were failed.
    (b) Consumer protection. The oversight agency shall institute 
procedures and mechanisms to protect the public from fraud and abuse by 
inspectors, mechanics, and others involved in the I/M program. This 
shall include a challenge mechanism by which a vehicle owner can contest 
the results of an inspection. It shall include mechanisms for protecting 
whistle blowers and following up on complaints by the public or others 
involved in the process. It shall include a program to assist owners in 
obtaining warranty covered repairs for eligible vehicles that fail a 
test. The SIP shall include a detailed consumer protection plan.

[57 FR 52987, Nov. 5, 1992, as amended at 65 FR 45534, July 24, 2000]



Sec. 51.369  Improving repair effectiveness.

    Effective repairs are the key to achieving program goals and the 
State shall take steps to ensure the capability exists in the repair 
industry to repair vehicles that fail I/M tests.
    (a) Technical assistance. The oversight agency shall provide the 
repair industry with information and assistance related to vehicle 
inspection diagnosis and repair.
    (1) The agency shall regularly inform repair facilities of changes 
in the inspection program, training course schedules, common problems 
being found with particular engine families, diagnostic tips and the 
like.
    (2) The agency shall provide a hot line service to assist repair 
technicians with specific repair problems, answer technical questions 
that arise in the repair process, and answer questions

[[Page 336]]

related to the legal requirements of State and Federal law with regard 
to emission control device tampering, engine switching, or similar 
issues.
    (b) Performance monitoring. (1) In enhanced I/M program areas, the 
oversight agency shall monitor the performance of individual motor 
vehicle repair facilities, and provide to the public at the time of 
initial failure, a summary of the performance of local repair facilities 
that have repaired vehicles for retest. Performance monitoring shall 
include statistics on the number of vehicles submitted for a retest 
after repair by the repair facility, the percentage passing on first 
retest, the percentage requiring more than one repair/retest trip before 
passing, and the percentage receiving a waiver. Programs may provide 
motorists with alternative statistics that convey similar information on 
the relative ability of repair facilities in providing effective and 
convenient repair, in light of the age and other characteristics of 
vehicles presented for repair at each facility.
    (2) Programs shall provide feedback, including statistical and 
qualitative information to individual repair facilities on a regular 
basis (at least annually) regarding their success in repairing failed 
vehicles.
    (3) A prerequisite for a retest shall be a completed repair form 
that indicates which repairs were performed, as well as any technician 
recommended repairs that were not performed, and identification of the 
facility that performed the repairs.
    (c) Repair technician training. The State shall assess the 
availability of adequate repair technician training in the I/M area and, 
if the types of training described in paragraphs (c)(1) through (4) of 
this section are not currently available, shall insure that training is 
made available to all interested individuals in the community either 
through private or public facilities. This may involve working with 
local community colleges or vocational schools to add curricula to 
existing programs or start new programs or it might involve attracting 
private training providers to offer classes in the area. The training 
available shall include:
    (1) Diagnosis and repair of malfunctions in computer controlled, 
close-loop vehicles;
    (2) The application of emission control theory and diagnostic data 
to the diagnosis and repair of failures on the transient emission test 
and the evaporative system functional checks (where applicable);
    (3) Utilization of diagnostic information on systematic or repeated 
failures observed in the transient emission test and the evaporative 
system functional checks (where applicable); and
    (4) General training on the various subsystems related to engine 
emission control.
    (d) SIP requirements. The SIP shall include a description of the 
technical assistance program to be implemented, a description of the 
procedures and criteria to be used in meeting the performance monitoring 
requirements of this section, and a description of the repair technician 
training resources available in the community.

[57 FR 52987, Nov. 5, 1992, as amended at 65 FR 45535, July 24, 2000]



Sec. 51.370  Compliance with recall notices.

    States shall establish methods to ensure that vehicles subject to 
enhanced I/M and that are included in either a ``Voluntary Emissions 
Recall'' as defined at 40 CFR 85.1902(d), or in a remedial plan 
determination made pursuant to section 207(c) of the Act, receive the 
required repairs. States shall require that owners of recalled vehicles 
have the necessary recall repairs completed, either in order to complete 
an annual or biennial inspection process or to obtain vehicle 
registration renewal. All recalls for which owner notification occurs 
after January 1, 1995 shall be included in the enhanced I/M recall 
requirement.
    (a) General requirements. (1) The State shall have an electronic 
means to identify recalled vehicles based on lists of VINs with 
unresolved recalls made available by EPA, the vehicle manufacturers, or 
a third party supplier approved by the Administrator. The State shall 
update its list of unresolved recalls on a quarterly basis at a minimum.

[[Page 337]]

    (2) The State shall require owners or lessees of vehicles with 
unresolved recalls to show proof of compliance with recall notices in 
order to complete either the inspection or registration cycle.
    (3) Compliance shall be required on the next registration or 
inspection date, allowing a reasonable period to comply, after 
notification of recall was received by the State.
    (b) Enforcement. (1) A vehicle shall either fail inspection or be 
denied vehicle registration if the required recall repairs have not been 
completed.
    (2) In the case of vehicles obtaining recall repairs but remaining 
on the updated list provided in paragraph (a)(1) of this section, the 
State shall have a means of verifying completion of the required 
repairs; electronic records or paper receipts provided by the authorized 
repair facility shall be required. The vehicle inspection or 
registration record shall be modified to include (or be supplemented 
with other VIN-linked records which include) the recall campaign 
number(s) and the date(s) repairs were performed. Documentation 
verifying required repairs shall include the following:
    (i) The VIN, make, and model year of the vehicle; and
    (ii) The recall campaign number and the date repairs were completed.
    (c) Reporting requirements. The State shall submit to EPA, by July 
of each year for the previous calendar year, an annual report providing 
the following information:
    (1) The number of vehicles in the I/M area initially listed as 
having unresolved recalls, segregated by recall campaign number;
    (2) The number of recalled vehicles brought into compliance by 
owners;
    (3) The number of listed vehicles with unresolved recalls that, as 
of the end of the calendar year, were not yet due for inspection or 
registration;
    (4) The number of recalled vehicles still in non-compliance that 
have either failed inspection or been denied registration on the basis 
of non-compliance with recall; and
    (5) The number of recalled vehicles that are otherwise not in 
compliance.
    (d) SIP submittals. The SIP shall describe the procedures used to 
incorporate the vehicle lists provided in paragraph (a)(1) of this 
section into the inspection or registration database, the quality 
control methods used to insure that recall repairs are properly 
documented and tracked, and the method (inspection failure or 
registration denial) used to enforce the recall requirements.



Sec. 51.371  On-road testing.

    On-road testing is defined as testing of vehicles for conditions 
impacting the emission of HC, CO, NOX and/or CO2 emissions on 
any road or roadside in the nonattainment area or the I/M program area. 
On-road testing is required in enhanced I/M areas and is an option for 
basic I/M areas.
    (a) General requirements. (1) On-road testing is to be part of the 
emission testing system, but is to be a complement to testing otherwise 
required.
    (2) On-road testing is not required in every season or on every 
vehicle but shall evaluate the emission performance of 0.5% of the 
subject fleet statewide or 20,000 vehicles, whichever is less, per 
inspection cycle.
    (3) The on-road testing program shall provide information about the 
performance of in-use vehicles, by measuring on-road emissions through 
the use of remote sensing devices or by assessing vehicle emission 
performance through roadside pullovers including tailpipe or evaporative 
emission testing or a check of the onboard diagnostic (OBD) system for 
vehicles so equipped. The program shall collect, analyze and report on-
road testing data.
    (4) Owners of vehicles that have previously been through the normal 
periodic inspection and passed the final retest and found to be high 
emitters shall be notified that the vehicles are required to pass an 
out-of-cycle follow-up inspection; notification may be by mailing in the 
case of remote sensing on-road testing or through immediate notification 
if roadside pullovers are used.
    (b) SIP requirements. (1) The SIP shall include a detailed 
description of the on-road testing program, including the types of 
testing, test limits and criteria, the number of vehicles (the 
percentage of the fleet) to be tested, the number of employees to be 
dedicated to

[[Page 338]]

the on-road testing effort, the methods for collecting, analyzing, 
utilizing, and reporting the results of on-road testing and, the portion 
of the program budget to be dedicated to on-road testing.
    (2) The SIP shall include the legal authority necessary to implement 
the on-road testing program, including the authority to enforce off-
cycle inspection and repair requirements (where applicable).
    (3) Emission reduction credit for on-road testing programs shall be 
granted for a program designed to obtain measurable emission reductions 
over and above those already predicted to be achieved by other aspects 
of the I/M program. Emission reduction credit will only be granted to 
those programs which require out-of-cycle repairs for confirmed high-
emitting vehicles identified under the on-road testing program. The SIP 
shall include technical support for the claimed additional emission 
reductions.

[57 FR 52987, Nov. 5, 1992, as amended at 65 FR 45535, July 24, 2000]



Sec. 51.372  State Implementation Plan submissions.

    (a) SIP submittals. The SIP shall address each of the elements 
covered in this subpart, including, but not limited to:
    (1) A schedule of implementation of the program including interim 
milestones leading to mandatory testing. The milestones shall include, 
at a minimum:
    (i) Passage of enabling statutory or other legal authority;
    (ii) Proposal of draft regulations and promulgation of final 
regulations;
    (iii) Issuance of final specifications and procedures;
    (iv) Issuance of final Request for Proposals (if applicable);
    (v) Licensing or certifications of stations and inspectors;
    (vi) The date mandatory testing will begin for each model year to be 
covered by the program;
    (vii) The date full-stringency cutpoints will take effect;
    (viii) All other relevant dates;
    (2) An analysis of emission level targets for the program using the 
most current EPA mobile source emission model or an alternative approved 
by the Administrator showing that the program meets the performance 
standard described in Sec. 51.351 or Sec. 51.352 of this subpart, as 
applicable;
    (3) A description of the geographic coverage of the program, 
including ZIP codes if the program is not county-wide;
    (4) A detailed discussion of each of the required design elements, 
including provisions for Federal facility compliance;
    (5) Legal authority requiring or allowing implementation of the I/M 
program and providing either broad or specific authority to perform all 
required elements of the program;
    (6) Legal authority for I/M program operation until such time as it 
is no longer necessary (i.e., until a Section 175 maintenance plan 
without an I/M program is approved by EPA);
    (7) Implementing regulations, interagency agreements, and memoranda 
of understanding; and
    (8) Evidence of adequate funding and resources to implement all 
aspects of the program.
    (b) Submittal schedule. The SIP shall be submitted to EPA according 
to the following schedule--
    (1) [Reserved]
    (2) A SIP revision required as a result of designation for a 
National Ambient Air Quality Standard in place prior to implementation 
of the 8-hour ozone standard and including all necessary legal authority 
and the items specified in paragraphs (a)(1) through (a)(8) of this 
section, shall be submitted no later than November 15, 1993. For non-
attainment areas designated and classified under the 8-hour ozone 
standard, a SIP revision including all necessary legal authority and the 
items specified in paragraphs (a)(1) through (a)(8) of this section, 
shall be submitted by May 8, 2007 or 1 year after the effective date of 
designation and classification under the 8-hour ozone National Ambient 
Air Quality Standard, whichever is later.
    (3) [Reserved]
    (c) Redesignation requests. Any nonattainment area that EPA 
determines would otherwise qualify for redesignation from nonattainment 
to attainment shall receive full approval of a State Implementation Plan 
(SIP) submittal under Sections 182(a)(2)(B) or

[[Page 339]]

182(b)(4) if the submittal contains the following elements:
    (1) Legal authority to implement a basic I/M program (or enhanced if 
the State chooses to opt up) as required by this subpart. The 
legislative authority for an I/M program shall allow the adoption of 
implementing regulations without requiring further legislation.
    (2) A request to place the I/M plan (if no I/M program is currently 
in place or if an I/M program has been terminated,) or the I/M upgrade 
(if the existing I/M program is to continue without being upgraded) into 
the contingency measures portion of the maintenance plan upon 
redesignation.
    (3) A contingency measure consisting of a commitment by the Governor 
or the Governor's designee to adopt or consider adopting regulations to 
implement an I/M program to correct a violation of the ozone or CO 
standard or other air quality problem, in accordance with the provisions 
of the maintenance plan.
    (4) A contingency commitment that includes an enforceable schedule 
for adoption and implementation of the I/M program, and appropriate 
milestones. The schedule shall include the date for submission of a SIP 
meeting all of the requirements of this subpart. Schedule milestones 
shall be listed in months from the date EPA notifies the State that it 
is in violation of the ozone or CO standard or any earlier date 
specified in the State plan. Unless the State, in accordance with the 
provisions of the maintenance plan, chooses not to implement I/M, it 
must submit a SIP revision containing an I/M program no more than 18 
months after notification by EPA.
    (d) Basic areas continuing operation of I/M programs as part of 
their maintenance plan without implemented upgrades shall be assumed to 
be 80% as effective as an implemented, upgraded version of the same I/M 
program design, unless a State can demonstrate using operating 
information that the I/M program is more effective than the 80% level.
    (e) SIP submittals to correct violations. SIP submissions required 
pursuant to a violation of the ambient ozone or CO standard (as 
discussed in paragraph (c) of this section) shall address all of the 
requirements of this subpart. The SIP shall demonstrate that performance 
standards in either Sec. 51.351 or Sec. 51.352 shall be met using an 
evaluation date (rounded to the nearest January for carbon monoxide and 
July for hydrocarbons) seven years after the date EPA notifies the State 
that it is in violation of the ozone or CO standard or any earlier date 
specified in the State plan. Emission standards for vehicles subject to 
an IM240 test may be phased in during the program but full standards 
must be in effect for at least one complete test cycle before the end of 
the 5-year period. All other requirements shall take effect within 24 
months of the date EPA notifies the State that it is in violation of the 
ozone or CO standard or any earlier date specified in the State plan. 
The phase-in allowances of Sec. 51.373(c) of this subpart shall not 
apply.

[57 FR 52987, Nov. 5, 1992, as amended at 60 FR 1738, Jan. 5, 1995; 60 
FR 48036, Sept. 18, 1995; 61 FR 40946, Aug. 6, 1996; 61 FR 44119, Aug. 
27, 1996; 71 FR 17711, Apr. 7, 2006]



Sec. 51.373  Implementation deadlines.

    I/M programs shall be implemented as expeditiously as practicable.
    (a) Decentralized basic programs shall be fully implemented by 
January 1, 1994, and centralized basic programs shall be fully 
implemented by July 1, 1994. More implementation time may be approved by 
the Administrator if an enhanced I/M program is implemented.
    (b) For areas newly required to implement basic I/M as a result of 
designation under the 8-hour ozone standard, the required program shall 
be fully implemented no later than 4 years after the effective date of 
designation and classification under the 8-hour ozone standard.
    (c) All requirements related to enhanced I/M programs shall be 
implemented by January 1, 1995, with the following exceptions.
    (1) Areas switching from an existing test-and-repair network to a 
test-only network may phase in the change between January of 1995 and 
January of 1996. Starting in January of 1995 at least 30% of the subject 
vehicles shall participate in the test-only system (in States with 
multiple I/M areas, implementation is not required in every area

[[Page 340]]

by January 1995 as long as statewide, 30% of the subject vehicles are 
involved in testing) and shall be subject to the new test procedures 
(including the evaporative system checks, visual inspections, and 
tailpipe emission tests). By January 1, 1996, all applicable vehicle 
model years and types shall be included in the test-only system. During 
the phase-in period, all requirements of this subpart shall be applied 
to the test-only portion of the program; existing requirements may 
continue to apply for the test-and-repair portion of the program until 
it is phased out by January 1, 1996.
    (2) Areas starting new test-only programs and those with existing 
test-only programs may also phase in the new test procedures between 
January 1, 1995 and January 1, 1996. Other program requirements shall be 
fully implemented by January 1, 1995.
    (d) For areas newly required to implement enhanced I/M as a result 
of designation under the 8-hour ozone standard, the required program 
shall be fully implemented no later than 4 years after the effective 
date of designation and classification under the 8-hour ozone standard.
    (e) [Reserved]
    (f) Areas that choose to implement an enhanced I/M program only 
meeting the requirements of Sec. 51.351(h) shall fully implement the 
program no later than July 1, 1999. The availability and use of this 
late start date does not relieve the area of the obligation to meet the 
requirements of Sec. 51.351(h)(11) by the end of 1999.
    (g) On-Board Diagnostic checks shall be implemented in all basic, 
low enhanced and high enhanced areas as part of the I/M program by 
January 1, 2002. Alternatively, states may elect to phase-in OBD-I/M 
testing for one test cycle by using the OBD-I/M check to screen clean 
vehicles from tailpipe testing and require repair and retest for only 
those vehicles which proceed to fail the tailpipe test. An additional 
alternative is also available to states with regard to the deadline for 
mandatory testing, repair, and retesting of vehicles based upon the OBD-
I/M check. Under this third option, if a state can show good cause (and 
the Administrator takes notice-and-comment action to approve this good 
cause showing), up to an additional 12 months' extension may be granted, 
establishing an alternative start date for such states of no later than 
January 1, 2003. States choosing to make this showing will also have 
available to them the phase-in approach described in this section, with 
the one-cycle time limit to begin coincident with the alternative start 
date established by Administrator approval of the showing, but no later 
than January 1, 2003. The showing of good cause (and its approval or 
disapproval) will be addressed on a case-by-case basis.
    (h) For areas newly required to implement either a basic or enhanced 
I/M program as a result of being designated and classified under the 8-
hour ozone standard, such programs shall begin OBD testing on subject 
OBD-equipped vehicles coincident with program start-up.

[57 FR 52987, Nov. 5, 1992, as amended at 58 FR 59367, Nov. 9, 1993; 61 
FR 39037, July 25, 1996; 61 FR 40946, Aug. 6, 1996; 63 FR 24433, May 4, 
1998; 66 FR 18178, Apr. 5, 2001; 71 FR 17711, Apr. 7, 2006]

   Appendix A to Subpart S of Part 51--Calibrations, Adjustments and 
                             Quality Control

                     (I) Steady-State Test Equipment

    States may opt to use transient emission test equipment for steady-
state tests and follow the quality control requirements in paragraph 
(II) of this appendix instead of the following requirements.
    (a) Equipment shall be calibrated in accordance with the 
manufacturers' instructions.
    (b) Prior to each test--(1) Hydrocarbon hang-up check. Immediately 
prior to each test the analyzer shall automatically perform a 
hydrocarbon hang-up check. If the HC reading, when the probe is sampling 
ambient air, exceeds 20 ppm, the system shall be purged with clean air 
or zero gas. The analyzer shall be inhibited from continuing the test 
until HC levels drop below 20 ppm.
    (2) Automatic zero and span. The analyzer shall conduct an automatic 
zero and span check prior to each test. The span check shall include the 
HC, CO, and CO2 channels, and the NO and O2 channels, if 
present. If zero and/or span drift cause the signal levels to move 
beyond the adjustment range of the analyzer, it shall lock out from 
testing.

[[Page 341]]

    (3) Low flow. The system shall lock out from testing if sample flow 
is below the acceptable level as defined in paragraph (I)(b)(6) of 
appendix D to this subpart.
    (c) Leak check. A system leak check shall be performed within 
twenty-four hours before the test in low volume stations (those 
performing less than the 4,000 inspections per year) and within four 
hours in high-volume stations (4,000 or more inspections per year) and 
may be performed in conjunction with the gas calibration described in 
paragraph (I)(d)(1) of this appendix. If a leak check is not performed 
within the preceding twenty-four hours in low volume stations and within 
four hours in high-volume stations or if the analyzer fails the leak 
check, the analyzer shall lock out from testing. The leak check shall be 
a procedure demonstrated to effectively check the sample hose and probe 
for leaks and shall be performed in accordance with good engineering 
practices. An error of more than 2% of the reading 
using low range span gas shall cause the analyzer to lock out from 
testing and shall require repair of leaks.
    (d) Gas calibration. (1) On each operating day in high-volume 
stations, analyzers shall automatically require and successfully pass a 
two-point gas calibration for HC, CO, and CO2 and shall continually 
compensate for changes in barometric pressure. Calibration shall be 
checked within four hours before the test and the analyzer adjusted if 
the reading is more than 2% different from the span gas value. In low-
volume stations, analyzers shall undergo a two-point calibration within 
seventy-two hours before each test, unless changes in barometric 
pressure are compensated for automatically and statistical process 
control demonstrates equal or better quality control using different 
frequencies. Gas calibration shall be accomplished by introducing span 
gas that meets the requirements of paragraph (I)(d)(3) of this appendix 
into the analyzer through the calibration port. If the analyzer reads 
the span gas within the allowable tolerance range (i.e., the square root 
of sum of the squares of the span gas tolerance described in paragraph 
(I)(d)(3) of this appendix and the calibration tolerance, which shall be 
equal to 2%), no adjustment of the analyzer is necessary. The gas 
calibration procedure shall correct readings that exceed the allowable 
tolerance range to the center of the allowable tolerance range. The 
pressure in the sample cell shall be the same with the calibration gas 
flowing during calibration as with the sample gas flowing during 
sampling. If the system is not calibrated, or the system fails the 
calibration check, the analyzer shall lock out from testing.
    (2) Span points. A two point gas calibration procedure shall be 
followed. The span shall be accomplished at one of the following pairs 
of span points:

(A) 300--ppm propane (HC)
1.0--% carbon monoxide (CO)
6.0--% carbon dioxide (CO2)
1000--ppm nitric oxide (if equipped with NO)
1200--ppm propane (HC)
4.0--% carbon monoxide (CO)
12.0--% carbon dioxide (CO2)
3000--ppm nitric oxide (if equipped with NO)
(B) --ppm propane
0.0--% carbon monoxide
0.0--% carbon dioxide
0--ppm nitric oxide (if equipped with NO)
600--ppm propane (HC)
1.6--% carbon monoxide (CO)
11.0--% carbon dioxide (CO2)
1200--ppm nitric oxide (if equipped with NO)

    (3) Span gases. The span gases used for the gas calibration shall be 
traceable to National Institute of Standards and Technology (NIST) 
standards 2%, and shall be within two percent of 
the span points specified in paragraph (d)(2) of this appendix. Zero 
gases shall conform to the specifications given in Sec. 86.114-79(a)(5) 
of this chapter.
    (e) Dynamometer checks--(1) Monthly check. Within one month 
preceding each loaded test, the accuracy of the roll speed indicator 
shall be verified and the dynamometer shall be checked for proper power 
absorber settings.
    (2) Semi-annual check. Within six months preceding each loaded test, 
the road-load response of the variable-curve dynamometer or the 
frictional power absorption of the dynamometer shall be checked by a 
coast down procedure similar to that described in Sec. 86.118-78 of 
this chapter. The check shall be done at 30 mph, and a power absorption 
load setting to generate a total horsepower (hp) of 4.1 hp. The actual 
coast down time from 45 mph to 15 mph shall be within 1 second of the time calculated by the following 
equation:
[GRAPHIC] [TIFF OMITTED] TC08NO91.014

where W is the total inertia weight as represented by the weight of the 
rollers (excluding free rollers), and any inertia flywheels used, 
measured in pounds. If the coast down time is not within the specified 
tolerance the dynamometer shall be taken out of service and corrective 
action shall be taken.
    (f) Other checks. In addition to the above periodic checks, these 
shall also be used to verify system performance under the following 
special circumstances.
    (1) Gas Calibration. (A) Each time the analyzer electronic or 
optical systems are repaired or replaced, a gas calibration shall be 
performed prior to returning the unit to service.
    (B) In high-volume stations, monthly multi-point calibrations shall 
be performed. Low-volume stations shall perform multi-

[[Page 342]]

point calibrations every six months. The calibration curve shall be 
checked at 20%, 40%, 60%, and 80% of full scale and adjusted or repaired 
if the specifications in appendix D(I)(b)(1) to this subpart are not 
met.
    (2) Leak checks. Each time the sample line integrity is broken, a 
leak check shall be performed prior to testing.

                      (II) Transient Test Equipment

    (a) Dynamometer. Once per week, the calibration of each dynamometer 
and each fly wheel shall be checked by a dynamometer coast-down 
procedure comparable to that in Sec. 86.118-78 of this chapter between 
the speeds of 55 to 45 mph, and between 30 to 20 mph. All rotating 
dynamometer components shall be included in the coast-down check for the 
inertia weight selected. For dynamometers with uncoupled rolls, the 
uncoupled rollers may undergo a separate coast-down check. If a vehicle 
is used to motor the dynamometer to the beginning coast-down speed, the 
vehicle shall be lifted off the dynamometer rolls before the coast-down 
test begins. If the difference between the measured coast-down time and 
the theoretical coast-down time is greater than +1 second, the system 
shall lock out, until corrective action brings the dynamometer into 
calibration.
    (b) Constant volume sampler. (1) The constant volume sampler (CVS) 
flow calibration shall be checked daily by a procedure that identifies 
deviations in flow from the true value. Deviations greater than 4% shall be corrected.
    (2) The sample probe shall be cleaned and checked at least once per 
month. The main CVS venturi shall be cleaned and checked at least once 
per year.
    (3) Verification that flow through the sample probe is adequate for 
the design shall be done daily. Deviations greater than the design 
tolerances shall be corrected.
    (c) Analyzer system--(1) Calibration checks. (A) Upon initial 
operation, calibration curves shall be generated for each analyzer. The 
calibration curve shall consider the entire range of the analyzer as one 
curve. At least 6 calibration points plus zero shall be used in the 
lower portion of the range corresponding to an average concentration of 
approximately 2 gpm for HC, 30 gpm for CO, 3 gpm for NOX, and 
400 gpm for CO2. For the case where a low and a high range 
analyzer is used, the high range analyzer shall use at least 6 
calibration points plus zero in the lower portion of the high range 
scale corresponding to approximately 100% of the full-scale value of the 
low range analyzer. For all analyzers, at least 6 calibration points 
shall also be used to define the calibration curve in the region above 
the 6 lower calibration points. Gas dividers may be used to obtain the 
intermediate points for the general range classifications specified. The 
calibration curves generated shall be a polynomial of no greater order 
than 4th order, and shall fit the date within 0.5% at each calibration 
point.
    (B) For all calibration curves, curve checks, span adjustments, and 
span checks, the zero gas shall be considered a down-scale reference 
gas, and the analyzer zero shall be set at the trace concentration value 
of the specific zero gas used.
    (2) The basic curve shall be checked monthly by the same procedure 
used to generate the curve, and to the same tolerances.
    (3) On a daily basis prior to vehicle testing--
    (A) The curve for each analyzer shall be checked by adjusting the 
analyzer to correctly read a zero gas and an up-scale span gas, and then 
by correctly reading a mid-scale span gas within 2% of point. If the 
analyzer does not read the mid-scale span point within 2% of point, the 
system shall lock out. The up-scale span gas concentration for each 
analyzer shall correspond to approximately 80 percent of full scale, and 
the mid-point concentration shall correspond to approximately 15 percent 
of full scale; and
    (B) After the up-scale span check, each analyzer in a given facility 
shall analyze a sample of a random concentration corresponding to 
approximately 0.5 to 3 times the cut point (in gpm) for the constituent. 
The value of the random sample may be determined by a gas blender. The 
deviation in analysis from the sample concentration for each analyzer 
shall be recorded and compared to the historical mean and standard 
deviation for the analyzers at the facility and at all facilities. Any 
reading exceeding 3 sigma shall cause the analyzer to lock out.
    (4) Flame ionization detector check. Upon initial operation, and 
after maintenance to the detector, each Flame Ionization Detector (FID) 
shall be checked, and adjusted if necessary, for proper peaking and 
characterization. Procedures described in SAE Paper No. 770141 are 
recommended for this purpose. A copy of this paper may be obtained from 
the Society of Automotive Engineers, Inc. (SAE), 400 Commonwealth Drive, 
Warrendale, Pennsylvania, 15096-0001. Additionally, every month the 
response of each FID to a methane concentration of approximately 50 ppm 
CH4 shall be checked. If the response is outside of the range 
of 1.10 to 1.20, corrective action shall be taken to bring the FID 
response within this range. The response shall be computed by the 
following formula:

[[Page 343]]

[GRAPHIC] [TIFF OMITTED] TC08NO91.015

    (5) Spanning frequency. The zero and up-scale span point shall be 
checked, and adjusted if necessary, at 2 hour intervals following the 
daily mid-scale curve check. If the zero or the up-scale span point 
drifts by more than 2% for the previous check (except for the first 
check of the day), the system shall lock out, and corrective action 
shall be taken to bring the system into compliance.
    (6) Spanning limit checks. The tolerance on the adjustment of the 
up-scale span point is 0.4% of point. A software algorithm to perform 
the span adjustment and subsequent calibration curve adjustment shall be 
used. However, software up-scale span adjustments greater than 10% shall cause the system to lock out, requiring system 
maintenance.
    (7) Integrator checks. Upon initial operation, and every three 
months thereafter, emissions from a randomly selected vehicle with 
official test value greater than 60% of the standard (determined 
retrospectively) shall be simultaneously sampled by the normal 
integration method and by the bag method in each lane. The data from 
each method shall be put into a historical data base for determining 
normal and deviant performance for each test lane, facility, and all 
facilities combined. Specific deviations exceeding 5% shall require corrective action.
    (8) Interference. CO and CO2 analyzers shall be checked 
prior to initial service, and on a yearly basis thereafter, for water 
interference. The specifications and procedures used shall generally 
comply with either Sec. 86.122-78 or Sec. 86.321-79 of this chapter.
    (9) NOX converter check. The converter efficiency of the 
NO2 to NO converter shall be checked on a weekly basis. The 
check shall generally conform to Sec. 86.123-78 of this chapter, or EPA 
MVEL Form 305-01. Equivalent methods may be approved by the 
Administrator.
    (10) NO/NOX flow balance. The flow balance between the NO 
and NOX test modes shall be checked weekly. The check may be 
combined with the NOX convertor check as illustrated in EPA 
MVEL Form 305-01.
    (11) Additional checks. Additional checks shall be performed on the 
HC, CO, CO2, and NOX analyzers according to best 
engineering practices for the measurement technology used to ensure that 
measurements meet specified accuracy requirements.
    (12) System artifacts (hang-up). Prior to each test a comparison 
shall be made between the background HC reading, the HC reading measured 
through the sample probe (if different), and the zero gas. Deviations 
from the zero gas greater than 10 parts per million carbon (ppmC) shall 
cause the analyzer to lock out.
    (13) Ambient background. The average of the pre-test and post-test 
ambient background levels shall be compared to the permissible levels of 
10 ppmC HC, 20 ppm CO, and 1 ppm NOX. If the permissible 
levels are exceeded, the test shall be voided and corrective action 
taken to lower the ambient background concentrations.
    (14) Analytical gases. Zero gases shall meet the requirements of 
Sec. 86.114-79(a)(5) of this chapter. NOX calibration gas 
shall be a single blend using nitrogen as the diluent. Calibration gas 
for the flame ionization detector shall be a single blend of propane 
with a diluent of air. Calibration gases for CO and CO2 shall 
be single blends using nitrogen or air as a diluent. Multiple blends of 
HC, CO, and CO2 in air may be used if shown to be stable and 
accurate.

                       (III) Purge Analysis System

    On a daily basis each purge flow meter shall be checked with a 
simulated purge flow against a reference flow measuring device with 
performance specifications equal to or better than those specified for 
the purge meter. The check shall include a mid-scale rate check, and a 
total flow check between 10 and 20 liters. Deviations greater than 
5% shall be corrected. On a monthly basis, the 
calibration of purge meters shall be checked for proper rate and total 
flow with three equally spaced points across the flow rate and the 
totalized flow range. Deviations exceeding the specified accuracy shall 
be corrected. The dynamometer quality assurance checks required under 
paragraph (II) of this appendix shall also apply to the dynamometer used 
for purge tests.

            (IV) Evaporative System Integrity Test Equipment

    (a) On a weekly basis pressure measurement devices shall be checked 
against a reference device with performance specifications equal to or 
better than those specified for the measurement device. Deviations 
exceeding the performance specifications shall be corrected. Flow 
measurement devices, if any, shall be checked according to paragraph III 
of this appendix.
    (b) Systems that monitor evaporative system leaks shall be checked 
for integrity on a daily basis by sealing and pressurizing.

[57 FR 52987, Nov. 5, 1992, as amended at 58 FR 59367, Nov. 9, 1993]

[[Page 344]]

           Appendix B to Subpart S of Part 51--Test Procedures

                              (I) Idle test

    (a) General requirements--(1) Exhaust gas sampling algorithm. The 
analysis of exhaust gas concentrations shall begin 10 seconds after the 
applicable test mode begins. Exhaust gas concentrations shall be 
analyzed at a minimum rate of two times per second. The measured value 
for pass/fail determinations shall be a simple running average of the 
measurements taken over five seconds.
    (2) Pass/fail determination. A pass or fail determination shall be 
made for each applicable test mode based on a comparison of the short 
test standards contained in appendix C to this subpart, and the measured 
value for HC and CO as described in paragraph (I)(a)(1) of this 
appendix. A vehicle shall pass the test mode if any pair of simultaneous 
measured values for HC and CO are below or equal to the applicable short 
test standards. A vehicle shall fail the test mode if the values for 
either HC or CO, or both, in all simultaneous pairs of values are above 
the applicable standards.
    (3) Void test conditions. The test shall immediately end and any 
exhaust gas measurements shall be voided if the measured concentration 
of CO plus CO2 falls below six percent or the vehicle's 
engine stalls at any time during the test sequence.
    (4) Multiple exhaust pipes. Exhaust gas concentrations from vehicle 
engines equipped with multiple exhaust pipes shall be sampled 
simultaneously.
    (5) This test shall be immediately terminated upon reaching the 
overall maximum test time.
    (b) Test sequence. (1) The test sequence shall consist of a first-
chance test and a second-chance test as follows:
    (i) The first-chance test, as described under paragraph (c) of this 
section, shall consist of an idle mode.
    (ii) The second-chance test as described under paragraph (I)(d) of 
this appendix shall be performed only if the vehicle fails the first-
chance test.
    (2) The test sequence shall begin only after the following 
requirements are met:
    (i) The vehicle shall be tested in as-received condition with the 
transmission in neutral or park and all accessories turned off. The 
engine shall be at normal operating temperature (as indicated by a 
temperature gauge, temperature lamp, touch test on the radiator hose, or 
other visual observation for overheating).
    (ii) For all pre-1996 model year vehicles, a tachometer shall be 
attached to the vehicle in accordance with the analyzer manufacturer's 
instructions. For 1996 and newer model year vehicles the OBD data link 
connector will be used to monitor RPM. In the event that an OBD data 
link connector is not available or that an RPM signal is not available 
over the data link connector, a tachometer shall be used instead.
    (iii) The sample probe shall be inserted into the vehicle's tailpipe 
to a minimum depth of 10 inches. If the vehicle's exhaust system 
prevents insertion to this depth, a tailpipe extension shall be used.
    (iv) The measured concentration of CO plus CO2 shall be 
greater than or equal to six percent.
    (c) First-chance test. The test timer shall start (tt=0) when the 
conditions specified in paragraph (I)(b)(2) of this appendix are met. 
The first-chance test shall have an overall maximum test time of 145 
seconds (tt=145). The first-chance test shall consist of an idle mode 
only.
    (1) The mode timer shall start (mt=0) when the vehicle engine speed 
is between 350 and 1100 rpm. If engine speed exceeds 1100 rpm or falls 
below 350 rpm, the mode timer shall reset zero and resume timing. The 
minimum mode length shall be determined as described under paragraph 
(I)(c)(2) of this appendix. The maximum mode length shall be 90 seconds 
elapsed time (mt=90).
    (2) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (i) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (ii) The vehicle shall pass the idle mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30), if prior 
to that time the criteria of paragraph (I)(c)(2)(i) of this appendix are 
not satisfied and the measured values are less than or equal to the 
applicable short test standards as described in paragraph (I)(a)(2) of 
this appendix.
    (iii) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), the measured values are less 
than or equal to the applicable short test standards as described in 
paragraph (I)(a)(2) of this appendix.
    (iv) The vehicle shall fail the idle mode and the test shall be 
terminated if none of the provisions of paragraphs (I)(c)(2)(i), (ii) 
and (iii) of this appendix is satisfied by an elapsed time of 90 seconds 
(mt=90). Alternatively, the vehicle may be failed if the provisions of 
paragraphs (I)(c)(2)(i) and (ii) of this appendix are not met within an 
elapsed time of 30 seconds.
    (v) Optional. The vehicle may fail the first-chance test and the 
second-chance test shall be omitted if no exhaust gas concentration

[[Page 345]]

lower than 1800 ppm HC is found by an elapsed time of 30 seconds 
(mt=30).
    (d) Second-chance test. If the vehicle fails the first-chance test, 
the test timer shall reset to zero (tt=0) and a second-chance test shall 
be performed. The second-chance test shall have an overall maximum test 
time of 425 seconds (tt=425). The test shall consist of a 
preconditioning mode followed immediately by an idle mode.
    (1) Preconditioning mode. The mode timer shall start (mt=0) when the 
engine speed is between 2200 and 2800 rpm. The mode shall continue for 
an elapsed time of 180 seconds (mt=180). If engine speed falls below 
2200 rpm or exceeds 2800 rmp for more than five seconds in any one 
excursion, or 15 seconds over all excursions, the mode timer shall reset 
to zero and resume timing.
    (2) Idle mode--(i) Ford Motor Company and Honda vehicles. The 
engines of 1981-1987 Ford Motor Company vehicles and 1984-1985 Honda 
Preludes shall be shut off for not more than 10 seconds and restarted. 
This procedure may also be used for 1988-1989 Ford Motor Company 
vehicles but should not be used for other vehicles. The probe may be 
removed from the tailpipe or the sample pump turned off if necessary to 
reduce analyzer fouling during the restart procedure.
    (ii) The mode timer shall start (mt=0) when the vehicle engine speed 
is between 350 and 1100 rpm. If engine speed exceeds 1100 rpm or falls 
below 350 rpm, the mode timer shall reset to zero and resume timing. The 
minimum idle mode length shall be determined as described in paragraph 
(I)(d)(2)(iii) of this appendix. The maximum idle mode length shall be 
90 seconds elapsed time (mt=90).
    (iii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the idle mode shall be terminated as follows:
    (A) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (B) The vehicle shall pass the idle mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30), if prior 
to that time the criteria of paragraph (I)(d)(2)(iii)(A) of this 
appendix are not satisfied and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(I)(a)(2) of this appendix.
    (C) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), measured values are less than or 
equal to the applicable short test standards described in paragraph 
(I)(a)(2) of this appendix.
    (D) The vehicle shall fail the idle mode and the test shall be 
terminated if none of the provisions of paragraphs (I)(d)(2)(iii)(A), 
(d)(2)(iii)(B), and (d)(2)(iii)(C) of this appendix are satisfied by an 
elapsed time of 90 seconds (mt=90).

                        (II) Two Speed Idle Test

    (a) General requirements--(1) Exhaust gas sampling algorithm. The 
analysis of exhaust gas concentrations shall begin 10 seconds after the 
applicable test mode begins. Exhaust gas concentrations shall be 
analyzed at a rate of two times per second. The measured value for pass/
fail determinations shall be a simple running average of the 
measurements taken over five seconds.
    (2) Pass/fail determination. A pass or fail determination shall be 
made for each applicable test mode based on a comparison of the short 
test standards contained in appendix C to this subpart, and the measured 
value for HC and CO as described in paragraph (II)(a)(1) of this 
appendix. A vehicle shall pass the test mode if any pair of simultaneous 
values for HC and CO are below or equal to the applicable short test 
standards. A vehicle shall fail the test mode if the values for either 
HC or CO, or both, in all simultaneous pairs of values are above the 
applicable standards.
    (3) Void test conditions. The test shall immediately end and any 
exhaust gas measurements shall be voided if the measured concentration 
of CO plus CO2 falls below six percent or the vehicle's 
engine stalls at any time during the test sequence.
    (4) Multiple exhaust pipes. Exhaust gas concentrations from vehicle 
engines equipped with multiple exhaust pipes shall be sampled 
simultaneously.
    (5) The test shall be immediately terminated upon reaching the 
overall maximum test time.
    (b) Test sequence. (1) The test sequence shall consist of a first-
chance test and a second-chance test as follows:
    (i) The first-chance test, as described under paragraph (II)(c) of 
this appendix, shall consist of an idle mode followed by a high-speed 
mode.
    (ii) The second-chance high-speed mode, as described under paragraph 
(II)(c) of this appendix, shall immediately follow the first-chance 
high-speed mode. It shall be performed only if the vehicle fails the 
first-chance test. The second-chance idle mode, as described under 
paragraph (II)(d) of this appendix, shall follow the second-chance high-
speed mode and be performed only if the vehicle fails the idle mode of 
the first-chance test.
    (2) The test sequence shall begin only after the following 
requirements are met:
    (i) The vehicle shall be tested in as-received condition with the 
transmission in neutral or park and all accessories turned

[[Page 346]]

off. The engine shall be at normal operating temperature (as indicated 
by a temperature gauge, temperature lamp, touch test on the radiator 
hose, or other visual observation for overheating).
    (ii) For all pre-1996 model year vehicles, a tachometer shall be 
attached to the vehicle in accordance with the analyzer manufacturer's 
instructions. For 1996 and newer model year vehicles the OBD data link 
connector will be used to monitor RPM. In the event that an OBD data 
link connector is not available or that an RPM signal is not available 
over the data link connector, a tachometer shall be used instead.
    (iii) The sample probe shall be inserted into the vehicle's tailpipe 
to a minimum depth of 10 inches. If the vehicle's exhaust system 
prevents insertion to this depth, a tailpipe extension shall be used.
    (iv) The measured concentration of CO plus CO2 shall be 
greater than or equal to six percent.
    (c) First-chance test and second-chance high-speed mode. The test 
timer shall start (tt=0) when the conditions specified in paragraph 
(b)(2) of this section are met. The first-chance test and second-chance 
high-speed mode shall have an overall maximum test time of 425 seconds 
(tt=425). The first-chance test shall consist of an idle mode followed 
immediately by a high-speed mode. This is followed immediately by an 
additional second-chance high-speed mode, if necessary.
    (1) First-chance idle mode. (i) The mode timer shall start (mt=0) 
when the vehicle engine speed is between 350 and 1100 rpm. If engine 
speed exceeds 1100 rpm or falls below 350 rpm, the mode timer shall 
reset to zero and resume timing. The minimum idle mode length shall be 
determined as described in paragraph (II)(c)(1)(ii) of this appendix. 
The maximum idle mode length shall be 90 seconds elapsed time (mt=90).
    (ii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode terminated as follows:
    (A) The vehicle shall pass the idle mode and the mode shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (B) The vehicle shall pass the idle mode and the mode shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30) if, prior 
to that time, the criteria of paragraph (II)(c)(1)(ii)(A) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(II)(a)(2) of this appendix.
    (C) The vehicle shall pass the idle mode and the mode shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), the measured values are less 
than or equal to the applicable short test standards as described in 
paragraph (II)(a)(2) of this appendix.
    (D) The vehicle shall fail the idle mode and the mode shall be 
terminated if none of the provisions of paragraphs (II)(c)(1)(ii)(A), 
(B), and (C) of this appendix is satisfied by an elapsed time of 90 
seconds (mt=90). Alternatively, the vehicle may be failed if the 
provisions of paragraphs (II)(c)(2)(i) and (ii) of this appendix are not 
met within an elapsed time of 30 seconds.
    (E) Optional. The vehicle may fail the first-chance test and the 
second-chance test shall be omitted if no exhaust gas concentration less 
than 1800 ppm HC is found by an elapsed time of 30 seconds (mt=30).
    (2) First-chance and second-chance high-speed modes. This mode 
includes both the first-chance and second-chance high-speed modes, and 
follows immediately upon termination of the first-chance idle mode.
    (i) The mode timer shall reset (mt=0) when the vehicle engine speed 
is between 2200 and 2800 rpm. If engine speed falls below 2200 rpm or 
exceeds 2800 rpm for more than two seconds in one excursion, or more 
than six seconds over all excursions within 30 seconds of the final 
measured value used in the pass/fail determination, the measured value 
shall be invalidated and the mode continued. If any excursion lasts for 
more than ten seconds, the mode timer shall reset to zero (mt=0) and 
timing resumed. The minimum high-speed mode length shall be determined 
as described under paragraphs (II)(c)(2)(ii) and (iii) of this appendix. 
The maximum high-speed mode length shall be 180 seconds elapsed time 
(mt=180).
    (ii) Ford Motor Company and Honda vehicles. For 1981-1987 model year 
Ford Motor Company vehicles and 1984-1985 model year Honda Preludes, the 
pass/fail analysis shall begin after an elapsed time of 10 seconds 
(mt=10) using the following procedure. This procedure may also be used 
for 1988-1989 Ford Motor Company vehicles but should not be used for 
other vehicles.
    (A) A pass or fail determination, as described below, shall be used, 
for vehicles that passed the idle mode, to determine whether the high-
speed test should be terminated prior to or at the end of an elapsed 
time of 180 seconds (mt=180).
    (1) The vehicle shall pass the high-speed mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), the measured values are less than or equal to 100 ppm HC and 
0.5 percent CO.
    (2) The vehicle shall pass the high-speed mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30) if, prior 
to that time, the criteria of paragraph (II)(c)(2)(ii)(A)(1) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short

[[Page 347]]

test standards as described in paragraph (II)(a)(2) of this appendix.
    (3) The vehicle shall pass the high-speed mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 180 seconds (mt=180), the measured values are less 
than or equal to the applicable short test standards as described in 
paragraph (II)(a)(2) of this appendix.
    (4) Restart. If at an elapsed time of 90 seconds (mt=90) the 
measured values are greater than the applicable short test standards as 
described in paragraph (II)(a)(2) of this appendix, the vehicle's engine 
shall be shut off for not more than 10 seconds after returning to idle 
and then shall be restarted. The probe may be removed from the tailpipe 
or the sample pump turned off if necessary to reduce analyzer fouling 
during the restart procedure. The mode timer will stop upon engine shut 
off (mt=90) and resume upon engine restart. The pass/fail determination 
shall resume as follows after 100 seconds have elapsed (mt=100).
    (i) The vehicle shall pass the high-speed mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 100 
seconds (mt=100) and 180 seconds (mt=180), the measured values are less 
than or equal to the applicable short test standards described in 
paragraph (II)(a)(2) of this appendix.
    (ii) The vehicle shall fail the high-speed mode and the test shall 
be terminated if paragraph (II)(c)(2)(ii)(A)(4)(i) of this appendix is 
not satisfied by an elapsed time of 180 seconds (mt=180).
    (B) A pass or fail determination shall be made for vehicles that 
failed the idle mode and the high-speed mode terminated at the end of an 
elapsed time of 180 seconds (mt=180) as follows:
    (1) The vehicle shall pass the high-speed mode and the mode shall be 
terminated at an elapsed time of 180 seconds (mt=180) if any measured 
values of HC and CO exhaust gas concentrations during the high-speed 
mode are less than or equal to the applicable short test standards as 
described in paragraph (II)(a)(2) of this appendix.
    (2) Restart. If at an elapsed time of 90 seconds (mt=90) the 
measured values of HC and CO exhaust gas concentrations during the high-
speed mode are greater than the applicable short test standards as 
described in paragraph (II)(a)(2) of this appendix, the vehicle's engine 
shall be shut off for not more than 10 seconds after returning to idle 
and then shall be restarted. The probe may be removed from the tailpipe 
or the sample pump turned off if necessary to reduce analyzer fouling 
during the restart procedure. The mode timer will stop upon engine shut 
off (mt=90) and resume upon engine restart. The pass/fail determination 
shall resume as follows after 100 seconds have elapsed (mt=100).
    (i) The vehicle shall pass the high-speed mode and the mode shall be 
terminated at an elapsed time of 180 seconds (mt=180) if any measured 
values of HC and CO exhaust gas concentrations during the high-speed 
mode are less than or equal to the applicable short test standards as 
described in paragraph (II)(a)(2) of this appendix.
    (ii) The vehicle shall fail the high-speed mode and the test shall 
be terminated if paragraph (II)(c)(2)(ii)(B)(2)(i) of this appendix is 
not satisfied by an elapsed time of 180 seconds (mt=180).
    (iii) All other light-duty motor vehicles. The pass/fail analysis 
for vehicles not specified in paragraph (II)(c)(2)(ii) of this appendix 
shall begin after an elapsed time of 10 seconds (mt=10) using the 
following procedure.
    (A) A pass or fail determination, as described below, shall be used 
for vehicles that passed the idle mode, to determine whether the high-
speed mode should be terminated prior to or at the end of an elapsed 
time of 180 seconds (mt=180).
    (1) The vehicle shall pass the high-speed mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), any measured values are less than or equal to 100 ppm HC and 
0.5 percent CO.
    (2) The vehicle shall pass the high-speed mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30) if, prior 
to that time, the criteria of paragraph (II)(c)(2)(iii)(A)(1) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(II)(a)(2) of this appendix.
    (3) The vehicle shall pass the high-speed mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 180 seconds (mt=180), the measured values are less 
than or equal to the applicable short test standards as described in 
paragraph (II)(a)(2) of this appendix.
    (4) The vehicle shall fail the high-speed mode and the test shall be 
terminated if none of the provisions of paragraphs 
(II)(c)(2)(iii)(A)(1), (2), and (3) of this appendix is satisfied by an 
elapsed time of 180 seconds (mt=180).
    (B) A pass or fail determination shall be made for vehicles that 
failed the idle mode and the high-speed mode terminated at the end of an 
elapsed time of 180 seconds (mt=180) as follows:
    (1) The vehicle shall pass the high-speed mode and the mode shall be 
terminated at an elapsed time of 180 seconds (mt=180) if any measured 
values are less than or equal to the applicable short test standards as 
described in paragraph (II)(a)(2) of this appendix.
    (2) The vehicle shall fail the high-speed mode and the test shall be 
terminated if paragraph (II)(c)(2)(iii)(B)(1) of this appendix

[[Page 348]]

is not satisfied by an elapsed time of 180 seconds (mt=180).
    (d) Second-chance idle mode. If the vehicle fails the first-chance 
idle mode and passes the high-speed mode, the test timer shall reset to 
zero (tt=0) and a second-chance idle mode shall commence. The second-
chance idle mode shall have an overall maximum test time of 145 seconds 
(tt=145). The test shall consist of an idle mode only.
    (1) The engines of 1981-1987 Ford Motor Company vehicles and 1984-
1985 Honda Preludes shall be shut off for not more than 10 seconds and 
restarted. The probe may be removed from the tailpipe or the sample pump 
turned off if necessary to reduce analyzer fouling during the restart 
procedure. This procedure may also be used for 1988-1989 Ford Motor 
Company vehicles but should not be used for other vehicles.
    (2) The mode timer shall start (mt=0) when the vehicle engine speed 
is between 350 and 1100 rpm. If the engine speed exceeds 1100 rpm or 
falls below 350 rpm the mode timer shall reset to zero and resume 
timing. The minimum second-chance idle mode length shall be determined 
as described in paragraph (II)(d)(3) of this appendix. The maximum 
second-chance idle mode length shall be 90 seconds elapsed time (mt=90).
    (3) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the second-chance idle mode shall be terminated as follows:
    (i) The vehicle shall pass the second-chance idle mode and the test 
shall be immediately terminated if, prior to an elapsed time of 30 
seconds (mt=30), any measured values are less than or equal to 100 ppm 
HC and 0.5 percent CO.
    (ii) The vehicle shall pass the second-chance idle mode and the test 
shall be terminated at the end of an elapsed time of 30 seconds (mt=30) 
if, prior to that time, the criteria of paragraph (II)(d)(3)(i) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(II)(a)(2) of this appendix.
    (iii) The vehicle shall pass the second-chance idle mode and the 
test shall be immediately terminated if, at any point between an elapsed 
time of 30 seconds (mt=30) and 90 seconds (mt=90), the measured values 
are less than or equal to the applicable short test standards as 
described in paragraph (II)(a)(2) of this appendix.
    (iv) The vehicle shall fail the second-chance idle mode and the test 
shall be terminated if none of the provisions of paragraph 
(II)(d)(3)(i), (ii), and (iii) of this appendix is satisfied by an 
elapsed time of 90 seconds (mt=90).

                            (III) Loaded Test

    (a) General requirements--(1) Exhaust gas sampling algorithm. The 
analysis of exhaust gas concentrations shall begin 10 seconds after the 
applicable test mode begins. Exhaust gas concentrations shall be 
analyzed at a minimum rate of two times per second. The measured value 
for pass/fail determinations shall be a simple running average of the 
measurements taken over five seconds.
    (2) Pass/fail determination. A pass or fail determination shall be 
made for each applicable test mode based on a comparison of the short 
test standards contained in appendix C to this subpart and the measured 
value for HC and CO as described in paragraph (III)(a)(1) of this 
appendix. A vehicle shall pass the test mode if any pair of simultaneous 
values for HC and CO are below or equal to the applicable short test 
standards. A vehicle shall fail the test mode if the values for either 
HC or CO, or both, in all simultaneous pairs of values are above the 
applicable standards.
    (3) Void test conditions. The test shall immediately end and any 
exhaust gas measurements shall be voided if the measured concentration 
of CO plus CO2 falls below six percent or the vehicle's 
engine stalls at any time during the test sequence.
    (4) Multiple exhaust pipes. Exhaust gas concentrations from vehicle 
engines equipped with multiple exhaust pipes shall be sampled 
simultaneously.
    (5) The test shall be immediately terminated upon reaching the 
overall maximum test time.
    (b) Test sequence. (1) The test sequence shall consist of a loaded 
mode using a chassis dynamometer followed immediately by an idle mode as 
described under paragraphs (III)(c)(1) and (2) of this appendix.
    (2) The test sequence shall begin only after the following 
requirements are met:
    (i) The dynamometer shall be warmed up, in stabilized operating 
condition, adjusted, and calibrated in accordance with the procedures of 
appendix A to this subpart. Prior to each test, variable-curve 
dynamometers shall be checked for proper setting of the road-load 
indicator or road-load controller.
    (ii) The vehicle shall be tested in as-received condition with all 
accessories turned off. The engine shall be at normal operating 
temperature (as indicated by a temperature gauge, temperature lamp, 
touch test on the radiator hose, or other visual observation for 
overheating).
    (iii) The vehicle shall be operated during each mode of the test 
with the gear selector in the following position:
    (A) In drive for automatic transmissions and in second (or third if 
more appropriate) for manual transmissions for the loaded mode;
    (B) In park or neutral for the idle mode.

[[Page 349]]

    (iv) For all pre-1996 model year vehicles, a tachometer shall be 
attached to the vehicle in accordance with the analyzer manufacturer's 
instructions. For 1996 and newer model year vehicles the OBD data link 
connector will be used to monitor RPM. In the event that an OBD data 
link connector is not available or that an RPM signal is not available 
over the data link connector, a tachometer shall be used instead.
    (v) The sample probe shall be inserted into the vehicle's tailpipe 
to a minimum depth of 10 inches. If the vehicle's exhaust system 
prevents insertion to this depth, a tailpipe extension shall be used.
    (vi) The measured concentration of CO plus CO2 shall be 
greater than or equal to six percent.
    (c) Overall test procedure. The test timer shall start (tt=0) when 
the conditions specified in paragraph (III)(b)(2) of this appendix are 
met and the mode timer initiates as specified in paragraph (III)(c)(1) 
of this appendix. The test sequence shall have an overall maximum test 
time of 240 seconds (tt=240). The test shall be immediately terminated 
upon reaching the overall maximum test time.
    (1) Loaded mode--(i) Ford Motor Company and Honda vehicles. 
(Optional) The engines of 1981-1987 Ford Motor Company vehicles and 
1984-1985 Honda Preludes shall be shut off for not more than 10 seconds 
and restarted. This procedure may also be used for 1988-1989 Ford Motor 
Company vehicles but should not be used for other vehicles. The probe 
may be removed from the tailpipe or the sample pump turned off if 
necessary to reduce analyzer fouling during the restart procedure.
    (ii) The mode timer shall start (mt=0) when the dynamometer speed is 
within the limits specified for the vehicle engine size according to the 
following schedule. If the dynamometer speed falls outside the limits 
for more than five seconds in one excursion, or 15 seconds over all 
excursions, the mode timer shall reset to zero and resume timing. The 
minimum mode length shall be determined as described in paragraph 
(III)(c)(1)(iii)(A) of this appendix. The maximum mode length shall be 
90 seconds elapsed time (mt=90).

                        Dynamometer Test Schedule
------------------------------------------------------------------------
                                                               Normal
                                                Roll speed     loading
       Gasoline engine size (cylinders)            (mph)       (brake
                                                             horsepower)
------------------------------------------------------------------------
4 or less.....................................       22-25  2.8-4.1
5-6...........................................       29-32  6.8-8.4
7 or more.....................................       32-35  8.4-10.8
------------------------------------------------------------------------

    (iii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (A) The vehicle shall pass the loaded mode and the mode shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), measured values are less than or 
equal to the applicable short test standards described in paragraph 
(a)(2) of this section.
    (B) The vehicle shall fail the loaded mode and the mode shall be 
terminated if paragraph (III)(c)(1)(iii)(A) of this appendix is not 
satisfied by an elapsed time of 90 seconds (mt=90).
    (C) Optional. The vehicle may fail the loaded mode and any 
subsequent idle mode shall be omitted if no exhaust gas concentration 
less than 1800 ppm HC is found by an elapsed time of 30 seconds (mt=30).
    (2) Idle mode--(i) Ford Motor Company and Honda vehicles. (Optional) 
The engines of 1981-1987 Ford Motor Company vehicles and 1984-1985 Honda 
Preludes shall be shut off for not more than 10 seconds and restarted. 
This procedure may also be used for 1988-1989 Ford Motor Company 
vehicles but should not be used for other vehicles. The probe may be 
removed from the tailpipe or the sample pump turned off if necessary to 
reduce analyzer fouling during the restart procedure.
    (ii) The mode timer shall start (mt=0) when the dynamometer speed is 
zero and the vehicle engine speed is between 350 and 1100 rpm. If engine 
speed exceeds 1100 rpm or falls below 350 rpm, the mode timer shall 
reset to zero and resume timing. The minimum idle mode length shall be 
determined as described in paragraph (II)(c)(2)(ii) of this appendix. 
The maximum idle mode length shall be 90 seconds elapsed time (mt=90).
    (iii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (A) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (B) The vehicle shall pass the idle mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30) if, prior 
to that time, the criteria of paragraph (III)(c)(2)(iii)(A) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(III)(a)(2) of this appendix.
    (C) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), measured values are less than or 
equal to the applicable short test standards described in paragraph 
(III)(a)(2) of this appendix.
    (D) The vehicle shall fail the idle mode and the test shall be 
terminated if none of the

[[Page 350]]

provisions of paragraphs (III)(c)(2)(iii)(A), (c)(2)(iii)(B), and 
(c)(2)(iii)(C) of this appendix is satisfied by an elapsed time of 90 
seconds (mt=90).

                      (IV) Preconditioned IDLE TEST

    (a) General requirements--(1) Exhaust gas sampling algorithm. The 
analysis of exhaust gas concentrations shall begin 10 seconds after the 
applicable test mode begins. Exhaust gas concentrations shall be 
analyzed at a minimum rate of two times per second. The measured value 
for pass/fail determinations shall be a simple running average of the 
measurements taken over five seconds.
    (2) Pass/fail determination. A pass or fail determination shall be 
made for each applicable test mode based on a comparison of the short 
test standards contained in appendix C to this subpart, and the measured 
value for HC and CO as described in paragraph (IV)(a)(1) of this 
appendix. A vehicle shall pass the test mode if any pair of simultaneous 
values for HC and CO are below or equal to the applicable short test 
standards. A vehicle shall fail the test mode if the values for either 
HC or CO, or both, in all simultaneous pairs of values are above the 
applicable standards.
    (3) Void test conditions. The test shall immediately end and any 
exhaust gas measurements shall be voided if the measured concentration 
of CO plus CO2 falls below six percent or the vehicle's 
engine stalls at any time during the test sequence.
    (4) Multiple exhaust pipes. Exhaust gas concentrations from vehicle 
engines equipped with multiple exhaust pipes shall be sampled 
simultaneously.
    (5) The test shall be immediately terminated upon reaching the 
overall maximum test time.
    (b) Test sequence. (1) The test sequence shall consist of a first-
chance test and a second-chance test as follows:
    (i) The first-chance test, as described under paragraph (IV)(c) of 
this appendix, shall consist of a preconditioning mode followed by an 
idle mode.
    (ii) The second-chance test, as described under paragraph (IV)(d) of 
this appendix, shall be performed only if the vehicle fails the first-
chance test.
    (2) The test sequence shall begin only after the following 
requirements are met:
    (i) The vehicle shall be tested in as-received condition with the 
transmission in neutral or park and all accessories turned off. The 
engine shall be at normal operating temperature (as indicated by a 
temperature gauge, temperature lamp, touch test on the radiator hose, or 
other visual observation for overheating).
    (ii) For all pre-1996 model year vehicles, a tachometer shall be 
attached to the vehicle in accordance with the analyzer manufacturer's 
instructions. For 1996 and newer model year vehicles the OBD data link 
connector will be used to monitor RPM. In the event that an OBD data 
link connector is not available or that an RPM signal is not available 
over the data link connector, a tachometer shall be used instead.
    (iii) The sample probe shall be inserted into the vehicle's tailpipe 
to a minimum depth of 10 inches. If the vehicle's exhaust system 
prevents insertion to this depth, a tailpipe extension shall be used.
    (iv) The measured concentration of CO plus CO2 shall be greater than 
or equal to six percent.
    (c) First-chance test. The test timer shall start (tt=0) when the 
conditions specified in paragraph (IV)(b)(2) of this appendix are met. 
The test shall have an overall maximum test time of 200 seconds 
(tt=200). The first-chance test shall consist of a preconditioning mode 
followed immediately by an idle mode.
    (1) Preconditioning mode. The mode timer shall start (mt=0) when the 
engine speed is between 2200 and 2800 rpm. The mode shall continue for 
an elapsed time of 30 seconds (mt=30). If engine speed falls below 2200 
rpm or exceeds 2800 rpm for more than five seconds in any one excursion, 
or 15 seconds over all excursions, the mode timer shall reset to zero 
and resume timing.
    (2) Idle mode. (i) The mode timer shall start (mt=0) when the 
vehicle engine speed is between 350 and 1100 rpm. If engine speed 
exceeds 1100 rpm or falls below 350 rpm, the mode timer shall reset to 
zero and resume timing. The minimum idle mode length shall be determined 
as described in paragraph (IV)(c)(2)(ii) of this appendix. The maximum 
idle mode length shall be 90 seconds elapsed time (mt=90).
    (ii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (A) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (B) The vehicle shall pass the idle mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30) if, prior 
to that time, the criteria of paragraph (IV)(c)(2)(ii)(A) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(IV)(a)(2) of this appendix.
    (C) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(IV)(a)(2) of this section.

[[Page 351]]

    (D) The vehicle shall fail the idle mode and the test shall be 
terminated if none of the provisions of paragraphs (IV)(c)(2)(ii)(A), 
(B), and (C) of this appendix is satisfied by an elapsed time of 90 
seconds (mt=90). Alternatively, the vehicle may be failed if the 
provisions of paragraphs (IV)(c)(2) (i) and (ii) of this appendix are 
not met within an elapsed time of 30 seconds.
    (E) Optional. The vehicle may fail the first-chance test and the 
second-chance test shall be omitted if no exhaust gas concentration less 
than 1800 ppm HC is found at an elapsed time of 30 seconds (mt=30).
    (d) Second-chance test. If the vehicle fails the first-chance test, 
the test timer shall reset to zero and a second-chance test shall be 
performed. The second-chance test shall have an overall maximum test 
time of 425 seconds. The test shall consist of a preconditioning mode 
followed immediately by an idle mode.
    (1) Preconditioning mode. The mode timer shall start (mt=0) when 
engine speed is between 2200 and 2800 rpm. The mode shall continue for 
an elapsed time of 180 seconds (mt=180). If the engine speed falls below 
2200 rpm or exceeds 2800 rpm for more than five seconds in any one 
excursion, or 15 seconds over all excursions, the mode timer shall reset 
to zero and resume timing.
    (2) Idle mode--(i) Ford Motor Company and Honda vehicles. The 
engines of 1981-1987 Ford Motor Company vehicles and 1984-1985 Honda 
Preludes shall be shut off for not more than 10 seconds and then shall 
be restarted. The probe may be removed from the tailpipe or the sample 
pump turned off if necessary to reduce analyzer fouling during the 
restart procedure. This procedure may also be used for 1988-1989 Ford 
Motor Company vehicles but should not be used for other vehicles.
    (ii) The mode timer shall start (mt=0) when the vehicle engine speed 
is between 350 and 1100 rpm. If the engine speed exceeds 1100 rpm or 
falls below 350 rpm, the mode timer shall reset to zero and resume 
timing. The minimum idle mode length shall be determined as described in 
paragraph (IV)(d)(2)(iii) of this appendix. The maximum idle mode length 
shall be 90 seconds elapsed time (mt=90).
    (iii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (A) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (B) The vehicle shall pass the idle mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30) if, prior 
to that time, the criteria of paragraph (IV)(d)(2)(iii)(A) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(IV)(a)(2) of this appendix.
    (C) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), measured values are less than or 
equal to the applicable short test standards described in paragraph 
(IV)(a)(2) of this appendix.
    (D) The vehicle shall fail the idle mode and the test shall be 
terminated if none of the provisions of paragraphs (IV)(d)(2)(iii) (A), 
(B), and (C) of this appendix is satisfied by an elapsed time of 90 
seconds (mt=90).

                (V) Idle Test With Loaded Preconditioning

    (a) General requirements--(1) Exhaust gas sampling algorithm. The 
analysis of exhaust gas concentrations shall begin 10 seconds after the 
applicable test mode begins. Exhaust gas concentrations shall be 
analyzed at a minimum rate of two times per second. The measured value 
for pass/fail determinations shall be a simple running average of the 
measurements taken over five seconds.
    (2) Pass/fail determination. A pass or fail determination shall be 
made for each applicable test mode based on a comparison of the short 
test standards contained in appendix C to this subpart, and the measured 
value for HC and CO as described in paragraph (V)(a)(1) of this 
appendix. A vehicle shall pass the test mode if any pair of simultaneous 
values for HC and CO are below or equal to the applicable short test 
standards. A vehicle shall fail the test mode if the values for either 
HC or CO, or both, in all simultaneous pairs of values are above the 
applicable standards.
    (3) Void test conditions. The test shall immediately end and any 
exhaust gas measurements shall be voided if the measured concentration 
of CO plus CO2 falls below six percent or the vehicle's 
engine stalls at any time during the test sequence.
    (4) Multiple exhaust pipes. Exhaust gas concentrations from vehicle 
engines equipped with multiple exhaust pipes shall be sampled 
simultaneously.
    (5) The test shall be immediately terminated upon reaching the 
overall maximum test time.
    (b) Test sequence. (1) The test sequence shall consist of a first-
chance test and a second-chance test as follows:
    (i) The first-chance test, as described under paragraph (V)(c) of 
this appendix, shall consist of an idle mode.
    (ii) The second-chance test as described under paragraph (V)(d) of 
this appendix shall be performed only if the vehicle fails the first-
chance test.
    (2) The test sequence shall begin only after the following 
requirements are met:

[[Page 352]]

    (i) The dynamometer shall be warmed up, in stabilized operating 
condition, adjusted, and calibrated in accordance with the procedures of 
appendix A to this subpart. Prior to each test, variable-curve 
dynamometers shall be checked for proper setting of the road-load 
indicator or road-load controller.
    (ii) The vehicle shall be tested in as-received condition with all 
accessories turned off. The engine shall be at normal operating 
temperature (as indicated by a temperature gauge, temperature lamp, 
touch test on the radiator hose, or other visual observation for 
overheating).
    (iii) The vehicle shall be operated during each mode of the test 
with the gear selector in the following position:
    (A) In drive for automatic transmissions and in second (or third if 
more appropriate) for manual transmissions for the loaded 
preconditioning mode;
    (B) In park or neutral for the idle mode.
    (iv) For all pre-1996 model year vehicles, a tachometer shall be 
attached to the vehicle in accordance with the analyzer manufacturer's 
instructions. For 1996 and newer model year vehicles the OBD data link 
connector will be used to monitor RPM. In the event that an OBD data 
link connector is not available or that an RPM signal is not available 
over the data link connector, a tachometer shall be used instead.
    (v) The sample probe shall be inserted into the vehicle's tailpipe 
to a minimum depth of 10 inches. If the vehicle's exhaust system 
prevents insertion to this depth, a tailpipe extension shall be used.
    (vi) The measured concentration of CO plus CO2 shall be 
greater than or equal to six percent.
    (c) First-chance test. The test timer shall start (tt=0) when the 
conditions specified in paragraph (V)(b)(2) of this appendix are met. 
The test shall have an overall maximum test time of 155 seconds 
(tt=155). The first-chance test shall consist of an idle mode only.
    (1) The mode timer shall start (mt=0) when the vehicle engine speed 
is between 350 and 1100 rpm. If the engine speed exceeds 1100 rpm or 
falls below 350 rpm, the mode timer shall reset to zero and resume 
timing. The minimum mode length shall be determined as described in 
paragraph (V)(c)(2) of this appendix. The maximum mode length shall be 
90 seconds elapsed time (mt=90).
    (2) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (i) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (ii) The vehicle shall pass the idle mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30) if, prior 
to that time, the criteria of paragraph (V)(c)(2)(i) of this appendix 
are not satisfied, and the measured values are less than or equal to the 
applicable short test standards as described in paragraph (V)(a)(2) of 
this appendix.
    (iii) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), the measured values are less 
than or equal to the applicable short test standards as described in 
paragraph (V)(a)(2) of this appendix.
    (iv) The vehicle shall fail the idle mode and the test shall be 
terminated if none of the provisions of paragraphs (V)(c)(2)(i), (ii), 
and (iii) of this appendix is satisfied by an elapsed time of 90 seconds 
(mt=90). Alternatively, the vehicle may be failed if the provisions of 
paragraphs (V)(c)(2) (i) and (ii) of this appendix are not met within an 
elapsed time of 30 seconds.
    (v) Optional. The vehicle may fail the first-chance test and the 
second-chance test shall be omitted if no exhaust gas concentration less 
than 1800 ppm HC is found at an elapsed time of 30 seconds (mt=30).
    (d) Second-chance test. If the vehicle fails the first-chance test, 
the test timer shall reset to zero (tt=0) and a second-chance test shall 
be performed. The second-chance test shall have an overall maximum test 
time of 200 seconds (tt=200). The test shall consist of a 
preconditioning mode using a chassis dynamometer, followed immediately 
by an idle mode.
    (1) Preconditioning mode. The mode timer shall start (mt=0) when the 
dynamometer speed is within the limits specified for the vehicle engine 
size in accordance with the following schedule. The mode shall continue 
for a minimum elapsed time of 30 seconds (mt=30). If the dynamometer 
speed falls outside the limits for more than five seconds in one 
excursion, or 15 seconds over all excursions, the mode timer shall reset 
to zero and resume timing.

------------------------------------------------------------------------
                                                      Dynamometer test
                                                          schedule
                                                   ---------------------
         Gasoline engine size (cylinders)                       Normal
                                                      Roll     loading
                                                     speed      (brake
                                                     (mph)   horsepower)
------------------------------------------------------------------------
4 or less.........................................    22-25  2.8-4.1
5-6...............................................    29-32  6.8-8.4
7 or more.........................................    32-35  8.4-10.8
------------------------------------------------------------------------

    (2) Idle mode. (i) Ford Motor Company and Honda vehicles. (Optional) 
The engines of 1981-1987 Ford Motor Company vehicles and 1984-1985 Honda 
Preludes shall be shut off for not more than 10 seconds and restarted. 
This procedure may also be used for 1988-1989 Ford

[[Page 353]]

Motor Company vehicles but should not be used for other vehicles. The 
probe may be removed from the tailpipe or the sample pump turned off if 
necessary to reduce analyzer fouling during the restart procedure.
    (ii) The mode timer shall start (mt=0) when the dynamometer speed is 
zero and the vehicle engine speed is between 350 and 1100 rpm. If the 
engine speed exceeds 1100 rpm or falls below 350 rpm, the mode timer 
shall reset to zero and resume timing. The minimum idle mode length 
shall be determined as described in paragraph (V)(d)(2)(ii) of this 
appendix. The maximum idle mode length shall be 90 seconds elapsed time 
(mt=90).
    (iii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (A) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (B) The vehicle shall pass the idle mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30) if, prior 
to that time, the criteria of paragraph (V)(d)(2)(ii)(A) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(V)(a)(2) of this appendix.
    (C) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), the measured values are less 
than or equal to the applicable short test standards as described in 
paragraph (V)(a)(2) of this appendix.
    (D) The vehicle shall fail the idle mode and the test shall be 
terminated if none of the provisions of paragraphs (V)(d)(2)(ii)(A), 
(B), and (C) of this appendix is satisfied by an elapsed time of 90 
seconds (mt=90).

                 (VI) Preconditioned Two Speed Idle Test

    (a) General requirements--(1) Exhaust gas sampling algorithm. The 
analysis of exhaust gas concentrations shall begin 10 seconds after the 
applicable test mode begins. Exhaust gas concentrations shall be 
analyzed at a minimum rate of two times per second. The measured value 
for pass/fail determinations shall be a simple running average of the 
measurements taken over five seconds.
    (2) Pass/fail determination. A pass or fail determination shall be 
made for each applicable test mode based on a comparison of the short 
test standards contained in appendix C to this subpart, and the measured 
value for HC and CO as described in paragraph (VI)(a)(1) of this 
appendix. A vehicle shall pass the test mode if any pair of simultaneous 
values for HC and CO are below or equal to the applicable short test 
standards. A vehicle shall fail the test mode if the values for either 
HC or CO, or both, in all simultaneous pairs of values are above the 
applicable standards.
    (3) Void test conditions. The test shall immediately end and any 
exhaust gas measurements shall be voided if the measured concentration 
of CO plus CO2 falls below six percent or the vehicle's 
engine stalls at any time during the test sequence.
    (4) Multiple exhaust pipes. Exhaust gas concentrations from vehicle 
engines equipped with multiple exhaust pipes shall be sampled 
simultaneously.
    (5) The test shall be immediately terminated upon reaching the 
overall maximum test time.
    (b) Test sequence. (1) The test sequence shall consist of a first-
chance test and a second-chance test as follows:
    (i) The first-chance test, as described under paragraph (VI)(c) of 
this appendix, shall consist of a first-chance high-speed mode followed 
immediately by a first-chance idle mode.
    (ii) The second-chance test as described under paragraph (VI)(d) of 
this appendix shall be performed only if the vehicle fails the first-
chance test.
    (2) The test sequence shall begin only after the following 
requirements are met:
    (i) The vehicle shall be tested in as-received condition with the 
transmission in neutral or park and all accessories turned off. The 
engine shall be at normal operating temperature (as indicated by a 
temperature gauge, temperature lamp, touch test on the radiator hose, or 
other visual observation for overheating).
    (ii) For all pre-1996 model year vehicles, a tachometer shall be 
attached to the vehicle in accordance with the analyzer manufacturer's 
instructions. For 1996 and newer model year vehicles the OBD data link 
connector will be used to monitor rpm. In the event that an OBD data 
link connector is not available or that an rpm signal is not available 
over the data link connector, a tachometer shall be used instead.
    (iii) The sample probe shall be inserted into the vehicle's tailpipe 
to a minimum depth of 10 inches. If the vehicle's exhaust system 
prevents insertion to this depth, a tailpipe extension shall be used.
    (iv) The measured concentration of CO plus CO2 shall be 
greater than or equal to six percent.
    (c) First-chance test. The test timer shall start (tt=0) when the 
conditions specified in paragraph (VI)(b)(2) of this appendix are met. 
The test shall have an overall maximum test time of 290 seconds 
(tt=290). The first-chance test shall consist of a high-speed mode 
followed immediately by an idle mode.

[[Page 354]]

    (1) First-chance high-speed mode. (i) The mode timer shall reset 
(mt=0) when the vehicle engine speed is between 2200 and 2800 rpm. If 
the engine speed falls below 2200 rpm or exceeds 2800 rpm for more than 
two seconds in one excursion, or more than six seconds over all 
excursions within 30 seconds of the final measured value used in the 
pass/fail determination, the measured value shall be invalidated and the 
mode continued. If any excursion lasts for more than ten seconds, the 
mode timer shall reset to zero (mt=0) and timing resumed. The high-speed 
mode length shall be 90 seconds elapsed time (mt=90).
    (ii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (A) The vehicle shall pass the high-speed mode and the mode shall be 
terminated at an elapsed time of 90 seconds (mt=90) if any measured 
values are less than or equal to the applicable short test standards as 
described in paragraph (VI)(a)(2) of this appendix.
    (B) The vehicle shall fail the high-speed mode and the mode shall be 
terminated if the requirements of paragraph (VI)(c)(1)(ii)(A) of this 
appendix are not satisfied by an elapsed time of 90 seconds (mt=90).
    (C) Optional. The vehicle shall fail the first-chance test and any 
subsequent test shall be omitted if no exhaust gas concentration lower 
than 1800 ppm HC is found at an elapsed time of 30 seconds (mt=30).
    (2) First-chance idle mode. (i) The mode timer shall start (mt=0) 
when the vehicle engine speed is between 350 and 1100 rpm. If the engine 
speed exceeds 1100 rpm or falls below 350 rpm, the mode timer shall 
reset to zero and resume timing. The minimum first-chance idle mode 
length shall be determined as described in paragraph (VI)(c)(2)(ii) of 
this appendix. The maximum first-chance idle mode length shall be 90 
seconds elapsed time (mt=90).
    (ii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (A) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (B) The vehicle shall pass the idle mode and the test shall be 
terminated at the end of an elapsed time of 30 seconds (mt=30) if, prior 
to that time, the criteria of paragraph (VI)(c)(2)(ii)(A) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(VI)(a)(2) of this appendix.
    (C) The vehicle shall pass the idle mode and the test shall be 
immediately terminated if, at any point between an elapsed time of 30 
seconds (mt=30) and 90 seconds (mt=90), the measured values are less 
than or equal to the applicable short test standards as described in 
paragraph (VI)(a)(2) of this appendix.
    (D) The vehicle shall fail the idle mode and the test shall be 
terminated if none of the provisions of paragraphs (VI)(c)(2)(ii) (A), 
(B), and (C) of this appendix is satisfied by an elapsed time of 90 
seconds (mt=90). Alternatively, the vehicle may be failed if the 
provisions of paragraphs (VI)(c)(2)(i) and (ii) of this appendix are not 
met within the elapsed time of 30 seconds.
    (d) Second-chance test. (1) If the vehicle fails either mode of the 
first-chance test, the test timer shall reset to zero (tt=0) and a 
second-chance test shall commence. The second-chance test shall be 
performed based on the first-chance test failure mode or modes as 
follows:
    (A) If the vehicle failed only the first-chance high-speed mode, the 
second-chance test shall consist of a second-chance high-speed mode as 
described in paragraph (VI)(d)(2) of this appendix. The overall maximum 
test time shall be 280 seconds (tt=280).
    (B) If the vehicle failed only the first-chance idle mode, the 
second-chance test shall consist of a second-chance pre-conditioning 
mode followed immediately by a second-chance idle mode as described in 
paragraphs (VI)(d) (3) and (4) of this appendix. The overall maximum 
test time shall be 425 seconds (tt=425).
    (C) If both the first-chance high-speed mode and first-chance idle 
mode were failed, the second-chance test shall consist of the second-
chance high-speed mode followed immediately by the second-chance idle 
mode as described in paragraphs (VI)(d) (2) and (4) of this appendix. 
However, if during this second-chance procedure the vehicle fails the 
second-chance high-speed mode, then the second-chance idle mode may be 
eliminated. The overall maximum test time shall be 425 seconds (tt=425).
    (2) Second-chance high-speed mode--(i) Ford Motor Company and Honda 
vehicles. The engines of 1981-1987 Ford Motor Company vehicles and 1984-
1985 Honda Preludes shall be shut off for not more than 10 seconds and 
then shall be restarted. The probe may be removed from the tailpipe or 
the sample pump turned off if necessary to reduce analyzer fouling 
during the restart procedure. This procedure may also be used for 1988-
1989 Ford Motor Company vehicles but should not be used for other 
vehicles.
    (ii) The mode timer shall reset (mt=0) when the vehicle engine speed 
is between 2200 and 2800 rpm. If the engine speed falls below 2200 rpm 
or exceeds 2800 rpm for more than two seconds in one excursion, or more

[[Page 355]]

than six seconds over all excursions within 30 seconds of the final 
measured value used in the pass/fail determination, the measured value 
shall be invalidated and the mode continued. The minimum second-chance 
high-speed mode length shall be determined as described in paragraphs 
(VI)(d)(2) (iii) and (iv) of this appendix. If any excursion lasts for 
more than ten seconds, the mode timer shall reset to zero (mt=0) and 
timing resumed. The maximum second-chance high-speed mode length shall 
be 180 seconds elapsed time (mt=180).
    (iii) In the case where the second-chance high-speed mode is not 
followed by the second-chance idle mode, the pass/fail analysis shall 
begin after an elapsed time of 10 seconds (mt=10). A pass or fail 
determination shall be made for the vehicle and the mode shall be 
terminated as follows:
    (A) The vehicle shall pass the high-speed mode and the test shall be 
immediately terminated if, prior to an elapsed time of 30 seconds 
(mt=30), measured values are less than or equal to 100 ppm HC and 0.5 
percent CO.
    (B) The vehicle shall pass the high-speed mode and the test shall be 
terminated if at the end of an elapsed time of 30 seconds (mt=30) if, 
prior to that time, the criteria of paragraph (VI)(d)(2)(iii)(A) of this 
appendix are not satisfied, and the measured values are less than or 
equal to the applicable short test standards as described in paragraph 
(VI)(a)(2) of this appendix.
    (C) The vehicle shall pass the high-speed mode and the test shall be 
immediately terminated if, at any point between an elapsed time for 30 
seconds (mt=30) and 180 seconds (mt=180), the measured values are less 
than or equal to the applicable short test standards as described in 
paragraph (VI)(a)(2) of this appendix.
    (D) The vehicle shall fail the high-speed mode and the test shall be 
terminated if none of the provisions of paragraphs (VI)(d)(2)(iii) (A), 
(B), and (C) of this appendix is satisfied by an elapsed time of 180 
seconds (mt=180).
    (iv) In the case where the second-chance high-speed mode is followed 
by the second-chance idle mode, the pass/fail analysis shall begin after 
an elapsed time of 10 seconds (mt=10). A pass or fail determination 
shall be made for the vehicle and the mode shall be terminated as 
follows:
    (A) The vehicle shall pass the high-speed mode and the mode shall be 
terminated at the end of an elapsed time of 180 seconds (mt=180) if any 
measured values are less than or equal to the applicable short test 
standards as described in paragraph (VI)(a)(2) of this appendix.
    (B) The vehicle shall fail the high-speed mode and the mode shall be 
terminated if paragraph (VI)(d)(2)(iv)(A) of this appendix is not 
satisfied by an elapsed time of 180 seconds (mt=180).
    (3) Second-chance preconditioning mode. The mode timer shall start 
(mt=0) when engine speed is between 2200 and 2800 rpm. The mode shall 
continue for an elapsed time of 180 seconds (mt=180). If the engine 
speed falls below 2200 rpm or exceeds 2800 rpm for more than five 
seconds in any one excursion, or 15 seconds over all excursions, the 
mode timer shall reset to zero and resume timing.
    (4) Second-chance idle mode--(i) Ford Motor Company and Honda 
vehicles. The engines of 1981-1987 Ford Motor Company vehicles and 1984-
1985 Honda Preludes shall be shut off for not more than 10 seconds and 
then shall be restarted. The probe may be removed from the tailpipe or 
the sample pump turned off if necessary to reduce analyzer fouling 
during the restart procedure. This procedure may also be used for 1988-
1989 Ford Motor Company vehicles but should not be used for other 
vehicles.
    (ii) The mode timer shall start (mt=0) when the vehicle engine speed 
is between 350 and 1100 rpm. If the engine exceeds 1100 rpm or falls 
below 350 rpm the mode timer shall reset to zero and resume timing. The 
minimum second-chance idle mode length shall be determined as described 
in paragraph (VI)(d)(4)(iii) of this appendix. The maximum second-chance 
idle mode length shall be 90 seconds elapsed time (mt=90).
    (iii) The pass/fail analysis shall begin after an elapsed time of 10 
seconds (mt=10). A pass or fail determination shall be made for the 
vehicle and the mode shall be terminated as follows:
    (A) The vehicle shall pass the second-chance idle mode and the test 
shall be immediately terminated if, prior to an elapsed time of 30 
seconds (mt=30), measured values are less than or equal to 100 ppm HC 
and 0.5 percent CO.
    (B) The vehicle shall pass the second-chance idle mode and the test 
shall be terminated at the end of an elapsed time of 30 seconds (mt=30) 
if, prior to that time, the criteria of paragraph (VI)(d)(4)(iii)(A) of 
this appendix are not satisfied, and the measured values are less than 
or equal to the applicable short test standards as described in 
paragraph (VI)(a)(2) of this appendix.
    (C) The vehicle shall pass the second-chance idle mode and the test 
shall be immediately terminated if, at any point between an elapsed time 
of 30 seconds (mt=30) and 90 seconds (mt=90), measured values are less 
than or equal to the applicable short test standards described in 
paragraph (VI)(a)(2) of this appendix.
    (D) The vehicle shall fail the second-chance idle mode and the test 
shall be terminated if none of the provisions of paragraphs

[[Page 356]]

(VI)(d)(4)(iii) (A), (B), and (C) of this appendix is satisfied by an 
elapsed time of 90 seconds (mt=90).

[ 57 FR 52987, Nov. 5, 1992, as amended at 61 FR 40946, Aug. 6, 1996]

  Appendix C to Subpart S of Part 51--Steady-State Short Test Standards

   (I) Short Test Standards for 1981 and Later Model Year Light-Duty 
                                Vehicles

    For 1981 and later model year light-duty vehicles for which any of 
the test procedures described in appendix B to this subpart are utilized 
to establish Emissions Performance Warranty eligibility (i.e., 1981 and 
later model year light-duty vehicles at low altitude and 1982 and later 
model year vehicles at high altitude to which high altitude 
certification standards of 1.5 gpm HC and 15 gpm CO or less apply), 
short test emissions for all tests and test modes shall not exceed:
    (a) Hydrocarbons: 220 ppm as hexane.
    (b) Carbon monoxide: 1.2%.

   (II) Short Test Standards for 1981 and Later Model Year Light-Duty 
                                 Trucks

    For 1981 and later model year light-duty trucks for which any of the 
test procedures described in appendix B to this subpart are utilized to 
establish Emissions Performance Warranty eligibility (i.e., 1981 and 
later model year light-duty trucks at low altitude and 1982 and later 
model year trucks at high altitude to which high altitude certification 
standards of 2.0 gpm HC and 26 gpm CO or less apply), short test 
emissions for all tests and test modes shall not exceed:
    (a) Hydrocarbons: 220 ppm as hexane.
    (b) Carbon monoxide: 1.2%.

  Appendix D to Subpart S of Part 51--Steady-State Short Test Equipment

              (I) Steady-State Test Exhaust Analysis System

    (a) Sampling system--(1) General requirements. The sampling system 
for steady-state short tests shall, at a minimum, consist of a tailpipe 
probe, a flexible sample line, a water removal system, particulate trap, 
sample pump, flow control components, tachometer or dynamometer, 
analyzers for HC, CO, and CO2, and digital displays for 
exhaust concentrations of HC, CO, and CO2, and engine rpm. 
Materials that are in contact with the gases sampled shall not 
contaminate or change the character of the gases to be analyzed, 
including gases from alcohol fueled vehicles. The probe shall be capable 
of being inserted to a depth of at least ten inches into the tailpipe of 
the vehicle being tested, or into an extension boot if one is used. A 
digital display for dynamometer speed and load shall be included if the 
test procedures described in appendix B to this subpart, paragraphs 
(III) and (V), are conducted. Minimum specifications for optional NO 
analyzers are also described in this appendix. The analyzer system shall 
be able to test, as specified in at least one section in appendix B to 
this subpart, all model vehicles in service at the time of sale of the 
analyzer.
    (2) Temperature operating range. The sampling system and all 
associated hardware shall be of a design certified to operate within the 
performance specifications described in paragraph (I)(b) of this 
appendix in ambient air temperatures ranging from 41 to 110 degrees 
Fahrenheit. The analyzer system shall, where necessary, include features 
to keep the sampling system within the specified range.
    (3) Humidity operating range. The sampling system and all associated 
hardware shall be of a design certified to operate within the 
performance specifications described in paragraph (I)(b) of this 
appendix at a minimum of 80 percent relative humidity throughout the 
required temperature range.
    (4) Barometric pressure compensation. Barometric pressure 
compensation shall be provided. Compensation shall be made for 
elevations up to 6,000 feet (above mean sea level). At any given 
altitude and ambient conditions specified in paragraph (I)(b) of this 
appendix, errors due to barometric pressure changes of 2 inches of mercury shall not exceed the accuracy limits 
specified in paragraph (I)(b) of this appendix.
    (5) Dual sample probe requirements. When testing a vehicle with dual 
exhaust pipes, a dual sample probe of a design certified by the analyzer 
manufacturer to provide equal flow in each leg shall be used. The equal 
flow requirement is considered to be met if the flow rate in each leg of 
the probe has been measured under two sample pump flow rates (the normal 
rate and a rate equal to the onset of low flow), and if the flow rates 
in each of the legs are found to be equal to each other (within 15% of 
the flow rate in the leg having lower flow).
    (6) System lockout during warm-up. Functional operation of the gas 
sampling unit shall remain disabled through a system lockout until the 
instrument meets stability and warm-up requirements. The instrument 
shall be considered ``warmed up'' when the zero and span readings for 
HC, CO, and CO2 have stabilized, within 3% of the full range of low scale, for five minutes 
without adjustment.
    (7) Electromagnetic isolation and interference. Electromagnetic 
signals found in an automotive service environment shall not cause 
malfunctions or changes in the accuracy in the electronics of the 
analyzer system. The instrument design shall ensure that readings do not 
vary as a result of electromagnetic radiation and induction devices 
normally found in the automotive service environment, including high 
energy vehicle ignition

[[Page 357]]

systems, radio frequency transmission radiation sources, and building 
electrical systems.
    (8) Vibration and shock protection. System operation shall be 
unaffected by the vibration and shock encountered under the normal 
operating conditions encountered in an automotive service environment.
    (9) Propane equivalency factor. The propane equivalency factor shall 
be displayed in a manner that enables it to be viewed conveniently, 
while permitting it to be altered only by personnel specifically 
authorized to do so.
    (b) Analyzers--(1) Accuracy. The analyzers shall be of a design 
certified to meet the following accuracy requirements when calibrated to 
the span points specified in appendix A to this subpart:

------------------------------------------------------------------------
           Channel               Range    Accuracy  Noise  Repeatability
------------------------------------------------------------------------
HC, ppm.....................  0-400       2 analyzers shall not exceed eight seconds 
to 90% of a step change in input. For NO analyzers, the response time 
shall not exceed twelve seconds to 90% of a step change in input.
    (4) Display refresh rate. Dynamic information being displayed shall 
be refreshed at a minimum rate of twice per second.
    (5) Interference effects. The interference effects for non-interest 
gases shall not exceed 10 ppm for hydrocarbons, 
0.05 percent for carbon monoxide, 0.20 percent for carbon dioxide, and 20 ppm for oxides of nitrogen.
    (6) Low flow indication. The analyzer shall provide an indication 
when the sample flow is below the acceptable level. The sampling system 
shall be equipped with a flow meter (or equivalent) that shall indicate 
sample flow degradation when meter error exceeds three percent of full 
scale, or causes system response time to exceed 13 seconds to 90 percent 
of a step change in input, whichever is less.
    (7) Engine speed detection. The analyzer shall utilize a tachometer 
capable of detecting engine speed in revolutions per minute (rpm) with a 
0.5 second response time and an accuracy of 3% of 
the true rpm.
    (8) Test and mode timers. The analyzer shall be capable of 
simultaneously determining the amount of time elapsed in a test, and in 
a mode within that test.
    (9) Sample rate. The analyzer shall be capable of measuring exhaust 
concentrations of gases specified in this section at a minimum rate of 
twice per second.
    (c) Demonstration of conformity. The analyzer shall be demonstrated 
to the satisfaction of the inspection program manager, through 
acceptance testing procedures, to meet the requirements of this section 
and that it is capable of being maintained as required in appendix A to 
this subpart.

                   (II) Steady-State Test Dynamometer

    (a) The chassis dynamometer for steady-state short tests shall 
provide the following capabilities:
    (1) Power absorption. The dynamometer shall be capable of applying a 
load to the vehicle's driving tire surfaces at the horsepower and speed 
levels specified in paragraph (II)(b) of this appendix.
    (2) Short-term stability. Power absorption at constant speed shall 
not drift more than 0.5 horsepower (hp) during any 
single test mode.
    (3) Roll weight capacity. The dynamometer shall be capable of 
supporting a driving axle weight up to four thousand (4,000) pounds or 
greater.
    (4) Between roll wheel lifts. These shall be controllable and 
capable of lifting a minimum of four thousand (4,000) pounds.
    (5) Roll brakes. Both rolls shall be locked when the wheel lift is 
up.
    (6) Speed indications. The dynamometer speed display shall have a 
range of 0-60 mph, and a resolution and accuracy of at least 1 mph.
    (7) Safety interlock. A roll speed sensor and safety interlock 
circuit shall be provided which prevents the application of the roll 
brakes and upward lift movement at any roll speed above 0.5 mph.
    (b) The dynamometer shall produce the load speed relationships 
specified in paragraphs (III) and (V) of appendix B to this subpart.

           (III) Transient Emission Test Equipment [Reserved]

         (IV) Evaporative System Purge Test Equipment [Reserved]

       (V) Evaporative System Integrity Test Equipment [Reserved]

[57 FR 52987, Nov. 5, 1992, as amended at 58 FR 59367, Nov. 9, 1993]

[[Page 358]]

    Appendix E to Subpart S of Part 51--Transient Test Driving Cycle

    (I) Driver's trace. All excursions in the transient driving cycle 
shall be evaluated by the procedures defined in Sec. 86.115-78(b)(1) 
and Sec. 86.115(c) of this chapter. Excursions exceeding these limits 
shall cause a test to be void. In addition, provisions shall be 
available to utilize cycle validation criteria, as described in Sec. 
86.1341-90 of this chapter, for trace speed versus actual speed as a 
means to determine a valid test.
    (II) Driving cycle. The following table shows the time speed 
relationship for the transient IM240 test procedure.

------------------------------------------------------------------------
                             Second                                MPH
------------------------------------------------------------------------
0..............................................................     0
1..............................................................     0
2..............................................................     0
3..............................................................     0
4..............................................................     0
5..............................................................     3
6..............................................................     5.9
7..............................................................     8.6
8..............................................................    11.5
9..............................................................    14.3
10.............................................................    16.9
11.............................................................    17.3
12.............................................................    18.1
13.............................................................    20.7
14.............................................................    21.7
15.............................................................    22.4
16.............................................................    22.5
17.............................................................    22.1
18.............................................................    21.5
19.............................................................    20.9
20.............................................................    20.4
21.............................................................    19.8
22.............................................................    17
23.............................................................    14.9
24.............................................................    14.9
25.............................................................    15.2
26.............................................................    15.5
27.............................................................    16
28.............................................................    17.1
29.............................................................    19.1
30.............................................................    21.1
31.............................................................    22.7
32.............................................................    22.9
33.............................................................    22.7
34.............................................................    22.6
35.............................................................    21.3
36.............................................................    19
37.............................................................    17.1
38.............................................................    15.8
39.............................................................    15.8
40.............................................................    17.7
41.............................................................    19.8
42.............................................................    21.6
43.............................................................    23.2
44.............................................................    24.2
45.............................................................    24.6
46.............................................................    24.9
47.............................................................    25
48.............................................................    25.7
49.............................................................    26.1
50.............................................................    26.7
51.............................................................    27.5
52.............................................................    28.6
53.............................................................    29.3
54.............................................................    29.8
55.............................................................    30.1
56.............................................................    30.4
57.............................................................    30.7
58.............................................................    30.7
59.............................................................    30.5
60.............................................................    30.4
61.............................................................    30.3
62.............................................................    30.4
63.............................................................    30.8
64.............................................................    30.4
65.............................................................    29.9
66.............................................................    29.5
67.............................................................    29.8
68.............................................................    30.3
69.............................................................    30.7
70.............................................................    30.9
71.............................................................    31
72.............................................................    30.9
73.............................................................    30.4
74.............................................................    29.8
75.............................................................    29.9
76.............................................................    30.2
77.............................................................    30.7
78.............................................................    31.2
79.............................................................    31.8
80.............................................................    32.2
81.............................................................    32.4
82.............................................................    32.2
83.............................................................    31.7
84.............................................................    28.6
85.............................................................    25.1
86.............................................................    21.6
87.............................................................    18.1
88.............................................................    14.6
89.............................................................    11.1
90.............................................................     7.6
91.............................................................     4.1
92.............................................................     0.6
93.............................................................     0
94.............................................................     0
95.............................................................     0
96.............................................................     0
97.............................................................     0
98.............................................................     3.3
99.............................................................     6.6
100............................................................     9.9
101............................................................    13.2
102............................................................    16.5
103............................................................    19.8
104............................................................    22.2
105............................................................    24.3
106............................................................    25.8
107............................................................    26.4
108............................................................    25.7
109............................................................    25.1
110............................................................    24.7
111............................................................    25.2
112............................................................    25.4
113............................................................    27.2
114............................................................    26.5
115............................................................    24
116............................................................    22.7
117............................................................    19.4
118............................................................    17.7
119............................................................    17.2
120............................................................    18.1
121............................................................    18.6
122............................................................    20
123............................................................    20.7
124............................................................    21.7
125............................................................    22.4
126............................................................    22.5
127............................................................    22.1
128............................................................    21.5

[[Page 359]]

 
129............................................................    20.9
130............................................................    20.4
131............................................................    19.8
132............................................................    17
133............................................................    17.1
134............................................................    15.8
135............................................................    15.8
136............................................................    17.7
137............................................................    19.8
138............................................................    21.6
139............................................................    22.2
140............................................................    24.5
141............................................................    24.7
142............................................................    24.8
143............................................................    24.7
144............................................................    24.6
145............................................................    24.6
146............................................................    25.1
147............................................................    25.6
148............................................................    25.7
149............................................................    25.4
150............................................................    24.9
151............................................................    25
152............................................................    25.4
153............................................................    26
154............................................................    26
155............................................................    25.7
156............................................................    26.1
157............................................................    26.7
158............................................................    27.3
159............................................................    30.5
160............................................................    33.5
161............................................................    36.2
162............................................................    37.3
163............................................................    39.3
164............................................................    40.5
165............................................................    42.1
166............................................................    43.5
167............................................................    45.1
168............................................................    46
169............................................................    46.8
170............................................................    47.5
171............................................................    47.5
172............................................................    47.3
173............................................................    47.2
174............................................................    47.2
175............................................................    47.4
176............................................................    47.9
177............................................................    48.5
178............................................................    49.1
179............................................................    49.5
180............................................................    50
181............................................................    50.6
182............................................................    51
183............................................................    51.5
184............................................................    52.2
185............................................................    53.2
186............................................................    54.1
187............................................................    54.6
188............................................................    54.9
189............................................................    55
190............................................................    54.9
191............................................................    54.6
192............................................................    54.6
193............................................................    54.8
194............................................................    55.1
195............................................................    55.5
196............................................................    55.7
197............................................................    56.1
198............................................................    56.3
199............................................................    56.6
200............................................................    56.7
201............................................................    56.7
202............................................................    56.3
203............................................................    56
204............................................................    55
205............................................................    53.4
206............................................................    51.6
207............................................................    51.8
208............................................................    52.1
209............................................................    52.5
210............................................................    53
211............................................................    53.5
212............................................................    54
213............................................................    54.9
214............................................................    55.4
215............................................................    55.6
216............................................................    56
217............................................................    56
218............................................................    55.8
219............................................................    55.2
220............................................................    54.5
221............................................................    53.6
222............................................................    52.5
223............................................................    51.5
224............................................................    50.5
225............................................................    48
226............................................................    44.5
227............................................................    41
228............................................................    37.5
229............................................................    34
230............................................................    30.5
231............................................................    27
232............................................................    23.5
233............................................................    20
234............................................................    16.5
235............................................................    13
236............................................................     9.5
237............................................................     6
238............................................................     2.5
239............................................................     0
------------------------------------------------------------------------


[57 FR 52987, Nov. 5, 1992, as amended at 58 FR 59367, Nov. 9, 1993]



    Subpart T_Conformity to State or Federal Implementation Plans of 
   Transportation Plans, Programs, and Projects Developed, Funded or 
       Approved Under Title 23 U.S.C. or the Federal Transit Laws



Sec. 51.390  Implementation plan revision.

    (a) States with areas subject to this subpart and part 93, subpart 
A, of this chapter must submit to the EPA and DOT a revision to their 
implementation plan which contains criteria and procedures for DOT, MPOs 
and other State or local agencies to assess the conformity of 
transportation plans, programs, and projects, consistent with this 
subpart and part 93, subpart A, of this chapter. This revision is to be 
submitted by November 25, 1994 (or within 12 months of an area's 
redesignation from attainment to nonattainment, if the State has not 
previously submitted

[[Page 360]]

such a revision). Further revisions to the implementation plan required 
by amendments to part 93, subpart A, of this chapter must be submitted 
within 12 months of the date of publication of such final amendments. 
EPA will provide DOT with a 30-day comment period before taking action 
to approve or disapprove the submission. A State's conformity provisions 
may contain criteria and procedures more stringent than the requirements 
described in this subpart and part 93, subpart A, of this chapter only 
if the State's conformity provisions apply equally to non-federal as 
well as Federal entities.
    (b) The Federal conformity rules under part 93, subpart A, of this 
chapter, in addition to any existing applicable State requirements, 
establish the conformity criteria and procedures necessary to meet the 
requirements of Clean Air Act section 176(c) until such time as EPA 
approves the conformity implementation plan revision required by this 
subpart. Following EPA approval of the State conformity provisions (or a 
portion thereof) in a revision to the applicable implementation plan, 
conformity determinations would be governed by the approved (or approved 
portion of the) State criteria and procedures. The Federal conformity 
regulations contained in part 93, subpart A, of this chapter would apply 
only for the portion, if any, of the State's conformity provisions that 
is not approved by EPA. In addition, any previously applicable 
implementation plan conformity requirements remain enforceable until the 
State submits a revision to its applicable implementation plan to 
specifically remove them and that revision is approved by EPA.
    (c) The implementation plan revision required by this section must 
meet all of the requirements of part 93, subpart A, of this chapter.
    (d) In order for EPA to approve the implementation plan revision 
submitted to EPA and DOT under this subpart, the plan must address all 
requirements of part 93, subpart A, of this chapter in a manner which 
gives them full legal effect. In particular, the revision shall 
incorporate the provisions of the following sections of part 93, subpart 
A, of this chapter in verbatim form, except insofar as needed to clarify 
or to give effect to a stated intent in the revision to establish 
criteria and procedures more stringent than the requirements stated in 
the following sections of this chapter: Sec. Sec. 93.101, 93.102, 
93.103, 93.104, 93.106, 93.109, 93.110, 93.111, 93.112, 93.113, 93.114, 
93.115, 93.116, 93.117, 93.118, 93.119, 93.120, 93.121, 93.126, and 
93.127.

[62 FR 43801, Aug. 15, 1997]



                  Subpart U_Economic Incentive Programs

    Source: 59 FR 16710, Apr. 7, 1994, unless otherwise noted.



Sec. 51.490  Applicability.

    (a) The rules in this subpart apply to any statutory economic 
incentive program (EIP) submitted to the EPA as an implementation plan 
revision to comply with sections 182(g)(3), 182(g)(5), 187(d)(3), or 
187(g) of the Act. Such programs may be submitted by any authorized 
governmental organization, including States, local governments, and 
Indian governing bodies.
    (b) The provisions contained in these rules, except as explicitly 
exempted, shall also serve as the EPA's policy guidance on discretionary 
EIP's submitted as implementation plan revisions for any purpose other 
than to comply with the statutory requirements specified in paragraph 
(a) of this section.



Sec. 51.491  Definitions.

    Act means the Clean Air Act as amended November 15, 1990.
    Actual emissions means the emissions of a pollutant from an affected 
source determined by taking into account actual emission rates 
associated with normal source operation and actual or representative 
production rates (i.e., capacity utilization and hours of operation).
    Affected source means any stationary, area, or mobile source of a 
criteria pollutant(s) to which an EIP applies. This term applies to 
sources explicitly included at the start of a program, as well as 
sources that voluntarily enter (i.e., opt into) the program.

[[Page 361]]

    Allowable emissions means the emissions of a pollutant from an 
affected source determined by taking into account the most stringent of 
all applicable SIP emissions limits and the level of emissions 
consistent with source compliance with all Federal requirements related 
to attainment and maintenance of the NAAQS and the production rate 
associated with the maximum rated capacity and hours of operation 
(unless the source is subject to federally enforceable limits which 
restrict the operating rate, or hours of operation, or both).
    Area sources means stationary and nonroad sources that are too small 
and/or too numerous to be individually included in a stationary source 
emissions inventory.
    Attainment area means any area of the country designated or 
redesignated by the EPA at 40 CFR part 81 in accordance with section 
107(d) as having attained the relevant NAAQS for a given criteria 
pollutant. An area can be an attainment area for some pollutants and a 
nonattainment area for other pollutants.
    Attainment demonstration means the requirement in section 
182(b)(1)(A) of the Act to demonstrate that the specific annual 
emissions reductions included in a SIP are sufficient to attain the 
primary NAAQS by the date applicable to the area.
    Directionally-sound strategies are strategies for which adequate 
procedures to quantify emissions reductions or specify a program 
baseline are not defined as part of the EIP.
    Discretionary economic incentive program means any EIP submitted to 
the EPA as an implementation plan revision for purposes other than to 
comply with the statutory requirements of sections 182(g)(3), 182(g)(5), 
187(d)(3), or 187(g) of the Act.
    Economic incentive program (EIP) means a program which may include 
State established emission fees or a system of marketable permits, or a 
system of State fees on sale or manufacture of products the use of which 
contributes to O3 formation, or any combination of the 
foregoing or other similar measures, as well as incentives and 
requirements to reduce vehicle emissions and vehicle miles traveled in 
the area, including any of the transportation control measures 
identified in section 108(f). Such programs may be directed toward 
stationary, area, and/or mobile sources, to achieve emissions reductions 
milestones, to attain and maintain ambient air quality standards, and/or 
to provide more flexible, lower-cost approaches to meeting environmental 
goals. Such programs are categorized into the following three 
categories: Emission-limiting, market-response, and directionally-sound 
strategies.
    Emission-limiting strategies are strategies that directly specify 
limits on total mass emissions, emission-related parameters (e.g., 
emission rates per unit of production, product content limits), or 
levels of emissions reductions relative to a program baseline that are 
required to be met by affected sources, while providing flexibility to 
sources to reduce the cost of meeting program requirements.
    Indian governing body means the governing body of any tribe, band, 
or group of Indians subject to the jurisdiction of the U.S. and 
recognized by the U.S. as possessing power of self-government.
    Maintenance plan means an implementation plan for an area for which 
the State is currently seeking designation or has previously sought 
redesignation to attainment, under section 107(d) of the Act, which 
provides for the continued attainment of the NAAQS.
    Market-response strategies are strategies that create one or more 
incentives for affected sources to reduce emissions, without directly 
specifying limits on emissions or emission-related parameters that 
individual sources or even all sources in the aggregate are required to 
meet.
    Milestones means the reductions in emissions required to be achieved 
pursuant to section 182(b)(1) and the corresponding requirements in 
section 182(c)(2) (B) and (C), 182(d), and 182(e) of the Act for 
O3 nonattainment areas, as well as the reduction in emissions 
of CO equivalent to the total of the specified annual emissions 
reductions required by December 31, 1995, pursuant to section 187(d)(1).
    Mobile sources means on-road (highway) vehicles (e.g., automobiles, 
trucks

[[Page 362]]

and motorcycles) and nonroad vehicles (e.g., trains, airplanes, 
agricultural equipment, industrial equipment, construction vehicles, 
off-road motorcycles, and marine vessels).
    National ambient air quality standard (NAAQS) means a standard set 
by the EPA at 40 CFR part 50 under section 109 of the Act.
    Nonattainment area means any area of the country designated by the 
EPA at 40 CFR part 81 in accordance with section 107(d) of the Act as 
nonattainment for one or more criteria pollutants. An area could be a 
nonattainment area for some pollutants and an attainment area for other 
pollutants.
    Nondiscriminatory means that a program in one State does not result 
in discriminatory effects on other States or sources outside the State 
with regard to interstate commerce.
    Program baseline means the level of emissions, or emission-related 
parameter(s), for each affected source or group of affected sources, 
from which program results (e.g., quantifiable emissions reductions) 
shall be determined.
    Program uncertainty factor means a factor applied to discount the 
amount of emissions reductions credited in an implementation plan 
demonstration to account for any strategy-specific uncertainties in an 
EIP.
    Reasonable further progress (RFP) plan means any incremental 
emissions reductions required by the CAA (e.g., section 182(b)) and 
approved by the EPA as meeting these requirements.
    Replicable refers to methods which are sufficiently unambiguous such 
that the same or equivalent results would be obtained by the application 
of the methods by different users.
    RFP baseline means the total of actual volatile organic compounds or 
nitrogen oxides emissions from all anthropogenic sources in an 
O3 nonattainment area during the calendar year 1990 (net of 
growth and adjusted pursuant to section 182(b)(1)(B) of the Act), 
expressed as typical O3 season, weekday emissions.
    Rule compliance factor means a factor applied to discount the amount 
of emissions reductions credited in an implementation plan demonstration 
to account for less-than-complete compliance by the affected sources in 
an EIP.
    Shortfall means the difference between the amount of emissions 
reductions credited in an implementation plan for a particular EIP and 
those that are actually achieved by that EIP, as determined through an 
approved reconciliation process.
    State means State, local government, or Indian-governing body.
    State implementation plan (SIP) means a plan developed by an 
authorized governing body, including States, local governments, and 
Indian-governing bodies, in a nonattainment area, as required under 
titles I & II of the Clean Air Act, and approved by the EPA as meeting 
these same requirements.
    Stationary source means any building, structure, facility or 
installation, other than an area or mobile source, which emits or may 
emit any criteria air pollutant or precursor subject to regulation under 
the Act.
    Statutory economic incentive program means any EIP submitted to the 
EPA as an implementation plan revision to comply with sections 
182(g)(3), 182(g)(5), 187(d)(3), or 187(g) of the Act.
    Surplus means, at a minimum, emissions reductions in excess of an 
established program baseline which are not required by SIP requirements 
or State regulations, relied upon in any applicable attainment plan or 
demonstration, or credited in any RFP or milestone demonstration, so as 
to prevent the double-counting of emissions reductions.
    Transportation control measure (TCM) is any measure of the types 
listed in section 108(F) of the Act, or any measure in an applicable 
implementation plan directed toward reducing emissions of air pollutants 
from transportation sources by a reduction in vehicle use or changes in 
traffic conditions.



Sec. 51.492  State program election and submittal.

    (a) Extreme O3 nonattainment areas. (1) A State or 
authorized governing body for any extreme O3 nonattainment 
area shall submit a plan revision to implement an EIP, in accordance 
with the requirements of this part, pursuant to section 182(g)(5) of the 
Act, if:

[[Page 363]]

    (i) A required milestone compliance demonstration is not submitted 
within the required period.
    (ii) The Administrator determines that the area has not met any 
applicable milestone.
    (2) The plan revision in paragraph (a)(1) of this section shall be 
submitted within 9 months after such failure or determination, and shall 
be sufficient, in combination with other elements of the SIP, to achieve 
the next milestone.
    (b) Serious CO nonattainment areas. (1) A State or authorized 
governing body for any serious CO nonattainment area shall submit a plan 
revision to implement an EIP, in accordance with the requirements of 
this part, if:
    (i) A milestone demonstration is not submitted within the required 
period, pursuant to section 187(d) of the Act.
    (ii) The Administrator notifies the State, pursuant to section 
187(d) of the Act, that a milestone has not been met.
    (iii) The Administrator determines, pursuant to section 186(b)(2) of 
the Act that the NAAQS for CO has not been attained by the applicable 
date for that area. Such revision shall be submitted within 9 months 
after such failure or determination.
    (2) Submittals made pursuant to paragraphs (b)(1) (i) and (ii) of 
this section shall be sufficient, together with a transportation control 
program, to achieve the specific annual reductions in CO emissions set 
forth in the implementation plan by the attainment date. Submittals made 
pursuant to paragraph (b)(1)(iii) of this section shall be adequate, in 
combination with other elements of the revised plan, to reduce the total 
tonnage of emissions of CO in the area by at least 5 percent per year in 
each year after approval of the plan revision and before attainment of 
the NAAQS for CO.
    (c) Serious and severe O3 nonattainment areas. If a 
State, for any serious or severe O3 nonattainment area, 
elects to implement an EIP in the circumstances set out in section 
182(g)(3) of the Act, the State shall submit a plan revision to 
implement the program in accordance with the requirements of this part. 
If the option to implement an EIP is elected, a plan revision shall be 
submitted within 12 months after the date required for election, and 
shall be sufficient, in combination with other elements of the SIP, to 
achieve the next milestone.
    (d) Any nonattainment or attainment area. Any State may at any time 
submit a plan or plan revision to implement a discretionary EIP, in 
accordance with the requirements of this part, pursuant to sections 
110(a)(2)(A) and 172(c)(6) and other applicable provisions of the Act 
concerning SIP submittals. The plan revision shall not interfere with 
any applicable requirement concerning attainment and RFP, or any other 
applicable requirements of the Act.



Sec. 51.493  State program requirements.

    Economic incentive programs shall be State and federally 
enforceable, nondiscriminatory, and consistent with the timely 
attainment of NAAQS, all applicable RFP and visibility requirements, 
applicable PSD increments, and all other applicable requirements of the 
Act. Programs in nonattainment areas for which credit is taken in 
attainment and RFP demonstrations shall be designed to ensure that the 
effects of the program are quantifiable and permanent over the entire 
duration of the program, and that the credit taken is limited to that 
which is surplus. Statutory programs shall be designed to result in 
quantifiable, significant reductions in actual emissions. The EIP's 
shall include the following elements, as applicable:
    (a) Statement of goals and rationale. This element shall include a 
clear statement as to the environmental problem being addressed, the 
intended environmental and economic goals of the program, and the 
rationale relating the incentive-based strategy to the program goals.
    (1) The statement of goals must include the goal that the program 
will benefit both the environment and the regulated entities. The 
program shall be designed so as to meaningfully meet this goal either 
directly, through increased or more rapid emissions reductions beyond 
those that would be achieved through a traditional regulatory program, 
or, alternatively, through other approaches that will result in real 
environmental benefits.

[[Page 364]]

Such alternative approaches include, but are not limited to, improved 
administrative mechanisms, reduced administrative burdens on regulatory 
agencies, improved emissions inventories, and the adoption of emission 
caps which over time constrain or reduce growth-related emissions beyond 
traditional regulatory approaches.
    (2) The incentive-based strategy shall be described in terms of one 
of the following three strategies:
    (i) Emission-limiting strategies, which directly specify limits on 
total mass emissions, emission-related parameters (e.g., emission rates 
per unit of production, product content limits), or levels of emissions 
reductions relative to a program baseline that affected sources are 
required to meet, while providing flexibility to sources to reduce the 
cost of meeting program requirements.
    (ii) Market-response strategies, which create one or more incentives 
for affected sources to reduce emissions, without directly specifying 
limits on emissions or emission-related parameters that individual 
sources or even all sources in the aggregate are required to meet.
    (iii) Directionally-sound strategies, for which adequate procedures 
to quantify emissions reductions are not defined.
    (b) Program scope. (1) This element shall contain a clear definition 
of the sources affected by the program. This definition shall address:
    (i) The extent to which the program is mandatory or voluntary for 
the affected sources.
    (ii) Provisions, if any, by which sources that are not required to 
be in the program may voluntarily enter the program.
    (iii) Provisions, if any, by which sources covered by the program 
may voluntarily leave the program.
    (2) Any opt-in or opt-out provisions in paragraph (b)(1) of this 
section shall be designed to provide mechanisms by which such program 
changes are reflected in an area's attainment and RFP demonstrations, 
thus ensuring that there will not be an increase in the emissions 
inventory for the area caused by voluntary entry or exit from the 
program.
    (3) The program scope shall be defined so as not to interfere with 
any other Federal requirements which apply to the affected sources.
    (c) Program baseline. A program baseline shall be defined as a basis 
for projecting program results and, if applicable, for initializing the 
incentive mechanism (e.g., for marketable permits programs). The program 
baseline shall be consistent with, and adequately reflected in, the 
assumptions and inputs used to develop an area's RFP plans and 
attainment and maintenance demonstrations, as applicable. The State 
shall provide sufficient supporting information from the areawide 
emissions inventory and other sources to justify the baseline used in 
the EIP.
    (1) For EIP's submitted in conjunction with, or subsequent to, the 
submission of any areawide progress plan due at the time of EIP 
submission (e.g., the 15 percent RFP plan and/or subsequent 3 percent 
plans) or an attainment demonstration, a State may exercise flexibility 
in setting a program baseline provided the program baseline is 
consistent with and reflected in all relevant progress plans or 
attainment demonstration. A flexible program baseline may be based on 
the lower of actual, allowable, or some other intermediate or lower 
level of emissions. For any EIP submitted prior to the submittal of an 
attainment demonstration, the State shall include the following with its 
EIP submittal:
    (i) A commitment that its subsequent attainment demonstration and 
all future progress plans, if applicable, will be consistent with the 
EIP baseline.
    (ii) A discussion of how the baseline will be integrated into the 
subsequent attainment demonstration, taking into account the potential 
that credit issued prior to the attainment demonstration may no longer 
be surplus relative to the attainment demonstration.
    (2) Except as provided for in paragraph (c)(4) of this section, for 
EIP's submitted during a time period when any progress plans are 
required but not yet submitted (e.g., the 15 percent RFP plan and/or the 
subsequent 3 percent plans), the program baseline shall be

[[Page 365]]

based on the lower-of-actual-or-allowable emissions. In such cases, 
actual emissions shall be taken from the most appropriate inventory, 
such as the 1990 actual emission inventory (due for submission in 
November 1992), and allowable emissions are the lower of SIP-allowable 
emissions or the level of emissions consistent with source compliance 
with all Federal requirements related to attainment and maintenance of 
the NAAQS.
    (3) For EIP's that are designed to implement new and/or previously 
existing RACT requirements through emissions trading and are submitted 
in conjunction with, or subsequent to, the submission of an associated 
RACT rule, a State may exercise flexibility in setting a program 
baseline provided the program baseline is consistent with and reflected 
in the associated RACT rule, and any applicable progress plans and 
attainment demonstrations.
    (4) For EIP's that are designed to implement new and/or previously 
existing RACT requirements through emissions trading and are submitted 
prior to the submission of a required RFP plan or attainment 
demonstration, States also have flexibility in determining the program 
baseline, provided the following conditions are met.
    (i) For EIP's that implement new RACT requirements for previously 
unregulated source categories through emissions trading, the new RACT 
requirements must reflect, to the extent practicable, increased 
emissions reductions beyond those that would be achieved through a 
traditional RACT program.
    (ii) For EIP's that impose new RACT requirements on previously 
unregulated sources in a previously regulated source category (e.g., 
RACT ``catch-up'' programs), the new incentive-based RACT rule shall, in 
the aggregate, yield reductions in actual emissions at least equivalent 
to that which would result from source-by-source compliance with the 
existing RACT limit for that source category.
    (5) A program baseline for individual sources shall, as appropriate, 
be contained or incorporated by reference in federally-enforceable 
operating permits or a federally-enforceable SIP.
    (6) An initial baseline for TCM's shall be calculated by 
establishing the preexisting conditions in the areas of interest. This 
may include establishing to what extent TCM's have already been 
implemented, what average vehicle occupancy (AVO) levels have been 
achieved during peak and off-peak periods, what types of trips occur in 
the region, and what mode choices have been made in making these trips. 
In addition, the extent to which travel options are currently available 
within the region of interest shall be determined. These travel options 
may include, but are not limited to, the degree of dispersion of transit 
services, the current ridership rates, and the availability and usage of 
parking facilities.
    (7) Information used in setting a program baseline shall be of 
sufficient quality to provide for at least as high a degree of 
accountability as currently exists for traditional control requirements 
for the categories of sources affected by the program.
    (d) Replicable emission quantification methods. This program 
element, for programs other than those which are categorized as 
directionally-sound, shall include credible, workable, and replicable 
methods for projecting program results from affected sources and, where 
necessary, for quantifying emissions from individual sources subject to 
the EIP. Such methods, if used to determine credit taken in attainment, 
RFP, and maintenance demonstrations, as applicable, shall yield results 
which can be shown to have a level of certainty comparable to that for 
source-specific standards and traditional methods of control strategy 
development. Such methods include, as applicable, the following 
elements:
    (1) Specification of quantification methods. This element shall 
specify the approach or the combination or range of approaches that are 
acceptable for each source category affected by the program. Acceptable 
approaches may include, but are not limited to:
    (i) Test methods for the direct measurement of emissions, either 
continuously or periodically.
    (ii) Calculation equations which are a function of process or 
control system

[[Page 366]]

parameters, ambient conditions, activity levels, and/or throughput or 
production rates.
    (iii) Mass balance calculations which are a function of inventory, 
usage, and/or disposal records.
    (iv) EPA-approved emission factors, where appropriate and adequate.
    (v) Any combination of these approaches.
    (2) Specification of averaging times.
    (i) The averaging time for any specified mass emissions caps or 
emission rate limits shall be consistent with: attaining and maintaining 
all applicable NAAQS, meeting RFP requirements, and ensuring equivalency 
with all applicable RACT requirements.
    (ii) If the averaging time for any specified VOC or NOX 
mass emissions caps or emission rate limits for stationary sources (and 
for other sources, as appropriate) is longer than 24 hours, the State 
shall provide, in support of the SIP submittal, a statistical showing 
that the specified averaging time is consistent with attaining the 
O3 NAAQS and satisfying RFP requirements, as applicable, on 
the basis of typical summer day emissions; and, if applicable, a 
statistical showing that the longer averaging time will produce 
emissions reductions that are equivalent on a daily basis to source-
specific RACT requirements.
    (3) Accounting for shutdowns and production curtailments. This 
accounting shall include provisions which ensure that:
    (i) Emissions reductions associated with shutdowns and production 
curtailments are not double-counted in attainment or RFP demonstrations.
    (ii) Any resultant ``shifting demand'' which increases emissions 
from other sources is accounted for in such demonstrations.
    (4) Accounting for batch, seasonal, and cyclical operations. This 
accounting shall include provisions which ensure that the approaches 
used to account for such variable operations are consistent with 
attainment and RFP plans.
    (5) Accounting for travel mode choice options, as appropriate, for 
TCM's. This accounting shall consider the factors or attributes of the 
different forms of travel modes (e.g., bus, ridesharing) which determine 
which type of travel an individual will choose. Such factors include, 
but are not limited to, time, cost, reliability, and convenience of the 
mode.
    (e) Source requirements. This program element shall include all 
source-specific requirements that constitute compliance with the 
program. Such requirements shall be appropriate, readily ascertainable, 
and State and federally enforceable, including, as applicable:
    (1) Emission limits.
    (i) For programs that impose limits on total mass emissions, 
emission rates, or other emission-related parameter(s), there must be an 
appropriate tracking system so that a facility's limits are readily 
ascertainable at all times.
    (ii) For emission-limiting EIP's that authorize RACT sources to meet 
their RACT requirements through RACT/non-RACT trading, such trading 
shall result in an exceptional environmental benefit. Demonstration of 
an exceptional environmental benefit shall require either the use of the 
statutory offset ratios for nonattainment areas as the determinant of 
the amount of emissions reductions that would be required from non-RACT 
sources generating credits for RACT sources or, alternatively, a trading 
ratio of 1.1 to 1, at a minimum, may be authorized, provided exceptional 
environmental benefits are otherwise demonstrated.
    (2) Monitoring, recordkeeping, and reporting requirements.
    (i) An EIP (or the SIP as a whole) must contain test methods and, 
where necessary, emission quantification methodologies, appropriate to 
the emission limits established in the SIP. EIP sources must be subject 
to clearly specified MRR requirements appropriate to the test methods 
and any applicable quantification methodologies, and consistent with the 
EPA's title V rules, where applicable. Such MRR requirements shall 
provide sufficiently reliable and timely information to determine 
compliance with emission limits and other applicable strategy-specific 
requirements, and to provide for State and Federal enforceability of 
such limits and requirements. Methods

[[Page 367]]

for MRR may include, but are not limited to:
    (A) The continuous monitoring of mass emissions, emission rates, or 
process or control parameters.
    (B) In situ or portable measurement devices to verify control system 
operating conditions.
    (C) Periodic measurement of mass emissions or emission rates using 
reference test methods.
    (D) Operation and maintenance procedures and/or other work practices 
designed to prevent, identify, or remedy noncomplying conditions.
    (E) Manual or automated recordkeeping of material usage, 
inventories, throughput, production, or levels of required activities.
    (F) Any combination of these methods. EIP's shall require that 
responsible parties at each facility in the EIP program certify reported 
information.
    (ii) Procedures for determining required data, including the 
emissions contribution from affected sources, for periods for which 
required data monitoring is not performed, data are otherwise missing, 
or data have been demonstrated to have been inaccurately determined.
    (3) Any other applicable strategy-specific requirements.
    (f) Projected results and audit/reconciliation procedures. (1) The 
SIP submittal shall include projections of the emissions reductions 
associated with the implementation of the program. These projected 
results shall be related to and consistent with the assumptions used to 
develop the area's attainment demonstration and maintenance plan, as 
applicable. For programs designed to produce emissions reductions 
creditable towards RFP milestones, projected emissions reductions shall 
be related to the RFP baseline and consistent with the area's RFP 
compliance demonstration. The State shall provide sufficient supporting 
information that shows how affected sources are or will be addressed in 
the emissions inventory, RFP plan, and attainment demonstration or 
maintenance plan, as applicable.
    (i) For emission-limiting programs, the projected results shall be 
consistent with the reductions in mass emissions or emissions-related 
parameters specified in the program design.
    (ii) For market-response programs, the projected results shall be 
based on market analyses relating levels of targeted emissions and/or 
emission-related activities to program design parameters.
    (iii) For directionally-sound programs, the projected results may be 
descriptive and shall be consistent with the area's attainment 
demonstration or maintenance plan.
    (2) Quantitative projected results shall be adjusted through the use 
of two uncertainty factors, as appropriate, to reflect uncertainties 
inherent in both the extent to which sources will comply with program 
requirements and the overall program design.
    (i) Uncertainty resulting from incomplete compliance shall be 
addressed through the use of a rule compliance factor.
    (ii) Programmatic uncertainty shall be addressed through the use of 
a program uncertainty factor. Any presumptive norms set by the EPA shall 
be used unless an adequate justification for an alternative factor is 
included in supporting information to be supplied with the SIP 
submittal. In the absence of any EPA-specified presumptive norms, the 
State shall provide an adequate justification for the selected factors 
as part of the supporting information to be supplied with the SIP 
submittal.
    (3) Unless otherwise provided in program-specific guidance issued by 
the EPA, EIP's for which SIP credit is taken shall include audit 
procedures to evaluate program implementation and track program results 
in terms of both actual emissions reductions, and, to the extent 
practicable, cost savings relative to traditional regulatory program 
requirements realized during program implementation. Such audits shall 
be conducted at specified time intervals, not to exceed three years. The 
State shall provide timely post-audit reports to the EPA.
    (i) For emission-limiting EIP's, the State shall commit to ensure 
the timely implementation of programmatic revisions or other measures 
which the State, in response to the audit, deems necessary for the 
successful operation

[[Page 368]]

of the program in the context of overall RFP and attainment 
requirements.
    (ii) For market-response EIP's, reconciliation procedures that 
identify a range of appropriate actions or revisions to program 
requirements that will make up for any shortfall between credited 
results (i.e., projected results, as adjusted by the two uncertainty 
factors described above) and actual results obtained during program 
implementation shall be submitted together with the program audit 
provisions. Such measures must be federally enforceable, as appropriate, 
and automatically executing to the extent necessary to make up the 
shortfall within a specified period of time, consistent with relevant 
RFP and attainment requirements.
    (g) Implementation schedule. The program shall contain a schedule 
for the adoption and implementation of all State commitments and source 
requirements included in the program design.
    (h) Administrative procedures. The program shall contain a 
description of State commitments which are integral to the 
implementation of the program, and the administrative system to be used 
to implement the program, addressing the adequacy of the personnel, 
funding, and legislative authority.
    (1) States shall furnish adequate documentation of existing legal 
authority and demonstrated administrative capacity to implement and 
enforce the provisions of the EIP.
    (2) For programs which require private and/or public entities to 
establish emission-related economic incentives (e.g., programs requiring 
employers to exempt carpoolers/multiple occupancy vehicles from paying 
for parking), States shall furnish adequate documentation of State 
authority and administrative capacity to implement and enforce the 
underlying program.
    (i) Enforcement mechanisms. The program shall contain a compliance 
instrument(s) for all program requirements, which is legally binding and 
State and federally enforceable. This program element shall also include 
a State enforcement program which defines violations, and specifies 
auditing and inspections plans and provisions for enforcement actions. 
The program shall contain effective penalties for noncompliance which 
preserve the level of deterrence in traditional programs. For all such 
programs, the manner of collection of penalties must be specified.
    (1) Emission limit violations. (i) Programs imposing limits on mass 
emissions or emission rates that provide for extended averaging times 
and/or compliance on a multisource basis shall include procedures for 
determining the number of violations, the number of days of violation, 
and sources in violation, for statutory maximum penalty purposes, when 
the limits are exceeded. The State shall demonstrate that such 
procedures shall not lessen the incentive for source compliance as 
compared to a program applied on a source-by-source, daily basis.
    (ii) Programs shall require plans for remedying noncompliance at any 
facility that exceeds a multisource emissions limit for a given 
averaging period. These plans shall be enforceable both federally and by 
the State.
    (2) Violations of MRR requirements. The MRR requirements shall apply 
on a daily basis, as appropriate, and violations thereof shall be 
subject to State enforcement sanctions and to the Federal penalty of up 
to $25,000 for each day a violation occurs or continues. In addition, 
where the requisite scienter conditions are met, violations of such 
requirements shall be subject to the Act's criminal penalty sanctions of 
section 113(c)(2), which provides for fines and imprisonment of up to 2 
years.



Sec. 51.494  Use of program revenues.

    Any revenues generated from statutory EIP's shall be used by the 
State for any of the following:
    (a) Providing incentives for achieving emissions reductions.
    (b) Providing assistance for the development of innovative 
technologies for the control of O3 air pollution and for the 
development of lower-polluting solvents and surface coatings. Such 
assistance shall not provide for the payment of more than 75 percent of 
either the costs of any project to develop such a technology or the 
costs of development of a lower-polluting solvent or surface coating.

[[Page 369]]

    (c) Funding the administrative costs of State programs under this 
Act. Not more than 50 percent of such revenues may be used for this 
purpose. The use of any revenues generated from discretionary EIP's 
shall not be constrained by the provisions of this part.



Subpart W_Determining Conformity of General Federal Actions to State or 
                      Federal Implementation Plans

    Source: 58 FR 63247, Nov. 30, 1993, unless otherwise noted.



Sec. 51.850  Prohibition.

    (a) No department, agency or instrumentality of the Federal 
Government shall engage in, support in any way or provide financial 
assistance for, license or permit, or approve any activity which does 
not conform to an applicable implementation plan.
    (b) A Federal agency must make a determination that a Federal action 
conforms to the applicable implementation plan in accordance with the 
requirements of this subpart before the action is taken.
    (c) Paragraph (b) of this section does not include Federal actions 
where either:
    (1) A National Environmental Policy Act (NEPA) analysis was 
completed as evidenced by a final environmental assessment (EA), 
environmental impact statement (EIS), or finding of no significant 
impact (FONSI) that was prepared prior to January 31, 1994;
    (2)(i) Prior to January 31, 1994, an EA was commenced or a contract 
was awarded to develop the specific environmental analysis;
    (ii) Sufficient environmental analysis is completed by March 15, 
1994 so that the Federal agency may determine that the Federal action is 
in conformity with the specific requirements and the purposes of the 
applicable SIP pursuant to the agency's affirmative obligation under 
section 176(c) of the Clean Air Act (Act); and
    (iii) A written determination of conformity under section 176(c) of 
the Act has been made by the Federal agency responsible for the Federal 
action by March 15, 1994.
    (d) Notwithstanding any provision of this subpart, a determination 
that an action is in conformance with the applicable implementation plan 
does not exempt the action from any other requirements of the applicable 
implementation plan, the NEPA, or the Act.



Sec. 51.851  State Implementation Plan (SIP) revision.

    (a) Each State must submit to the Environmental Protection Agency 
(EPA) a revision to its applicable implementation plan which contains 
criteria and procedures for assessing the conformity of Federal actions 
to the applicable implementation plan, consistent with this subpart. The 
State must submit the conformity provisions within 12 months after 
November 30, 1993 or within 12 months of an area's designation to 
nonattainment, whichever date is later.
    (b) The Federal conformity rules under this subpart and 40 CFR part 
93, in addition to any existing applicable State requirements, establish 
the conformity criteria and procedures necessary to meet the Act 
requirements until such time as the required conformity SIP revision is 
approved by EPA. A State's conformity provisions must contain criteria 
and procedures that are no less stringent than the requirements 
described in this subpart. A State may establish more stringent 
conformity criteria and procedures only if they apply equally to non-
Federal as well as Federal entities. Following EPA approval of the State 
conformity provisions (or a portion thereof) in a revision to the 
applicable SIP, the approved (or approved portion of the) State criteria 
and procedures would govern conformity determinations and the Federal 
conformity regulations contained in 40 CFR part 93 would apply only for 
the portion, if any, of the State's conformity provisions that is not 
approved by EPA. In addition, any previously applicable SIP requirements 
relating to conformity remain enforceable until the State revises its 
SIP to specifically remove them from the SIP and that revision is 
approved by EPA.

[[Page 370]]



Sec. 51.852  Definitions.

    Terms used but not defined in this part shall have the meaning given 
them by the Act and EPA's regulations, (40 CFR chapter I), in that order 
of priority.
    Affected Federal land manager means the Federal agency or the 
Federal official charged with direct responsibility for management of an 
area designated as Class I under the Act (42 U.S.C. 7472) that is 
located within 100 km of the proposed Federal action.
    Applicable implementation plan or applicable SIP means the portion 
(or portions) of the SIP or most recent revision thereof, which has been 
approved under section 110 of the Act, or promulgated under section 
110(c) of the Act (Federal implementation plan), or promulgated or 
approved pursuant to regulations promulgated under section 301(d) of the 
Act and which implements the relevant requirements of the Act.
    Areawide air quality modeling analysis means an assessment on a 
scale that includes the entire nonattainment or maintenance area which 
uses an air quality dispersion model to determine the effects of 
emissions on air quality.
    Cause or contribute to a new violation means a Federal action that:
    (1) Causes a new violation of a national ambient air quality 
standard (NAAQS) at a location in a nonattainment or maintenance area 
which would otherwise not be in violation of the standard during the 
future period in question if the Federal action were not taken; or
    (2) Contributes, in conjunction with other reasonably foreseeable 
actions, to a new violation of a NAAQS at a location in a nonattainment 
or maintenance area in a manner that would increase the frequency or 
severity of the new violation.
    Caused by, as used in the terms ``direct emissions'' and ``indirect 
emissions,'' means emissions that would not otherwise occur in the 
absence of the Federal action.
    Criteria pollutant or standard means any pollutant for which there 
is established a NAAQS at 40 CFR part 50.
    Direct emissions means those emissions of a criteria pollutant or 
its precursors that are caused or initiated by the Federal action and 
occur at the same time and place as the action.
    Emergency means a situation where extremely quick action on the part 
of the Federal agencies involved is needed and where the timing of such 
Federal activities makes it impractical to meet the requirements of this 
subpart, such as natural disasters like hurricanes or earthquakes, civil 
disturbances such as terrorist acts, and military mobilizations.
    Emissions budgets are those portions of the applicable SIP's 
projected emissions inventories that describe the levels of emissions 
(mobile, stationary, area, etc.) that provide for meeting reasonable 
further progress milestones, attainment, and/or maintenance for any 
criteria pollutant or its precursors.
    Emissions offsets, for purposes of Sec. 51.858, are emissions 
reductions which are quantifiable, consistent with the applicable SIP 
attainment and reasonable further progress demonstrations, surplus to 
reductions required by, and credited to, other applicable SIP 
provisions, enforceable at both the State and Federal levels, and 
permanent within the timeframe specified by the program.
    Emissions that a Federal agency has a continuing program 
responsibility for means emissions that are specifically caused by an 
agency carrying out its authorities, and does not include emissions that 
occur due to subsequent activities, unless such activities are required 
by the Federal agency. Where an agency, in performing its normal program 
responsibilities, takes actions itself or imposes conditions that result 
in air pollutant emissions by a non-Federal entity taking subsequent 
actions, such emissions are covered by the meaning of a continuing 
program responsibility.
    EPA means the Environmental Protection Agency.
    Federal action means any activity engaged in by a department, 
agency, or instrumentality of the Federal Government, or any activity 
that a department, agency or instrumentality of the Federal Government 
supports in any way, provides financial assistance for, licenses, 
permits, or approves, other than activities related to transportation 
plans, programs, and projects

[[Page 371]]

developed, funded, or approved under title 23 U.S.C. or the Federal 
Transit Act (49 U.S.C. 1601 et seq.). Where the Federal action is a 
permit, license, or other approval for some aspect of a non-Federal 
undertaking, the relevant activity is the part, portion, or phase or the 
non-Federal undertaking that requires the Federal permit, license, or 
approval.
    Federal agency means, for purposes of this subpart, a Federal 
department, agency, or instrumentality of the Federal Government.
    Increase the frequency or severity of any existing violation of any 
standard in any area means to cause a nonattainment area to exceed a 
standard more often or to cause a violation at a greater concentration 
than previously existed and/or would otherwise exist during the future 
period in question, if the project were not implemented.
    Indirect emissions means those emissions of a criteria pollutant or 
its precursors that:
    (1) Are caused by the Federal action, but may occur later in time 
and/or may be farther removed in distance from the action itself but are 
still reasonably foreseeable; and
    (2) The Federal agency can practicably control and will maintain 
control over due to a continuing program responsibility of the Federal 
agency.
    Local air quality modeling analysis means an assessment of localized 
impacts on a scale smaller than the entire nonattainment or maintenance 
area, including, for example, congested roadway intersections and 
highways or transit terminals, which uses an air quality dispersion 
model to determine the effects of emissions on air quality.
    Maintenance area means an area with a maintenance plan approved 
under section 175A of the Act.
    Maintenance plan means a revision to the applicable SIP, meeting the 
requirements of section 175A of the Act.
    Metropolitan Planning Organization (MPO) is that organization 
designated as being responsible, together with the State, for conducting 
the continuing, cooperative, and comprehensive planning process under 23 
U.S.C. 134 and 49 U.S.C. 1607.
    Milestone has the meaning given in sections 182(g)(1) and 189(c)(1) 
of the Act.
    National ambient air quality standards (NAAQS) are those standards 
established pursuant to section 109 of the Act and include standards for 
carbon monoxide (CO), lead (Pb), nitrogen dioxide (NO2), 
ozone, particulate matter (PM-10), and sulfur dioxide (SO2).
    NEPA is the National Environmental Policy Act of 1969, as amended 
(42 U.S.C. 4321 et seq.).
    Nonattainment Area (NAA) means an area designated as nonattainment 
under section 107 of the Act and described in 40 CFR part 81.
    Precursors of a criteria pollutant are:
    (1) For ozone, nitrogen oxides (NOX), unless an area is 
exempted from NOX requirements under section 182(f) of the 
Act, and volatile organic compounds (VOC); and
    (2) For PM-10, those pollutants described in the PM-10 nonattainment 
area applicable SIP as significant contributors to the PM-10 levels.
    Reasonably foreseeable emissions are projected future indirect 
emissions that are identified at the time the conformity determination 
is made; the location of such emissions is known and the emissions are 
quantifiable, as described and documented by the Federal agency based on 
its own information and after reviewing any information presented to the 
Federal agency.
    Regional water and/or wastewater projects include construction, 
operation, and maintenance of water or wastewater conveyances, water or 
wastewater treatment facilities, and water storage reservoirs which 
affect a large portion of a nonattainment or maintenance area.
    Regionally significant action means a Federal action for which the 
direct and indirect emissions of any pollutant represent 10 percent or 
more of a nonattainment or maintenance area's emissions inventory for 
that pollutant.
    Total of direct and indirect emissions means the sum of direct and 
indirect emissions increases and decreases caused by the Federal action; 
i.e., the ``net'' emissions considering all direct and indirect 
emissions. The portion of emissions which are exempt or presumed to 
conform under Sec. 51.853, (c),

[[Page 372]]

(d), (e), or (f) are not included in the ``total of direct and indirect 
emissions.'' The ``total of direct and indirect emissions'' includes 
emissions of criteria pollutants and emissions of precursors of criteria 
pollutants.

[58 FR 63247, Nov. 30, 1993, as amended at 71 FR 17008, Apr. 5, 2006]



Sec. 51.853  Applicability.

    (a) Conformity determinations for Federal actions related to 
transportation plans, programs, and projects developed, funded, or 
approved under title 23 U.S.C. or the Federal Transit Act (49 U.S.C. 
1601 et seq.) must meet the procedures and criteria of 40 CFR part 51, 
subpart T, in lieu of the procedures set forth in this subpart.
    (b) For Federal actions not covered by paragraph (a) of this 
section, a conformity determination is required for each criteria 
pollutant or precursor where the total of direct and indirect emissions 
of the criteria pollutant or precursor in a nonattainment or maintenance 
area caused by a Federal action would equal or exceed any of the rates 
in paragraphs (b)(1) or (2) of this section.
    (1) For purposes of paragraph (b) of this section, the following 
rates apply in nonattainment areas (NAA's):

------------------------------------------------------------------------
                                                                  Tons/
                                                                   year
------------------------------------------------------------------------
Ozone (VOC's or NOX):
  Serious NAA's................................................       50
  Severe NAA's.................................................       25
  Extreme NAA's................................................       10
  Other ozone NAA's outside an ozone transport region..........      100
Other ozone NAA's inside an ozone transport region:
  VOC..........................................................       50
  NOX..........................................................      100
Carbon monoxide: All NAA's.....................................      100
SO2 or NO2: All NAA's..........................................      100
PM-10:
  Moderate NAA's...............................................      100
  Serious NAA's................................................       70
PM2.5:
  Direct emissions.............................................      100
  SO2..........................................................      100
  NOX (unless determined not to be significant precursors).....      100
  VOC or ammonia (if determined to be significant precursors)..      100
Pb: All NAA's..................................................       25
------------------------------------------------------------------------

    (2) For purposes of paragraph (b) of this section, the following 
rates apply in maintenance areas:

------------------------------------------------------------------------
                                                                  Tons/
                                                                   year
------------------------------------------------------------------------
Ozone (NOX, SO2 or NO2): All Maintenance Areas.................      100
Ozone (VOC's):
  Maintenance areas inside an ozone transport region...........       50
  Maintenance areas outside an ozone transport region..........      100
Carbon monoxide: All Maintenance Areas.........................      100
PM-10: All Maintenance Areas...................................      100
PM2.5:
  Direct emissions.............................................      100
  SO2..........................................................      100
  NOX (unless determined not to be significant precursors).....      100
  VOC or ammonia (if determined to be significant precursors)..      100
Pb: All Maintenance Areas......................................       25
------------------------------------------------------------------------

    (c) The requirements of this subpart shall not apply to:
    (1) Actions where the total of direct and indirect emissions are 
below the emissions levels specified in paragraph (b) of this section.
    (2) The following actions which would result in no emissions 
increase or an increase in emissions that is clearly de minimis:
    (i) Judicial and legislative proceedings.
    (ii) Continuing and recurring activities such as permit renewals 
where activities conducted will be similar in scope and operation to 
activities currently being conducted.
    (iii) Rulemaking and policy development and issuance.
    (iv) Routine maintenance and repair activities, including repair and 
maintenance of administrative sites, roads, trails, and facilities.
    (v) Civil and criminal enforcement activities, such as 
investigations, audits, inspections, examinations, prosecutions, and the 
training of law enforcement personnel.
    (vi) Administrative actions such as personnel actions, 
organizational changes, debt management or collection, cash management, 
internal agency audits, program budget proposals, and matters relating 
to the administration and collection of taxes, duties and fees.
    (vii) The routine, recurring transportation of materiel and 
personnel.
    (viii) Routine movement of mobile assets, such as ships and 
aircraft, in home port reassignments and stations

[[Page 373]]

(when no new support facilities or personnel are required) to perform as 
operational groups and/or for repair or overhaul.
    (ix) Maintenance dredging and debris disposal where no new depths 
are required, applicable permits are secured, and disposal will be at an 
approved disposal site.
    (x) Actions, such as the following, with respect to existing 
structures, properties, facilities and lands where future activities 
conducted will be similar in scope and operation to activities currently 
being conducted at the existing structures, properties, facilities, and 
lands; for example, relocation of personnel, disposition of federally-
owned existing structures, properties, facilities, and lands, rent 
subsidies, operation and maintenance cost subsidies, the exercise of 
receivership or conservatorship authority, assistance in purchasing 
structures, and the production of coins and currency.
    (xi) The granting of leases, licenses such as for exports and trade, 
permits, and easements where activities conducted will be similar in 
scope and operation to activities currently being conducted.
    (xii) Planning, studies, and provision of technical assistance.
    (xiii) Routine operation of facilities, mobile assets and equipment.
    (xiv) Transfers of ownership, interests, and titles in land, 
facilities, and real and personal properties, regardless of the form or 
method of the transfer.
    (xv) The designation of empowerment zones, enterprise communities, 
or viticultural areas.
    (xvi) Actions by any of the Federal banking agencies or the Federal 
Reserve Banks, including actions regarding charters, applications, 
notices, licenses, the supervision or examination of depository 
institutions or depository institution holding companies, access to the 
discount window, or the provision of financial services to banking 
organizations or to any department, agency or instrumentality of the 
United States.
    (xvii) Actions by the Board of Governors of the Federal Reserve 
System or any Federal Reserve Bank to effect monetary or exchange rate 
policy.
    (xviii) Actions that implement a foreign affairs function of the 
United States.
    (xix) Actions (or portions thereof) associated with transfers of 
land, facilities, title, and real properties through an enforceable 
contract or lease agreement where the delivery of the deed is required 
to occur promptly after a specific, reasonable condition is met, such as 
promptly after the land is certified as meeting the requirements of the 
Comprehensive Environmental Response, Compensation, and Liability Act 
(CERCLA), and where the Federal agency does not retain continuing 
authority to control emissions associated with the lands, facilities, 
title, or real properties.
    (xx) Transfers of real property, including land, facilities, and 
related personal property from a Federal entity to another Federal 
entity and assignments of real property, including land, facilities, and 
related personal property from a Federal entity to another Federal 
entity for subsequent deeding to eligible applicants.
    (xxi) Actions by the Department of the Treasury to effect fiscal 
policy and to exercise the borrowing authority of the United States.
    (3) The following actions where the emissions are not reasonably 
foreseeable:
    (i) Initial Outer Continental Shelf lease sales which are made on a 
broad scale and are followed by exploration and development plans on a 
project level.
    (ii) Electric power marketing activities that involve the 
acquisition, sale and transmission of electric energy.
    (4) Actions which implement a decision to conduct or carry out a 
conforming program such as prescribed burning actions which are 
consistent with a conforming land management plan.
    (d) Notwithstanding the other requirements of this subpart, a 
conformity determination is not required for the following Federal 
actions (or portion thereof):
    (1) The portion of an action that includes major new or modified 
stationary sources that require a permit under the new source review 
(NSR) program (section 173 of the Act) or the

[[Page 374]]

prevention of significant deterioration (PSD) program (title I, part C 
of the Act).
    (2) Actions in response to emergencies or natural disasters such as 
hurricanes, earthquakes, etc., which are commenced on the order of hours 
or days after the emergency or disaster and, if applicable, which meet 
the requirements of paragraph (e) of this section.
    (3) Research, investigations, studies, demonstrations, or training 
(other than those exempted under paragraph (c)(2) of this section), 
where no environmental detriment is incurred and/or, the particular 
action furthers air quality research, as determined by the State agency 
primarily responsible for the applicable SIP.
    (4) Alteration and additions of existing structures as specifically 
required by new or existing applicable environmental legislation or 
environmental regulations (e.g., hush houses for aircraft engines and 
scrubbers for air emissions).
    (5) Direct emissions from remedial and removal actions carried out 
under the Comprehensive Environmental Response, Compensation and 
Liability Act (CERCLA) and associated regulations to the extent such 
emissions either comply with the substantive requirements of the PSD/NSR 
permitting program or are exempted from other environmental regulation 
under the provisions of CERCLA and applicable regulations issued under 
CERCLA.
    (e) Federal actions which are part of a continuing response to an 
emergency or disaster under paragraph (d)(2) of this section and which 
are to be taken more than 6 months after the commencement of the 
response to the emergency or disaster under paragraph (d)(2) of this 
section are exempt from the requirements of this subpart only if:
    (1) The Federal agency taking the actions makes a written 
determination that, for a specified period not to exceed an additional 6 
months, it is impractical to prepare the conformity analyses which would 
otherwise be required and the actions cannot be delayed due to 
overriding concerns for public health and welfare, national security 
interests and foreign policy commitments; or
    (2) For actions which are to be taken after those actions covered by 
paragraph (e)(1) of this section, the Federal agency makes a new 
determination as provided in paragraph (e)(1) of this section.
    (f) Notwithstanding other requirements of this subpart, actions 
specified by individual Federal agencies that have met the criteria set 
forth in either paragraph (g)(1) or (g)(2) of this section and the 
procedures set forth in paragraph (h) of this section are presumed to 
conform, except as provided in paragraph (j) of this section.
    (g) The Federal agency must meet the criteria for establishing 
activities that are presumed to conform by fulfilling the requirements 
set forth in either paragraph (g)(1) or (g)(2) of this section:
    (1) The Federal agency must clearly demonstrate using methods 
consistent with this subpart that the total of direct and indirect 
emissions from the type of activities which would be presumed to conform 
would not:
    (i) Cause or contribute to any new violation of any standard in any 
area;
    (ii) Interfere with provisions in the applicable SIP for maintenance 
of any standard;
    (iii) Increase the frequency or severity of any existing violation 
of any standard in any area; or
    (iv) Delay timely attainment of any standard or any required interim 
emission reductions or other milestones in any area including, where 
applicable, emission levels specified in the applicable SIP for purposes 
of:
    (A) A demonstration of reasonable further progress;
    (B) A demonstration of attainment; or
    (C) A maintenance plan; or
    (2) The Federal agency must provide documentation that the total of 
direct and indirect emissions from such future actions would be below 
the emission rates for a conformity determination that are established 
in paragraph (b) of this section, based, for example, on similar actions 
taken over recent years.
    (h) In addition to meeting the criteria for establishing exemptions 
set

[[Page 375]]

forth in paragraphs (g)(1) or (g)(2) of this section, the following 
procedures must also be complied with to presume that activities will 
conform:
    (1) The Federal agency must identify through publication in the 
Federal Register its list of proposed activities that are presumed to 
conform and the basis for the presumptions;
    (2) The Federal agency must notify the appropriate EPA Regional 
Office(s), State and local air quality agencies and, where applicable, 
the agency designated under section 174 of the Act and the MPO and 
provide at least 30 days for the public to comment on the list of 
proposed activities presumed to conform;
    (3) The Federal agency must document its response to all the 
comments received and make the comments, response, and final list of 
activities available to the public upon request; and
    (4) The Federal agency must publish the final list of such 
activities in the Federal Register.
    (i) Notwithstanding the other requirements of this subpart, when the 
total of direct and indirect emissions of any pollutant from a Federal 
action does not equal or exceed the rates specified in paragraph (b) of 
this section, but represents 10 percent or more of a nonattainment or 
maintenance area's total emissions of that pollutant, the action is 
defined as a regionally significant action and the requirements of Sec. 
51.850 and Sec. Sec. 51.855 through 51.860 shall apply for the Federal 
action.
    (j) Where an action otherwise presumed to conform under paragraph 
(f) of this section is a regionally significant action or does not in 
fact meet one of the criteria in paragraph (g)(1) of this section, that 
action shall not be presumed to conform and the requirements of Sec. 
51.850 and Sec. Sec. 51.855 through 51.860 shall apply for the Federal 
action.
    (k) The provisions of this subpart shall apply in all nonattainment 
and maintenance areas.

[58 FR 63247, Nov. 30, 1993, as amended at 71 FR 17008, Apr. 5, 2006]



Sec. 51.854  Conformity analysis.

    Any Federal department, agency, or instrumentality of the Federal 
Government taking an action subject to this subpart must make its own 
conformity determination consistent with the requirements of this 
subpart. In making its conformity determination, a Federal agency must 
consider comments from any interested parties. Where multiple Federal 
agencies have jurisdiction for various aspects of a project, a Federal 
agency may choose to adopt the analysis of another Federal agency or 
develop its own analysis in order to make its conformity determination.



Sec. 51.855  Reporting requirements.

    (a) A Federal agency making a conformity determination under Sec. 
51.858 must provide to the appropriate EPA Regional Office(s), State and 
local air quality agencies and, where applicable, affected Federal land 
managers, the agency designated under section 174 of the Act and the MPO 
a 30 day notice which describes the proposed action and the Federal 
agency's draft conformity determination on the action.
    (b) A Federal agency must notify the appropriate EPA Regional 
Office(s), State and local air quality agencies and, where applicable, 
affected Federal land managers, the agency designated under section 174 
of the Clean Air Act and the MPO within 30 days after making a final 
conformity determination under Sec. 51.858.



Sec. 51.856  Public participation.

    (a) Upon request by any person regarding a specific Federal action, 
a Federal agency must make available for review its draft conformity 
determination under Sec. 51.858 with supporting materials which 
describe the analytical methods and conclusions relied upon in making 
the applicability analysis and draft conformity determination.
    (b) A Federal agency must make public its draft conformity 
determination under Sec. 51.858 by placing a notice by prominent 
advertisement in a daily newspaper of general circulation in the area 
affected by the action and by providing 30 days for written public 
comment prior to taking any formal action on the draft determination. 
This comment period may be concurrent with any other public involvement, 
such as occurs in the NEPA process.

[[Page 376]]

    (c) A Federal agency must document its response to all the comments 
received on its draft conformity determination under Sec. 51.858 and 
make the comments and responses available, upon request by any person 
regarding a specific Federal action, within 30 days of the final 
conformity determination.
    (d) A Federal agency must make public its final conformity 
determination under Sec. 51.858 for a Federal action by placing a 
notice by prominent advertisement in a daily newspaper of general 
circulation in the area affected by the action within 30 days of the 
final conformity determination.



Sec. 51.857  Frequency of conformity determinations.

    (a) The conformity status of a Federal action automatically lapses 5 
years from the date a final conformity determination is reported under 
Sec. 51.855, unless the Federal action has been completed or a 
continuous program has been commenced to implement that Federal action 
within a reasonable time.
    (b) Ongoing Federal activities at a given site showing continuous 
progress are not new actions and do not require periodic 
redeterminations so long as such activities are within the scope of the 
final conformity determination reported under Sec. 51.855.
    (c) If, after the conformity determination is made, the Federal 
action is changed so that there is an increase in the total of direct 
and indirect emissions above the levels in Sec. 51.853(b), a new 
conformity determination is required.



Sec. 51.858  Criteria for determining conformity of general Federal 
actions.

    (a) An action required under Sec. 51.853 to have a conformity 
determination for a specific pollutant, will be determined to conform to 
the applicable SIP if, for each pollutant that exceeds the rates in 
Sec. 51.853(b), or otherwise requires a conformity determination due to 
the total of direct and indirect emissions from the action, the action 
meets the requirements of paragraph (c) of this section, and meets any 
of the following requirements:
    (1) For any criteria pollutant, the total of direct and indirect 
emissions from the action are specifically identified and accounted for 
in the applicable SIP's attainment or maintenance demonstration;
    (2) For ozone or nitrogen dioxide, the total of direct and indirect 
emissions from the action are fully offset within the same nonattainment 
or maintenance area through a revision to the applicable SIP or a 
similarly enforceable measure that effects emission reductions so that 
there is no net increase in emissions of that pollutant;
    (3) For any criteria pollutant, except ozone and nitrogen dioxide, 
the total of direct and indirect emissions from the action meet the 
requirements:
    (i) Specified in paragraph (b) of this section, based on areawide 
air quality modeling analysis and local air quality modeling analysis; 
or
    (ii) Meet the requirements of paragraph (a)(5) of this section and, 
for local air quality modeling analysis, the requirement of paragraph 
(b) of this section;
    (4) For CO or PM-10--
    (i) Where the State agency primarily responsible for the applicable 
SIP determines that an areawide air quality modeling analysis is not 
needed, the total of direct and indirect emissions from the action meet 
the requirements specified in paragraph (b) of this section, based on 
local air quality modeling analysis; or
    (ii) Where the State agency primarily responsible for the applicable 
SIP determines that an areawide air quality modeling analysis is 
appropriate and that a local air quality modeling analysis is not 
needed, the total of direct and indirect emissions from the action meet 
the requirements specified in paragraph (b) of this section, based on 
areawide modeling, or meet the requirements of paragraph (a)(5) of this 
section; or
    (5) For ozone or nitrogen dioxide, and for purposes of paragraphs 
(a)(3)(ii) and (a)(4)(ii) of this section, each portion of the action or 
the action as a whole meets any of the following requirements:
    (i) Where EPA has approved a revision to an area's attainment or 
maintenance demonstration after 1990 and the State makes a determination 
as provided in paragraph (a)(5)(i)(A) of this

[[Page 377]]

section or where the State makes a commitment as provided in paragraph 
(a)(5)(i)(B) of this section:
    (A) The total of direct and indirect emissions from the action (or 
portion thereof) is determined and documented by the State agency 
primarily responsible for the applicable SIP to result in a level of 
emissions which, together with all other emissions in the nonattainment 
(or maintenance) area, would not exceed the emissions budgets specified 
in the applicable SIP;
    (B) The total of direct and indirect emissions from the action (or 
portion thereof) is determined by the State agency responsible for the 
applicable SIP to result in a level of emissions which, together with 
all other emissions in the nonattainment (or maintenance) area, would 
exceed an emissions budget specified in the applicable SIP and the State 
Governor or the Governor's designee for SIP actions makes a written 
commitment to EPA which includes the following:
    (1) A specific schedule for adoption and submittal of a revision to 
the SIP which would achieve the needed emission reductions prior to the 
time emissions from the Federal action would occur;
    (2) Identification of specific measures for incorporation into the 
SIP which would result in a level of emissions which, together with all 
other emissions in the nonattainment or maintenance area, would not 
exceed any emissions budget specified in the applicable SIP;
    (3) A demonstration that all existing applicable SIP requirements 
are being implemented in the area for the pollutants affected by the 
Federal action, and that local authority to implement additional 
requirements has been fully pursued;
    (4) A determination that the responsible Federal agencies have 
required all reasonable mitigation measures associated with their 
action; and
    (5) Written documentation including all air quality analyses 
supporting the conformity determination;
    (C) Where a Federal agency made a conformity determination based on 
a State commitment under paragraph (a)(5)(i)(B) of this section, such a 
State commitment is automatically deemed a call for a SIP revision by 
EPA under section 110(k)(5) of the Act, effective on the date of the 
Federal conformity determination and requiring response within 18 months 
or any shorter time within which the State commits to revise the 
applicable SIP;
    (ii) The action (or portion thereof), as determined by the MPO, is 
specifically included in a current transportation plan and 
transportation improvement program which have been found to conform to 
the applicable SIP under 40 CFR part 51, subpart T, or 40 CFR part 93, 
subpart A;
    (iii) The action (or portion thereof) fully offsets its emissions 
within the same nonattainment or maintenance area through a revision to 
the applicable SIP or an equally enforceable measure that effects 
emission reductions equal to or greater than the total of direct and 
indirect emissions from the action so that there is no net increase in 
emissions of that pollutant;
    (iv) Where EPA has not approved a revision to the relevant SIP 
attainment or maintenance demonstration since 1990, the total of direct 
and indirect emissions from the action for the future years (described 
in Sec. 51.859(d)) do not increase emissions with respect to the 
baseline emissions:
    (A) The baseline emissions reflect the historical activity levels 
that occurred in the geographic area affected by the proposed Federal 
action during:
    (1) Calendar year 1990;
    (2) The calendar year that is the basis for the classification (or, 
where the classification is based on multiple years, the most 
representative year), if a classification is promulgated in 40 CFR part 
81; or
    (3) The year of the baseline inventory in the PM-10 applicable SIP;
    (B) The baseline emissions are the total of direct and indirect 
emissions calculated for the future years (described in Sec. 51.859(d)) 
using the historic activity levels (described in paragraph (a)(5)(iv)(A) 
of this section) and appropriate emission factors for the future years; 
or
    (v) Where the action involves regional water and/or wastewater 
projects, such projects are sized to meet only the needs of population 
projections that are in the applicable SIP.

[[Page 378]]

    (b) The areawide and/or local air quality modeling analyses must:
    (1) Meet the requirements in Sec. 51.859; and
    (2) Show that the action does not:
    (i) Cause or contribute to any new violation of any standard in any 
area; or
    (ii) Increase the frequency or severity of any existing violation of 
any standard in any area.
    (c) Notwithstanding any other requirements of this section, an 
action subject to this subpart may not be determined to conform to the 
applicable SIP unless the total of direct and indirect emissions from 
the action is in compliance or consistent with all relevant requirements 
and milestones contained in the applicable SIP, such as elements 
identified as part of the reasonable further progress schedules, 
assumptions specified in the attainment or maintenance demonstration, 
prohibitions, numerical emission limits, and work practice requirements.
    (d) Any analyses required under this section must be completed, and 
any mitigation requirements necessary for a finding of conformity must 
be identified before the determination of conformity is made.



Sec. 51.859  Procedures for conformity determinations of general Federal 
actions.

    (a) The analyses required under this subpart must be based on the 
latest planning assumptions.
    (1) All planning assumptions must be derived from the estimates of 
population, employment, travel, and congestion most recently approved by 
the MPO, or other agency authorized to make such estimates, where 
available.
    (2) Any revisions to these estimates used as part of the conformity 
determination, including projected shifts in geographic location or 
level of population, employment, travel, and congestion, must be 
approved by the MPO or other agency authorized to make such estimates 
for the urban area.
    (b) The analyses required under this subpart must be based on the 
latest and most accurate emission estimation techniques available as 
described below, unless such techniques are inappropriate. If such 
techniques are inappropriate and written approval of the EPA Regional 
Administrator is obtained for any modification or substitution, they may 
be modified or another technique substituted on a case-by-case basis or, 
where appropriate, on a generic basis for a specific Federal agency 
program.
    (1) For motor vehicle emissions, the most current version of the 
motor vehicle emissions model specified by EPA and available for use in 
the preparation or revision of SIPs in that State must be used for the 
conformity analysis as specified in paragraphs (b)(1) (i) and (ii) of 
this section:
    (i) The EPA must publish in the Federal Register a notice of 
availability of any new motor vehicle emissions model; and
    (ii) A grace period of three months shall apply during which the 
motor vehicle emissions model previously specified by EPA as the most 
current version may be used. Conformity analyses for which the analysis 
was begun during the grace period or no more than 3 years before the 
Federal Register notice of availability of the latest emission model may 
continue to use the previous version of the model specified by EPA.
    (2) For non-motor vehicle sources, including stationary and area 
source emissions, the latest emission factors specified by EPA in the 
``Compilation of Air Pollutant Emission Factors (AP-42)''\1\ must be 
used for the conformity analysis unless more accurate emission data are 
available, such as actual stack test data from stationary sources which 
are part of the conformity analysis.
---------------------------------------------------------------------------

    \1\ Copies may be obtained from the Technical Support Division of 
OAQPS, EPA, MD-14, Research Triangle Park, NC 27711.
---------------------------------------------------------------------------

    (c) The air quality modeling analyses required under this subpart 
must be based on the applicable air quality models, data bases, and 
other requirements specified in the most recent version of the 
``Guideline on Air Quality Models (Revised)'' (1986), including 
supplements (EPA publication no. 450/2-78-027R) \2\, unless:
---------------------------------------------------------------------------

    \2\ See footnote 1 at Sec. 51.859(b)(2).
---------------------------------------------------------------------------

    (1) The guideline techniques are inappropriate, in which case the 
model may

[[Page 379]]

be modified or another model substituted on a case-by-case basis or, 
where appropriate, on a generic basis for a specific Federal agency 
program; and
    (2) Written approval of the EPA Regional Administrator is obtained 
for any modification or substitution.
    (d) The analyses required under this subpart, except Sec. 
51.858(a)(1), must be based on the total of direct and indirect 
emissions from the action and must reflect emission scenarios that are 
expected to occur under each of the following cases:
    (1) The Act mandated attainment year or, if applicable, the farthest 
year for which emissions are projected in the maintenance plan;
    (2) The year during which the total of direct and indirect emissions 
from the action is expected to be the greatest on an annual basis; and
    (3) any year for which the applicable SIP specifies an emissions 
budget.



Sec. 51.860  Mitigation of air quality impacts.

    (a) Any measures that are intended to mitigate air quality impacts 
must be identified and the process for implementation and enforcement of 
such measures must be described, including an implementation schedule 
containing explicit timelines for implementation.
    (b) Prior to determining that a Federal action is in conformity, the 
Federal agency making the conformity determination must obtain written 
commitments from the appropriate persons or agencies to implement any 
mitigation measures which are identified as conditions for making 
conformity determinations.
    (c) Persons or agencies voluntarily committing to mitigation 
measures to facilitate positive conformity determinations must comply 
with the obligations of such commitments.
    (d) In instances where the Federal agency is licensing, permitting 
or otherwise approving the action of another governmental or private 
entity, approval by the Federal agency must be conditioned on the other 
entity meeting the mitigation measures set forth in the conformity 
determination.
    (e) When necessary because of changed circumstances, mitigation 
measures may be modified so long as the new mitigation measures continue 
to support the conformity determination. Any proposed change in the 
mitigation measures is subject to the reporting requirements of Sec. 
51.856 and the public participation requirements of Sec. 51.857.
    (f) The implementation plan revision required in Sec. 51.851 shall 
provide that written commitments to mitigation measures must be obtained 
prior to a positive conformity determination and that such commitments 
must be fulfilled.
    (g) After a State revises its SIP to adopt its general conformity 
rules and EPA approves that SIP revision, any agreements, including 
mitigation measures, necessary for a conformity determination will be 
both State and federally enforceable. Enforceability through the 
applicable SIP will apply to all persons who agree to mitigate direct 
and indirect emissions associated with a Federal action for a conformity 
determination.



Subpart X_Provisions for Implementation of 8-hour Ozone National Ambient 
                          Air Quality Standard

    Source: 69 FR 23996, Apr. 30, 2004, unless otherwise noted.



Sec. 51.900  Definitions.

    The following definitions apply for purposes of this subpart. Any 
term not defined herein shall have the meaning as defined in 40 CFR 
51.100.
    (a) 1-hour NAAQS means the 1-hour ozone national ambient air quality 
standards codified at 40 CFR 50.9.
    (b) 8-hour NAAQS means the 8-hour ozone national ambient air quality 
standards codified at 40 CFR 50.10.
    (c) 1-hour ozone design value is the 1-hour ozone concentration 
calculated according to 40 CFR part 50, Appendix H and the 
interpretation methodology issued by the Administrator most recently 
before the date of the enactment of the CAA Amendments of 1990.

[[Page 380]]

    (d) 8-Hour ozone design value is the 8-hour ozone concentration 
calculated according to 40 CFR part 50, appendix I.
    (e) CAA means the Clean Air Act as codified at 42 U.S.C. 7401-7671q 
(2003).
    (f) Applicable requirements means for an area the following 
requirements to the extent such requirements apply or applied to the 
area for the area's classification under section 181(a)(1) of the CAA 
for the 1-hour NAAQS at designation for the 8-hour NAAQS:
    (1) Reasonably available control technology (RACT).
    (2) Inspection and maintenance programs (I/M).
    (3) Major source applicability cut-offs for purposes of RACT.
    (4) Rate of Progress (ROP) reductions.
    (5) Stage II vapor recovery.
    (6) Clean fuels fleet program under section 183(c)(4) of the CAA.
    (7) Clean fuels for boilers under section 182(e)(3) of the CAA.
    (8) Transportation Control Measures (TCMs) during heavy traffic 
hours as provided under section 182(e)(4) of the CAA.
    (9) Enhanced (ambient) monitoring under section 182(c)(1) of the 
CAA.
    (10) Transportation controls under section 182(c)(5) of the CAA.
    (11) Vehicle miles traveled provisions of section 182(d)(1) of the 
CAA.
    (12) NOX requirements under section 182(f) of the CAA.
    (13) Attainment demonstration or an alternative as provided under 
Sec. 51.905(a)(1)(ii).
    (g) Attainment year ozone season shall mean the ozone season 
immediately preceding a nonattainment area's attainment date.
    (h) Designation for the 8-hour NAAQS shall mean the effective date 
of the 8-hour designation for an area.
    (i) Higher classification/lower classification. For purposes of 
determining whether a classification is higher or lower, classifications 
are ranked from lowest to highest as follows: classification under 
subpart 1 of the CAA; marginal; moderate; serious; severe-15; severe-17; 
and extreme.
    (j) Initially designated means the first designation that becomes 
effective for an area for the 8-hour NAAQS and does not include a 
redesignation to attainment or nonattainment for that standard.
    (k) Maintenance area for the 1-hour NAAQS means an area that was 
designated nonattainment for the 1-hour NAAQS on or after November 15, 
1990 and was redesignated to attainment for the 1-hour NAAQS subject to 
a maintenance plan as required by section 175A of the CAA.
    (l) Nitrogen Oxides (NOX) means the sum of nitric oxide 
and nitrogen dioxide in the flue gas or emission point, collectively 
expressed as nitrogen dioxide.
    (m) NOX SIP Call means the rules codified at 40 CFR 
51.121 and 51.122.
    (n) Ozone season means for each State, the ozone monitoring season 
as defined in 40 CFR Part 58, Appendix D, section 2.5 for that State.
    (o) Ozone transport region means the area established by section 
184(a) of the CAA or any other area established by the Administrator 
pursuant to section 176A of the CAA for purposes of ozone.
    (p) Reasonable further progress (RFP) means for the purposes of the 
8-hour NAAQS, the progress reductions required under section 172(c)(2) 
and section 182(b)(1) and (c)(2)(B) and (c)(2)(C) of the CAA.
    (q) Rate of progress (ROP) means for purposes of the 1-hour NAAQS, 
the progress reductions required under section 172(c)(2) and section 
182(b)(1) and (c)(2)(B) and (c)(2)(C) of the CAA.
    (r) Revocation of the 1-hour NAAQS means the time at which the 1-
hour NAAQS no longer apply to an area pursuant to 40 CFR 50.9(b).
    (s) Subpart 1 (CAA) means subpart 1 of part D of title I of the CAA.
    (t) Subpart 2 (CAA) means subpart 2 of part D of title I of the CAA.
    (u) Attainment Area means, unless otherwise indicated, an area 
designated as either attainment, unclassifiable, or attainment/
unclassifiable.

[69 FR 23996, Apr. 30, 2004, as amended at 70 FR 30604, May 26, 2005]



Sec. 51.901  Applicability of part 51.

    The provisions in subparts A through W of part 51 apply to areas for 
purposes of the 8-hour NAAQS to the extent they are not inconsistent 
with the provisions of this subpart.

[[Page 381]]



Sec. 51.902  Which classification and nonattainment area planning 
provisions of the CAA shall apply to areas designated nonattainment 
for the 8-hour NAAQS?

    (a) Classification under subpart 2 (CAA). An area designated 
nonattainment for the 8-hour NAAQS with a 1-hour ozone design value 
equal to or greater than 0.121 ppm at the time the Administrator signs a 
final rule designating or redesignating the area as nonattainment for 
the 8-hour NAAQS will be classified in accordance with section 181 of 
the CAA, as interpreted in Sec. 51.903(a), for purposes of the 8-hour 
NAAQS, and will be subject to the requirements of subpart 2 that apply 
for that classification.
    (b) Covered under subpart 1 (CAA). An area designated nonattainment 
for the 8-hour ozone NAAQS with a 1-hour design value less than 0.121 
ppm at the time the Administrator signs a final rule designating or 
redesignating the area as nonattainment for the 8-hour NAAQS will be 
covered under section 172(a)(1) of the CAA and will be subject to the 
requirements of subpart 1.



Sec. 51.903  How do the classification and attainment date provisions in 
section 181 of subpart 2 of the CAA apply to areas subject to Sec. 51.902(a)?

    (a) In accordance with section 181(a)(1) of the CAA, each area 
subject to Sec. 51.902(a) shall be classified by operation of law at 
the time of designation. However, the classification shall be based on 
the 8-hour design value for the area, in accordance with Table 1 below, 
or such higher or lower classification as the State may request as 
provided in paragraphs (b) and (c) of this section. The 8-hour design 
value for the area shall be calculated using the three most recent years 
of air quality data. For each area classified under this section, the 
primary NAAQS attainment date for the 8-hour NAAQS shall be as 
expeditious as practicable but not later than the date provided in the 
following Table 1.

              Table 1--Classification for 8-Hour Ozone NAAQS for Areas Subject to Sec.  51.902(a)
----------------------------------------------------------------------------------------------------------------
                                                                                            Maximum period for
                                                                                           attainment dates in
                                                                         8-hour  design     state plans (years
                Area class                                                 value  (ppm   after effective date of
                                                                             ozone)           nonattainment
                                                                                          designation for 8-hour
                                                                                                  NAAQS)
----------------------------------------------------------------------------------------------------------------
Marginal.................................  from........................           0.085                        3
                                           up to \1\...................           0.092
Moderate.................................  from........................           0.092                        6
                                           up to \1\...................           0.107
Serious..................................  from........................           0.107                        9
                                           up to \1\...................           0.120
Severe-15................................  from........................           0.120                       15
                                           up to \1\...................           0.127
Severe-17................................  from........................           0.127                       17
                                           up to \1\...................           0.187
Extreme..................................  equal to....................           0.187                      20
                                           or above....................
----------------------------------------------------------------------------------------------------------------
\1\ but not including.

    (b) A State may request a higher classification for any reason in 
accordance with section 181(b)(3) of the CAA.
    (c) A State may request a lower classification in accordance with 
section 181(a)(4) of the CAA.



Sec. 51.904  How do the classification and attainment date provisions in 
section 172(a) of subpart 1 of the CAA apply to areas subject to Sec. 51.902(b)?

    (a) Classification. The Administrator may classify an area subject 
to Sec. 51.902(b) as an overwhelming transport area if:
    (1) The area meets the criteria as specified for rural transport 
areas under section 182(h) of the CAA;

[[Page 382]]

    (2) Transport of ozone and/or precursors into the area is so 
overwhelming that the contribution of local emissions to observed 8-hour 
ozone concentration above the level of the NAAQS is relatively minor; 
and
    (3) The Administrator finds that sources of VOC (and, where the 
Administrator determines relevant, NOX) emissions within the 
area do not make a significant contribution to the ozone concentrations 
measured in other areas.
    (b) Attainment dates. For an area subject to Sec. 51.902(b), the 
Administrator will approve an attainment date consistent with the 
attainment date timing provision of section 172(a)(2)(A) of the CAA at 
the time the Administrator approves an attainment demonstration for the 
area.



Sec. 51.905  How do areas transition from the 1-hour NAAQS to the 8-hour 
NAAQS and what are the anti-backsliding provisions?

    (a) What requirements that applied in an area for the 1-hour NAAQS 
continue to apply after revocation of the 1-hour NAAQS for that area?--
(1) 8-Hour NAAQS Nonattainment/1-Hour NAAQS Nonattainment. The following 
requirements apply to an area designated nonattainment for the 8-hour 
NAAQS and designated nonattainment for the 1-hour NAAQS at the time of 
designation for the 8-hour NAAQS for that area.
    (i) The area remains subject to the obligation to adopt and 
implement the applicable requirements as defined in Sec. 51.900(f), 
except as provided in paragraph (a)(1)(iii) of this section, and except 
as provided in paragraph (b) of this section.
    (ii) If the area has not met its obligation to have a fully-approved 
attainment demonstration SIP for the 1-hour NAAQS, the State must comply 
with one of the following:
    (A) Submit a 1-hour attainment demonstration no later than 1 year 
after designation;
    (B) Submit a RFP plan for the 8-hour NAAQS no later than 1-year 
following designations for the 8-hour NAAQS providing a 5 percent 
increment of emissions reduction from the area's 2002 emissions 
baseline, which must be in addition to measures (or enforceable 
commitments to measures) in the SIP at the time of the effective date of 
designation and in addition to national or regional measures and must be 
achieved no later than 2 years after the required date for submission (3 
years after designation).
    (C) Submit an 8-hour ozone attainment demonstration no later than 1 
year following designations that demonstrates attainment of the 8-hour 
NAAQS by the area's attainment date; provides for 8-hour RFP for the 
area out to the attainment date; and for the initial period of RFP for 
the area (between 2003-2008), achieve the emission reductions by 
December 31, 2007.
    (iii) If the area has an outstanding obligation for an approved 1-
hour ROP SIP, it must develop and submit to EPA all outstanding 1-hour 
ROP plans; where a 1-hour obligation overlaps with an 8-hour RFP 
requirement, the State's 8-hour RFP plan can be used to satisfy the 1-
hour ROP obligation if the 8-hour RFP plan has an emission target at 
least as stringent as the 1-hour ROP emission target in each of the 1-
hour ROP target years for which the 1-hour ROP obligation exists.
    (2) 8-Hour NAAQS Nonattainment/1-Hour NAAQS Maintenance. An area 
designated nonattainment for the 8-hour NAAQS that is a maintenance area 
for the 1-hour NAAQS at the time of designation for the 8-hour NAAQS for 
that area remains subject to the obligation to implement the applicable 
requirements as defined in Sec. 51.900 (f) to the extent such 
obligations are required by the approved SIP, except as provided in 
paragraph (b) of this section. Applicable measures in the SIP must 
continue to be implemented; however, if these measures were shifted to 
contingency measures prior to designation for the 8-hour NAAQS for the 
area, they may remain as contingency measures, unless the measures are 
required to be implemented by the CAA by virtue of the area's 
requirements under the 8-hour NAAQS. The State may not remove such 
measures from the SIP.
    (3) 8-Hour NAAQS Attainment/1-Hour NAAQS Nonattainment--(i) 
Obligations in an approved SIP. For an area that is 8-hour NAAQS 
attainment/1-hour NAAQS nonattainment, the State may

[[Page 383]]

request that obligations under the applicable requirements of Sec. 
51.900(f) be shifted to contingency measures, consistent with sections 
110(l) and 193 of the CAA, after revocation of the 1-hour NAAQS; 
however, the State cannot remove the obligations from the SIP. For such 
areas, the State may request that the nonattainment NSR provisions be 
removed from the SIP on or after the date of revocation of the 1-hour 
NAAQS and need not be shifted to contingency measures subject to 
paragraph (e)(4) of this section.
    (ii) Attainment demonstration and ROP plans. (A) To the extent an 8-
hour NAAQS attainment/1-hour NAAQS nonattainment area does not have an 
approved attainment demonstration or ROP plan that was required for the 
1-hour NAAQS under the CAA, the obligation to submit such an attainment 
demonstration or ROP plan
    (1) Is deferred for so long as the area continues to maintain the 8-
hour NAAQS; and
    (2) No longer applies once the area has an approved maintenance plan 
pursuant to paragraph (a)(3)(iii) of this section.
    (B) For an 8-hour NAAQS attainment/1-hour NAAQS nonattainment area 
that violates the 8-hour NAAQS, prior to having an approved maintenance 
plan for the 8-hour NAAQS as provided under paragraph (a)(3)(iii) of 
this section, paragraphs (a)(3)(ii)(B)(1), (2), and (3) of this section 
shall apply.
    (1) In lieu of any outstanding obligation to submit an attainment 
demonstration, within 1 year after the date on which EPA publishes a 
determination that a violation of the 8-hour NAAQS has occurred, the 
State must submit (or revise a submitted) maintenance plan for the 8-
hour NAAQS, as provided under paragraph (a)(3)(iii) of this section, 
to--
    (i) Address the violation by relying on modeling that meets EPA 
guidance for purposes of demonstrating maintenance of the NAAQS; or
    (ii) Submit a SIP providing for a 3 percent increment of emissions 
reductions from the area's 2002 emissions baseline; these reductions 
must be in addition to measures (or enforceable commitments to measures) 
in the SIP at the time of the effective date of designation and in 
addition to national or regional measures.
    (2) The plan required under paragraph (a)(3)(ii)(B)(1) of this 
section must provide for the emission reductions required within 3 years 
after the date on which EPA publishes a determination that a violation 
of the 8-hour NAAQS has occurred.
    (3) The State shall submit an ROP plan to achieve any outstanding 
ROP reductions that were required for the area for the 1-hour NAAQS, and 
the 3-year period or periods for achieving the ROP reductions will begin 
January 1 of the year following the 3-year period on which EPA bases its 
determination that a violation of the 8-hour NAAQS occurred.
    (iii) Maintenance plans for the 8-hour NAAQS. For areas initially 
designated attainment for the 8-hour NAAQS, and designated nonattainment 
for the 1-hour NAAQS at the time of designation for the 8-hour NAAQS, 
the State shall submit no later than 3 years after the area's 
designation for the 8-hour NAAQS, a maintenance plan for the 8-hour 
NAAQS in accordance with section 110(a)(1) of the CAA. The maintenance 
plan must provide for continued maintenance of the 8-hour NAAQS for 10 
years following designation and must include contingency measures. This 
provision does not apply to areas redesignated from nonattainment to 
attainment for the 8-hour NAAQS pursuant to CAA section 107(d)(3); such 
areas are subject to the maintenance plan requirement in section 175A of 
the CAA.
    (4) 8-Hour NAAQS Attainment/1-Hour NAAQS Maintenance--(i) 
Obligations in an approved SIP. For an 8-hour NAAQS attainment/1-hour 
NAAQS maintenance area, the State may request that obligations under the 
applicable requirements of Sec. 51.900(f) be shifted to contingency 
measures, consistent with sections 110(l) and 193 of the CAA, after 
revocation of the 1-hour NAAQS; however, the State cannot remove the 
obligations from the SIP.
    (ii) Maintenance Plans for the 8-hour NAAQS. For areas initially 
designated attainment for the 8-hour NAAQS and subject to the 
maintenance plan for the 1-hour NAAQS at the time of designation for the 
8-hour NAAQS, the State

[[Page 384]]

shall submit no later than 3 years after the area's designation for the 
8-hour NAAQS, a maintenance plan for the 8-hour NAAQS in accordance with 
section 110(a)(1) of the CAA. The maintenance plan must provide for 
continued maintenance of the 8-hour NAAQS for 10 years following 
designation and must include contingency measures. This provision does 
not apply to areas redesignated from nonattainment to attainment for the 
8-hour NAAQS pursuant to section 107(d)(3); such areas are subject to 
the maintenance plan requirement in section 175A of the CAA.
    (b) Does attainment of the ozone NAAQS affect the obligations under 
paragraph (a) of this section? A State remains subject to the 
obligations under paragraphs (a)(1)(i) and (a)(2) of this section until 
the area attains the 8-hour NAAQS. After the area attains the 8-hour 
NAAQS, the State may request such obligations be shifted to contingency 
measures, consistent with sections 110(l) and 193 of the CAA; however, 
the State cannot remove the obligations from the SIP.
    (c) Which portions of an area designated for the 8-hour NAAQS remain 
subject to the obligations identified in paragraph (a) of this section? 
(1) Except as provided in paragraph (c)(2) of this section, only the 
portion of the designated area for the 8-hour NAAQS that was required to 
adopt the applicable requirements in Sec. 51.900(f) for purposes of the 
1-hour NAAQS is subject to the obligations identified in paragraph (a) 
of this section, including the requirement to submit a maintenance plan 
for purposes of paragraph (a)(3)(iii) of this section. 40 CFR part 81, 
subpart C identifies the boundaries of areas and the area designations 
and classifications for the 1-hour NAAQS in place as of the effective 
date of designation for the 8-hour NAAQS.
    (2) For purposes of paragraph (a)(1)(ii)(B) and (C) of this section, 
the requirement to achieve emission reductions applies to the entire 
area designated nonattainment for the 8-hour ozone NAAQS.
    (d) [Reserved]
    (e) What obligations that applied for the 1-hour NAAQS will no 
longer apply after revocation of the 1-hour NAAQS for an area?--(1) 
Maintenance plans. Upon revocation of the 1-hour NAAQS, an area with an 
approved 1-hour maintenance plan under section 175A of the CAA may 
modify the maintenance plan: To remove the obligation to submit a 
maintenance plan for the 1-hour NAAQS 8 years after approval of the 
initial 1-hour maintenance plan; and to remove the obligation to 
implement contingency measures upon a violation of the 1-hour NAAQS. 
However, such requirements will remain enforceable as part of the 
approved SIP until such time as EPA approves a SIP revision removing 
such obligations. The EPA shall not approve a SIP revision requesting 
these modifications until the State submits and EPA approves an 
attainment demonstration for the 8-hour NAAQS for an area initially 
designated nonattainment for the 8-hour ozone NAAQS or a maintenance SIP 
for the 8-hour NAAQS for an area initially designated attainment for the 
8-hour NAAQS. Any revision to such SIP must meet the requirements of 
section 110(l) and 193 of the CAA.
    (2) Findings of failure to attain the 1-hour NAAQS. (i) Upon 
revocation of the 1-hour NAAQS for an area, EPA is no longer obligated--
    (A) To determine pursuant to section 181(b)(2) or section 179(c) of 
the CAA whether an area attained the 1-hour NAAQS by that area's 
attainment date for the 1-hour NAAQS; or
    (B) To reclassify an area to a higher classification for the 1-hour 
NAAQS based upon a determination that the area failed to attain the 1-
hour NAAQS by the area's attainment date for the 1-hour NAAQS.
    (ii) Upon revocation of the 1-hour NAAQS for an area, the State is 
no longer required to include in its SIP provisions for CAA section 
181(b)(4) and 185 fees on emissions sources in areas classified as 
severe or extreme based on a failure to meet the 1-hour attainment date. 
Upon revocation of the 1-hour NAAQS in an area, the State may remove 
from the SIP for the area the provisions for complying with the section 
185 fee provision as it applies to the 1-hour NAAQS.
    (iii) Upon revocation of the 1-hour NAAQS for an area, the State is 
no longer required to include in its SIP

[[Page 385]]

contingency measures under CAA sections 172(c)(9) and 182(c)(9) that 
would be triggered based on a failure to attain the 1-hour NAAQS or to 
make reasonable further progress toward attainment of the 1-hour NAAQS. 
A State may not remove from the SIP a contingency measure that is an 
applicable requirement.
    (3) Conformity determinations for the 1-hour NAAQS. Upon revocation 
of the 1-hour NAAQS for an area, conformity determinations pursuant to 
section 176(c) of the CAA are no longer required for the 1-hour NAAQS. 
At that time, any provisions of applicable SIPs that require conformity 
determinations in such areas for the 1-hour NAAQS will no longer be 
enforceable pursuant to section 176(c)(5) of the CAA.
    (4) Nonattainment area new source review under the 1-hour NAAQS. (i) 
Upon revocation of the 1-hour ozone NAAQS, for any area that was 
designated nonattainment for the 1-hour ozone NAAQS, the area's 
implementation plan provisions satisfying sections 172(c)(5) and 173 of 
the CAA (including provisions satisfying section 182) based on the 
area's previous 1-hour ozone NAAQS classification are no longer required 
elements of an approvable implementation plan. Instead, the area's 
implementation plan must meet the requirements contained in paragraphs 
(e)(4)(ii) through (e)(4)(iv) of this section.
    (ii) If the area is designated nonattainment for the 8-hour ozone 
NAAQS, the implementation plan must include requirements to implement 
the provisions of sections 172(c)(5) and 173 of the CAA based on the 
area's 8-hour ozone NAAQS classification under part 81 of this chapter, 
and the provisions of Sec. 51.165.
    (iii) If the area is designated attainment or unclassifiable for the 
8-hour ozone NAAQS, the area's implementation plan must include 
provisions to implement the provisions of section 165 of the CAA, and 
the provisions of Sec. 51.166 of this part, unless the provisions of 
Sec. 52.21 of this chapter apply in such area.
    (iv) If the area is designated attainment or unclassifiable but is 
located in an Ozone Transport Region, the area's implementation plan 
must include provisions to implement, consistent with the requirements 
in section 184 of the CAA, the requirements of sections 172(c) and 173 
of the CAA as if the area is classified as moderate nonattainment for 
the 8-hour ozone NAAQS.
    (f) What is the continued applicability of the NOX SIP 
Call after revocation of the 1-hour NAAQS? The NOX SIP Call 
shall continue to apply after revocation of the 1-hour NAAQS. Control 
obligations approved into the SIP pursuant to 40 CFR 51.121 and 51.122 
may be modified by the State only if the requirements of Sec. Sec. 
51.121 and 51.122, including the statewide NOX emission 
budgets, continue to be met and the State makes a showing consistent 
with section 110(l) of the CAA.

[69 FR 23996, Apr. 30, 2004, as amended at 70 FR 30604, May 26, 2005; 70 
FR 44474, Aug. 3, 2005]



Sec. 51.906  Redesignation to nonattainment following initial 
designations for the 8-hour NAAQS.

    For any area that is initially designated attainment or 
unclassifiable for the 8-hour NAAQS and that is subsequently 
redesignated to nonattainment for the 8-hour ozone NAAQS, any absolute, 
fixed date applicable in connection with the requirements of this part 
is extended by a period of time equal to the length of time between the 
effective date of the initial designation for the 8-hour NAAQS and the 
effective date of redesignation, except as otherwise provided in this 
subpart.

[70 FR 71700, Nov. 29, 2005]



Sec. 51.907  For an area that fails to attain the 8-hour NAAQS by its 
attainment date, how does EPA interpret sections 172(a)(2)(C)(ii) and 
181(a)(5)(B) of the CAA?

    For purposes of applying sections 172(a)(2)(C) and 181(a)(5) of the 
CAA, an area will meet the requirement of section 172(a)(2)(C)(ii) or 
181(a)(5)(B) of the CAA pertaining to 1-year extensions of the 
attainment date if:
    (a) For the first 1-year extension, the area's 4th highest daily 8-
hour average in the attainment year is 0.084 ppm or less.
    (b) For the second 1-year extension, the area's 4th highest daily 8-
hour

[[Page 386]]

value, averaged over both the original attainment year and the first 
extension year, is 0.084 ppm or less.
    (c) For purposes of paragraphs (a) and (b) of this section, the 
area's 4th highest daily 8-hour average shall be from the monitor with 
the highest 4th highest daily 8-hour average of all the monitors that 
represent that area.



Sec. 51.908  What modeling and attainment demonstration requirements 
apply for purposes of the 8-hour ozone NAAQS?

    (a) What is the attainment demonstration requirement for an area 
classified as moderate or higher under subpart 2 pursuant to Sec. 
51.903? An area classified as moderate or higher under Sec. 51.903 
shall be subject to the attainment demonstration requirement applicable 
for that classification under section 182 of the Act, except such 
demonstration is due no later than 3 years after the area's designation 
for the 8-hour NAAQS.
    (b) What is the attainment demonstration requirement for an area 
subject only to subpart 1 in accordance with Sec. 51.902(b)? An area 
subject to Sec. 51.902(b) shall be subject to the attainment 
demonstration under section 172(c)(1) of the Act and shall submit an 
attainment demonstration no later than 3 years after the area's 
designation for the 8-hour NAAQS.
    (c) What criteria must the attainment demonstration meet? An 
attainment demonstration due pursuant to paragraph (a) or (b) of this 
section must meet the requirements of Sec. 51.112; the adequacy of an 
attainment demonstration shall be demonstrated by means of a 
photochemical grid model or any other analytical method determined by 
the Administrator, in the Administrator's discretion, to be at least as 
effective.
    (d)For each nonattainment area, the State must provide for 
implementation of all control measures needed for attainment no later 
than the beginning of the attainment year ozone season.

[69 FR 23996, Apr. 30, 2004, as amended at 70 FR 71700, Nov. 29, 2005]



Sec. 51.909  [Reserved]



Sec. 51.910  What requirements for reasonable further progress (RFP) 
under sections 172(c)(2) and 182 apply for areas designated nonattainment 
for the 8-hour ozone NAAQS?

    (a) What are the general requirements for RFP for an area classified 
under subpart 2 pursuant to Sec. 51.903? For an area classified under 
subpart 2 pursuant to Sec. 51.903, the RFP requirements specified in 
section 182 of the Act for that area's classification shall apply.
    (1) What is the content and timing of the RFP plan required under 
sections 182(b)(1) and 182(c)(2)(B) of the Act for an area classified as 
moderate or higher pursuant to Sec. 51.903 (subpart 2 coverage)?
    (i) Moderate or Above Area. (A) Except as provided in paragraph 
(a)(1)(ii) of this section, for each area classified as moderate or 
higher, the State shall submit a SIP revision consistent with section 
182(b)(1) of the Act no later than 3 years after designation for the 8-
hour NAAQS for the area. The 6-year period referenced in section 
182(b)(1) of the Act shall begin January 1 of the year following the 
year used for the baseline emissions inventory.
    (B) For each area classified as serious or higher, the State shall 
submit a SIP revision consistent with section 182(c)(2)(B) of the Act no 
later than 3 years after designation for the 8-hour NAAQS. The final 
increment of progress must be achieved no later than the attainment date 
for the area.
    (ii) Area with Approved 1-hour Ozone 15 Percent VOC ROP Plan. An 
area classified as moderate or higher that has the same boundaries as an 
area, or is entirely composed of several areas or portions of areas, for 
which EPA fully approved a 15 percent plan for the 1-hour NAAQS is 
considered to have met section 182(b)(1) of the Act for the 8-hour NAAQS 
and instead:
    (A) If classified as moderate, the area is subject to RFP under 
section 172(c)(2) of the Act and shall submit no later than 3 years 
after designation for the 8-hour NAAQS a SIP revision that meets the 
requirements of paragraph (b)(2) of this section, consistent with the 
attainment date established in the attainment demonstration SIP.

[[Page 387]]

    (B) If classified as serious or higher, the area is subject to RFP 
under section 182(c)(2)(B) of the Act and shall submit no later than 3 
years after designation for the 8-hour NAAQS an RFP SIP providing for an 
average of 3 percent per year of VOC and/or NOX emissions 
reductions for
    (1) the 6-year period beginning January 1 of the year following the 
year used for the baseline emissions inventory; and
    (2) all remaining 3-year periods after the first 6-year period out 
to the area's attainment date.
    (iii) Moderate and Above Area for Which Only a Portion Has an 
Approved 1-hour Ozone 15 Percent VOC ROP Plan. An area classified as 
moderate or higher that contains one or more areas, or portions of 
areas, for which EPA fully approved a 15 percent plan for the 1-hour 
NAAQS as well as areas for which EPA has not fully approved a 15 percent 
plan for the 1-hour NAAQS shall meet the requirements of either 
paragraph (a)(1)(iii)(A) or (B) below.
    (A) The State shall not distinguish between the portion of the area 
that previously met the 15 percent VOC reduction requirement and the 
portion of the area that did not, and
    (1) The State shall submit a SIP revision consistent with section 
182(b)(1) of the Act no later than 3 years after designation for the 8-
hour NAAQS for the entire area. The 6-year period referenced in section 
182(b)(1) of the Act shall begin January 1 of the year following the 
year used for the baseline emissions inventory.
    (2) For each area classified as serious or higher, the State shall 
submit a SIP revision consistent with section 182(c)(2)(B) of the Act no 
later than 3 years after designation for the 8-hour NAAQS. The final 
increment of progress must be achieved no later than the attainment date 
for the area.
    (B) The State shall treat the area as two parts, each with a 
separate RFP target as follows:
    (1) For the portion of the area without an approved 15 percent VOC 
RFP plan for the 1-hour standard, the State shall submit a SIP revision 
consistent with section 182(b)(1) of the Act no later than 3 years after 
designation for the 8-hour NAAQS for the area. The 6-year period 
referenced in section 182(b)(1) of the Act shall begin January 1 of the 
year following the year used for the baseline emissions inventory. 
Emissions reductions to meet this requirement may come from anywhere 
within the 8-hour nonattainment area.
    (2) For the portion of the area with an approved 15 percent VOC plan 
for the 1-hour NAAQS, the State shall submit a SIP as required under 
paragraph (b)(2)of this section.
    (2) What restrictions apply on the creditability of emission control 
measures for the RFP plans required under this section? Except as 
specifically provided in section 182(b)(1)(C) and (D) and section 
182(c)(2)(B) of the Act, all SIP-approved or federally promulgated 
emissions reductions that occur after the baseline emissions inventory 
year are creditable for purposes of the RFP requirements in this 
section, provided the reductions meet the requirements for 
creditability, including the need to be enforceable, permanent, 
quantifiable and surplus, as described for purposes of State economic 
incentive programs in the requirements of Sec. 51.493 of this part.
    (b) How does the RFP requirement of section 172(c)(2) of the Act 
apply to areas subject to that requirement? (1) An area subject to the 
RFP requirement of subpart 1 pursuant to Sec. 51.902(b) or a moderate 
area subject to subpart 2 as covered in paragraphs (a)(1)(ii)(A) of this 
section shall meet the RFP requirements of section 172(c)(2) of the Act 
as provided in paragraph (b)(2) of this section.
    (2) The State shall submit no later than 3 years following 
designation for the 8-hour NAAQS a SIP providing for RFP consistent with 
the following:
    (i) For each area with an attainment demonstration requesting an 
attainment date of 5 years or less after designation for the 8-hour 
NAAQS, the attainment demonstration SIP shall require that all emissions 
reductions needed for attainment be implemented by the beginning of the 
attainment year ozone season.
    (ii) For each area with an attainment demonstration requesting an 
attainment date more than 5 years after designation for the 8-hour 
NAAQS, the attainment demonstration SIP--

[[Page 388]]

    (A) Shall provide for a 15 percent emission reduction from the 
baseline year within 6 years after the baseline year.
    (B) May use either NOX or VOC emissions reductions (or 
both) to achieve the 15 percent emission reduction requirement. Use of 
NOX emissions reductions must meet the criteria in section 
182(c)(2)(C) of the Act.
    (C) For each subsequent 3-year period out to the attainment date, 
the RFP SIP must provide for an additional increment of progress. The 
increment for each 3-year period must be a portion of the remaining 
emission reductions needed for attainment beyond those reductions 
achieved for the first increment of progress (e.g., beyond 2008 for 
areas designated nonattainment in June 2004). Specifically, the amount 
of reductions needed for attainment is divided by the number of years 
needed for attainment after the first increment of progress in order to 
establish an ``annual increment.'' For each 3-year period out to the 
attainment date, the area must achieve roughly the portion of reductions 
equivalent to three annual increments.
    (c) What method should a State use to calculate RFP targets? In 
calculating RFP targets for the initial 6-year period and the subsequent 
3-year periods pursuant to this section, the State shall use the methods 
consistent with the requirements of sections 182(b)(1)(C) and (D) and 
182(c)(2)(B) to properly account for non-creditable reductions.
    (d) What is the baseline emissions inventory for RFP plans? For the 
RFP plans required under this section, the baseline emissions inventory 
shall be determined at the time of designation of the area for the 8-
hour NAAQS and shall be the emissions inventory for the most recent 
calendar year for which a complete inventory is required to be submitted 
to EPA under the provisions of subpart A of this part or a more recent 
alternative baseline emissions inventory provided the State demonstrates 
that the baseline inventory meets the CAA provisions for RFP and 
provides a rationale for why it is appropriate to use the alternative 
baseline year rather than 2002 to comply with the CAA's RFP provisions.

 [70 FR 71700, Nov. 29, 2005]



Sec. 51.911  [Reserved]



Sec. 51.912  What requirements apply for reasonably available control 
technology (RACT) and reasonably available control measures (RACM) under 
the 8-hour NAAQS?

    (a) What is the RACT requirement for areas subject to subpart 2 in 
accordance with Sec. 51.903? (1) For each area subject to subpart 2 in 
accordance with Sec. 51.903 of this part and classified moderate or 
higher, the State shall submit a SIP revision that meets the 
NOX and VOC RACT requirements in sections 182(b)(2) and 
182(f) of the Act.
    (2) The State shall submit the RACT SIP for each area no later than 
27 months after designation for the 8-hour ozone NAAQS.
    (3) The State shall provide for implementation of RACT as 
expeditiously as practicable but no later than the first ozone season or 
portion thereof which occurs 30 months after the RACT SIP is due.
    (b) How do the RACT provisions apply to a major stationary source? 
Volatile organic compounds and NOX are to be considered 
separately for purposes of determining whether a source is a major 
stationary source as defined in section 302 of the Act.
    (c) What is the RACT requirement for areas subject only to subpart 1 
pursuant to Sec. 51.902(b)? Areas subject only to subpart 1 pursuant to 
Sec. 51.902(b) are subject to the RACT requirement specified in section 
172(c)(1) of the Act.
    (1) For an area that submits an attainment demonstration that 
requests an attainment date 5 years or less after designation for the 8-
hour NAAQS, the State shall meet the RACT requirement by submitting an 
attainment demonstration SIP demonstrating that the area has adopted all 
control measures necessary to demonstrate attainment as expeditiously as 
practicable.
    (2) For an area that submits an attainment demonstration that 
requests an attainment date more than 5 years after designation for the 
8-hour NAAQS, the State shall submit a SIP consistent with the 
requirements of

[[Page 389]]

Sec. 51.912(a) and (b) except the State shall submit the RACT SIP for 
each area with its request pursuant to Clean Air Act section 
172(a)(2)(A) to extend the attainment date.
    (d) What is the Reasonably Available Control Measures (RACM) 
requirement for areas designated nonattainment for the 8-hour NAAQS? For 
each nonattainment area required to submit an attainment demonstration 
under Sec. 51.908, the State shall submit with the attainment 
demonstration a SIP revision demonstrating that it has adopted all RACM 
necessary to demonstrate attainment as expeditiously as practicable and 
to meet any RFP requirements.

[70 FR 71701, Nov. 29, 2005]



Sec. 51.913  How do the section 182(f) NOX exemption 
provisions apply for the 8-hour NAAQS?

    (a) A person may petition the Administrator for an exemption from 
NOX obligations under section 182(f) for any area designated 
nonattainment for the 8-hour ozone NAAQS and for any area in a section 
184 ozone transport region.
    (b) The petition must contain adequate documentation that the 
criteria in section 182(f) are met.
    (c) A section 182(f) NOX exemption granted for the 1-hour 
ozone standard does not relieve the area from any NOX 
obligations under section 182(f) for the 8-hour ozone standard.

[70 FR 71701, Nov. 29, 2005]



Sec. 51.914  What new source review requirements apply for 8-hour ozone 
nonattainment areas?

    The requirements for new source review for the 8-hour ozone standard 
are located in Sec. 51.165 of this part.

[70 FR 71702, Nov. 29, 2005]



Sec. 51.915  What emissions inventory requirements apply under the 
8-hour NAAQS?

    For each nonattainment area subject to subpart 2 in accordance with 
Sec. 51.903, the emissions inventory requirements in sections 182(a)(1) 
and 182(a)(3) of the Act shall apply, and such SIP shall be due no later 
2 years after designation. For each nonattainment area subject only to 
title I, part D, subpart 1 of the Act in accordance with Sec. 
51.902(b), the emissions inventory requirement in section 172(c)(3) of 
the Act shall apply, and an emission inventory SIP shall be due no later 
3 years after designation. For purposes of defining the data elements 
for the emissions inventories for these areas, the ozone-relevant data 
element requirements under 40 CFR part 51 subpart A apply.

[70 FR 71702, Nov. 29, 2005]



Sec. 51.916  What are the requirements for an Ozone Transport Region 
under the 8-hour NAAQS?

    (a) In General. Sections 176A and 184 of the Act apply for purposes 
of the 8-hour NAAQS.
    (b) RACT Requirements for Certain Portions of an Ozone Transport 
Region.
    (1) The State shall submit a SIP revision that meets the RACT 
requirements of section 184 of the Act for each area that is located in 
an ozone transport region and that is--
    (i) Designated as attainment or unclassifiable for the 8-hour 
standard;
    (ii) Designated nonattainment and classified as marginal for the 8-
hour standard; or
    (iii) Designated nonattainment and covered solely under subpart 1 of 
part D, title I of the CAA for the 8-hour standard.
    (2) The State is required to submit the RACT revision no later than 
September 16, 2006 and shall provide for implementation of RACT as 
expeditiously as practicable but no later than May 1, 2009.

[70 FR 71702, Nov. 29, 2005]



Sec. 51.917  What is the effective date of designation for the Las 
Vegas, NV, 8-hour ozone nonattainment area?

    The Las Vegas, NV, 8-hour ozone nonattainment area (designated on 
September 17, 2004 (69 FR 55956)) shall be treated as having an 
effective date of designation of June 15, 2004, for purposes of 
calculating SIP submission deadlines, attainment dates, or any other 
deadline under this subpart.

[70 FR 71702, Nov. 29, 2005]

[[Page 390]]



Sec. 51.918  Can any SIP planning requirements be suspended in 8-hour 
ozone nonattainment areas that have air quality data that meets the NAAQS?

    Upon a determination by EPA that an area designated nonattainment 
for the 8-hour ozone NAAQS has attained the standard, the requirements 
for such area to submit attainment demonstrations and associated 
reasonably available control measures, reasonable further progress 
plans, contingency measures, and other planning SIPs related to 
attainment of the 8-hour ozone NAAQS shall be suspended until such time 
as: the area is redesignated to attainment, at which time the 
requirements no longer apply; or EPA determines that the area has 
violated the 8-hour ozone NAAQS.

[70 FR 71702, Nov. 29, 2005]

                  Appendixes A-K to Part 51 [Reserved]

    Appendix L to Part 51--Example Regulations for Prevention of Air 
                      Pollution Emergency Episodes

    The example regulations presented herein reflect generally 
recognized ways of preventing air pollution from reaching levels that 
would cause imminent and substantial endangerment to the health of 
persons. States are required under subpart H to have emergency episodes 
plans but they are not required to adopt the regulations presented 
herein.
    1.0 Air pollution emergency. This regulation is designed to prevent 
the excessive buildup of air pollutants during air pollution episodes, 
thereby preventing the occurrence of an emergency due to the effects of 
these pollutants on the health of persons.
    1.1 Episode criteria. Conditions justifying the proclamation of an 
air pollution alert, air pollution warning, or air pollution emergency 
shall be deemed to exist whenever the Director determines that the 
accumulation of air pollutants in any place is attaining or has attained 
levels which could, if such levels are sustained or exceeded, lead to a 
substantial threat to the health of persons. In making this 
determination, the Director will be guided by the following criteria:
    (a) Air Pollution Forecast: An internal watch by the Department of 
Air Pollution Control shall be actuated by a National Weather Service 
advisory that Atmospheric Stagnation Advisory is in effect or the 
equivalent local forecast of stagnant atmospheric condition.
    (b) Alert: The Alert level is that concentration of pollutants at 
which first stage control actions is to begin. An Alert will be declared 
when any one of the following levels is reached at any monitoring site:
SO2--800 [micro]g/m\3\ (0.3 p.p.m.), 24-hour average.
PM10--350 [micro]g/m\3\, 24-hour average.
CO--17 mg/m\3\ (15 p.p.m.), 8-hour average.
Ozone (O2)=400 [micro]g/m\3\ (0.2 ppm)-hour average.
NO2-1130 [micro]g/m\3\ (0.6 p.p.m.), 1-hour average, 282 
[micro]g/m\3\ (0.15 p.p.m.), 24-hour average.
    In addition to the levels listed for the above pollutants, 
meterological conditions are such that pollutant concentrations can be 
expected to remain at the above levels for twelve (12) or more hours or 
increase, or in the case of ozone, the situation is likely to reoccur 
within the next 24-hours unless control actions are taken.
    (c) Warning: The warning level indicates that air quality is 
continuing to degrade and that additional control actions are necessary. 
A warning will be declared when any one of the following levels is 
reached at any monitoring site:

SO2--1,600 [micro]g/m\3\ (0.6 p.p.m.), 24-hour average.
PM10--420 [micro]g/m\3\, 24-hour average.
CO--34 mg/m\3\ (30 p.p.m.), 8-hour average.
Ozone (O3)--800 [micro]g/m\3\ (0.4 p.p.m.), 1-hour average.
NO2--2,260 [micro]g/m\3\ (1.2 ppm)--1-hour average; 565 
[micro]g/m\3\ (0.3 ppm), 24-hour average.

    In addition to the levels listed for the above pollutants, 
meterological conditions are such that pollutant concentrations can be 
expected to remain at the above levels for twelve (12) or more hours or 
increase, or in the case of ozone, the situation is likely to reoccur 
within the next 24-hours unless control actions are taken.
    (d) Emergency: The emergency level indicates that air quality is 
continuing to degrade toward a level of significant harm to the health 
of persons and that the most stringent control actions are necessary. An 
emergency will be declared when any one of the following levels is 
reached at any monitoring site:

SO2--2,100 [micro]g/m\3\ (0.8 p.p.m.), 24-hour average.
    PM10--500 [micro]g/m\3\, 24-hour average.
CO--46 mg/m\3\ (40 p.p.m.), 8-hour average.
Ozone (O3)--1,000 [micro]g/m\3\ (0.5 p.p.m.), 1-hour average.
NO2-3,000 [micro]g/m\3\ (1.6 ppm), 1-hour average; 750 
[micro]g/m\3\ (0.4 ppm), 24-hour average.

    In addition to the levels listed for the above pollutants, 
meterological conditions are such that pollutant concentrations can be 
expected to remain at the above levels for twelve (12) or more hours or 
increase, or in the case of ozone, the situation is likely to reoccur 
within the next 24-hours unless control actions are taken.
    (e) Termination: Once declared, any status reached by application of 
these criteria will

[[Page 391]]

remain in effect until the criteria for that level are no longer met. At 
such time, the next lower status will be assumed.
    1.2 Emission reduction plans. (a) Air Pollution Alert--When the 
Director declares an Air Pollution Alert, any person responsible for the 
operation of a source of air pollutants as set forth in Table I shall 
take all Air Pollution Alert actions as required for such source of air 
pollutants and shall put into effect the preplanned abatement strategy 
for an Air Pollution Alert.
    (b) Air Pollution Warning--When the Director declares an Air 
Pollution Warning, any person responsible for the operation of a source 
of air pollutants as set forth in Table II shall take all Air Pollution 
Warning actions as required for such source of air pollutants and shall 
put into effect the preplanned abatement strategy for an Air Pollution 
Warning.
    (c) Air Pollution Emergency--When the Director declares an Air 
Pollution Emergency, any person responsible for the operation of a 
source of air pollutants as described in Table III shall take all Air 
Pollution Emergency actions as required for such source of air 
pollutants and shall put into effect the preplanned abatement strategy 
for an Air Pollution Emergency.
    (d) When the Director determines that a specified criteria level has 
been reached at one or more monitoring sites solely because of emissions 
from a limited number of sources, he shall notify such source(s) that 
the preplanned abatement strategies of Tables I, II, and III or the 
standby plans are required, insofar as it applies to such source(s), and 
shall be put into effect until the criteria of the specified level are 
no longer met.
    1.3 Preplanned abatement strategies, (a) Any person responsible for 
the operation of a source of air pollutants as set forth in Tables I-III 
shall prepare standby plans for reducing the emission of air pollutants 
during periods of an Air Pollution Alert, Air Pollution Warning, and Air 
Pollution Emergency. Standby plans shall be designed to reduce or 
eliminate emissions of air pollutants in accordance with the objectives 
set forth in Tables I-III which are made a part of this section.
    (b) Any person responsible for the operation of a source of air 
pollutants not set forth under section 1.3(a) shall, when requested by 
the Director in writing, prepare standby plans for reducing the emission 
of air pollutants during periods of an Air Pollution Alert, Air 
Pollution Warning, and Air Pollution Emergency. Standby plans shall be 
designed to reduce or eliminate emissions of air pollutants in 
accordance with the objectives set forth in Tables I-III.
    (c) Standby plans as required under section 1.3(a) and (b) shall be 
in writing and identify the sources of air pollutants, the approximate 
amount of reduction of pollutants and a brief description of the manner 
in which the reduction will be achieved during an Air Pollution Alert, 
Air Pollution Warning, and Air Pollution Emergency.
    (d) During a condition of Air Pollution Alert, Air Pollution 
Warning, and Air Pollution Emergency, standby plans as required by this 
section shall be made available on the premises to any person authorized 
to enforce the provisions of applicable rules and regulations.
    (e) Standby plans as required by this section shall be submitted to 
the Director upon request within thirty (30) days of the receipt of such 
request; such standby plans shall be subject to review and approval by 
the Director. If, in the opinion of the Director, a standby plan does 
not effectively carry out the objectives as set forth in Table I-III, 
the Director may disapprove it, state his reason for disapproval and 
order the preparation of an amended standby plan within the time period 
specified in the order.

   Table I--Abatement Strategies Emission Reduction Plans alert level

                             Part A. General

    1. There shall be no open burning by any persons of tree waste, 
vegetation, refuse, or debris in any form.
    2. The use of incinerators for the disposal of any form of solid 
waste shall be limited to the hours between 12 noon and 4 p.m.
    3. Persons operating fuel-burning equipment which required boiler 
lancing or soot blowing shall perform such operations only between the 
hours of 12 noon and 4 p.m.
    4. Persons operating motor vehicles should eliminate all unnecessary 
operations.

                       Part B. Source curtailment

    Any person responsible for the operation of a source of air 
pollutants listed below shall take all required control actions for this 
Alert Level.

------------------------------------------------------------------------
      Source of air pollution                  Control action
------------------------------------------------------------------------
1. Coal or oil-fired electric       a. Substantial reduction by
 power generating facilities.        utilization of fuels having low ash
                                     and sulfur content.
                                    b. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing and
                                     soot blowing.
                                    c. Substantial reduction by
                                     diverting electric power generation
                                     to facilities outside of Alert
                                     Area.

[[Page 392]]

 
2. Coal and oil-fired process       a. Substantial reduction by
 steam generating facilities.        utilization of fuels having low ash
                                     and sulfur content.
                                    b. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing and
                                     soot blowing.
                                    c. Substantial reduction of steam
                                     load demands consistent with
                                     continuing plant operations.
3. Manufacturing industries of the  a. Substantial reduction of air
 following classifications:          pollutants from manufacturing
 Primary Metals Industry.            operations by curtailing,
 Petroleum Refining Operations.      postponing, or deferring production
 Chemical Industries.                and all operations.
 Mineral Processing Industries.     b. Maximum reduction by deferring
 Paper and Allied Products.          trade waste disposal operations
 Grain Industry.                     which emit solid particles, gas
                                     vapors or malodorous substances.
                                    c. Maximum reduction of heat load
                                     demands for processing.
                                    d. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing and
                                     soot blowing.
------------------------------------------------------------------------

                   Table II--Emission Reduction Plans

                              warning level

                             Part A. General

    1. There shall be no open burning by any persons of tree waste, 
vegetation, refuse, or debris in any form.
    2. The use of incinerators for the disposal of any form of solid 
waste or liquid waste shall be prohibited.
    3. Persons operating fuel-burning equipment which requires boiler 
lancing or soot blowing shall perform such operations only between the 
hours of 12 noon and 4 p.m.
    4. Persons operating motor vehicles must reduce operations by the 
use of car pools and increased use of public transportation and 
elimination of unnecessary operation.

                       Part B. Source curtailment

    Any person responsible for the operation of a source of air 
pollutants listed below shall take all required control actions for this 
Warning Level.

------------------------------------------------------------------------
      Source of air pollution                  Control action
------------------------------------------------------------------------
1. Coal or oil-fired process steam  a. Maximum reduction by utilization
 generating facilities.              of fuels having lowest ash and
                                     sulfur content.
                                    b. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing and
                                     soot blowing.
                                    c. Maximum reduction by diverting
                                     electric power generation to
                                     facilities outside of Warning Area.
2. Oil and oil-fired process steam  a. Maximum reduction by utilization
 generating facilities.              of fuels having the lowest
                                     available ash and sulfur content.
                                    b. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing and
                                     soot blowing.
                                    c. Making ready for use a plan of
                                     action to be taken if an emergency
                                     develops.
3. Manufacturing industries which   a. Maximum reduction of air
 require considerable lead time      contaminants from manufacturing
 for shut-down including the         operations by, if necessary,
 following classifications:          assuming reasonable economic
 Petroleum Refining.                 hardships by postponing production
 Chemical Industries.                and allied operation.
 Primary Metals Industries.         b. Maximum reduction by deferring
 Glass Industries.                   trade waste disposal operations
 Paper and Allied Products.          which emit solid particles, gases,
                                     vapors or malodorous substances.
                                    c. Maximum reduction of heat load
                                     demands for processing.
                                    d. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing or
                                     soot blowing.
4. Manufacturing industries         a. Elimination of air pollutants
 require relatively short lead       from manufacturing operations by
 times for shut-down including the   ceasing, curtailing, postponing or
 following classifications:          deferring production and allied
 Primary Metals Industries.          operations to the extent possible
 Chemical Industries.                without causing injury to persons
 Mineral Processing Industries.      or damage to equipment.
 Grain Industry.                    b. Elimination of air pollutants
                                     from trade waste disposal processes
                                     which emit solid particles, gases,
                                     vapors or malodorous substances.
                                    c. Maximum reduction of heat load
                                     demands for processing.
                                    d. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing or
                                     soot blowing.
------------------------------------------------------------------------


[[Page 393]]

                   Table III--Emission Reduction Plans

                             emergency level

                             Part A. General

    1. There shall be no open burning by any persons of tree waste, 
vegetation, refuse, or debris in any form.
    2. The use of incinerators for the disposal of any form of solid or 
liquid waste shall be prohibited.
    3. All places of employment described below shall immediately cease 
operations.
    a. Mining and quarrying of nonmetallic minerals.
    b. All construction work except that which must proceed to avoid 
emergent physical harm.
    c. All manufacturing establishments except those required to have in 
force an air pollution emergency plan.
    d. All wholesale trade establishments; i.e., places of business 
primarily engaged in selling merchandise to retailers, or industrial, 
commercial, institutional or professional users, or to other 
wholesalers, or acting as agents in buying merchandise for or selling 
merchandise to such persons or companies, except those engaged in the 
distribution of drugs, surgical supplies and food.
    e. All offices of local, county and State government including 
authorities, joint meetings, and other public bodies excepting such 
agencies which are determined by the chief administrative officer of 
local, county, or State government, authorities, joint meetings and 
other public bodies to be vital for public safety and welfare and the 
enforcement of the provisions of this order.
    f. All retail trade establishments except pharmacies, surgical 
supply distributors, and stores primarily engaged in the sale of food.
    g. Banks, credit agencies other than banks, securities and 
commodities brokers, dealers, exchanges and services; offices of 
insurance carriers, agents and brokers, real estate offices.
    h. Wholesale and retail laundries, laundry services and cleaning and 
dyeing establishments; photographic studios; beauty shops, barber shops, 
shoe repair shops.
    i. Advertising offices; consumer credit reporting, adjustment and 
collection agencies; duplicating, addressing, blueprinting; 
photocopying, mailing, mailing list and stenographic services; equipment 
rental services, commercial testing laboratories.
    j. Automobile repair, automobile services, garages.
    k. Establishments rendering amusement and recreational services 
including motion picture theaters.
    l. Elementary and secondary schools, colleges, universities, 
professional schools, junior colleges, vocational schools, and public 
and private libraries.
    4. All commercial and manufacturing establishments not included in 
this order will institute such actions as will result in maximum 
reduction of air pollutants from their operation by ceasing, curtailing, 
or postponing operations which emit air pollutants to the extent 
possible without causing injury to persons or damage to equipment.
    5. The use of motor vehicles is prohibited except in emergencies 
with the approval of local or State police.

                       Part B. Source curtailment

    Any person responsible for the operation of a source of air 
pollutants listed below shall take all required control actions for this 
Emergency Level.

------------------------------------------------------------------------
      Source of air pollution                  Control action
------------------------------------------------------------------------
1. Coal or oil-fired electric       a. Maximum reduction by utilization
 power generating facilities.        of fuels having lowest ash and
                                     sulfur content.
                                    b. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing or
                                     soot blowing.
                                    c. Maximum reduction by diverting
                                     electric power generation to
                                     facilities outside of Emergency
                                     Area.
2. Coal and oil-fired process       a. Maximum reduction by reducing
 steam generating facilities.        heat and steam demands to absolute
                                     necessities consistent with
                                     preventing equipment damage.
                                    b. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing and
                                     soot blowing.
                                    c. Taking the action called for in
                                     the emergency plan.
3. Manufacturing industries of the  a. Elimination of air pollutants
 following classifications:          from manufacturing operations by
 Primary Metals Industries.          ceasing, curtailing, postponing or
 Petroleum Refining.                 deferring production and allied
 Chemical Industries.                operations to the extent possible
 Mineral Processing Industries.      without causing injury to persons
 Grain Industry.                     or damage to equipment.
 Paper and Allied Products.         b. Elimination of air pollutants
                                     from trade waste disposal processes
                                     which emit solid particles, gases,
                                     vapors or malodorous substances.
                                    c. Maximum reduction of heat load
                                     demands for processing.
                                    d. Maximum utilization of mid-day
                                     (12 noon to 4 p.m.) atmospheric
                                     turbulence for boiler lancing or
                                     soot blowing.
------------------------------------------------------------------------


[[Page 394]]


(Secs. 110, 301(a), 313, 319, Clean Air Act (42 U.S.C. 7410, 7601(a), 
7613, 7619))

[36 FR 22398, Nov. 25, 1971; 36 FR 24002, Dec. 17, 1971, as amended at 
37 FR 26312, Dec. 9, 1972; 40 FR 36333, Aug. 20, 1975; 41 FR 35676, Aug. 
24, 1976; 44 FR 27570, May 10, 1979; 51 FR 40675, Nov. 7, 1986; 52 FR 
24714, July 1, 1987]

Appendix M to Part 51--Recommended Test Methods for State Implementation 
                                  Plans

Method 201--Determination of PM10 Emissions (Exhaust Gas 
Recycle Procedure).
Method 201A--Determination of PM10 Emissions (Constant 
Sampling Rate Procedure).
Method 202--Determination of Condensible Particulate Emissions From 
Stationary Sources
Method 204--Criteria for and Verification of a Permanent or Temporary 
Total Enclosure.
Method 204A--Volatile Organic Compounds Content in Liquid Input Stream.
Method 204B--Volatile Organic Compounds Emissions in Captured Stream.
Method 204C--Volatile Organic Compounds Emissions in Captured Stream 
(Dilution Technique).
Method 204D--Volatile Organic Compounds Emissions in Uncaptured Stream 
from Temporary Total Enclosure.
Method 204E--Volatile Organic Compounds Emissions in Uncaptured Stream 
from Building Enclosure.
Method 204F--Volatile Organic Compounds Content in Liquid Input Stream 
(Distillation Approach).
Method 205--Verification of Gas Dilution Systems for Field Instrument 
Calibrations

    Presented herein are recommended test methods for measuring air 
pollutantemanating from an emission source. They are provided for States 
to use in their plans to meet the requirements of subpart K--Source 
Surveillance.
    The State may also choose to adopt other methods to meet the 
requirements of subpart K of this part, subject to the normal plan 
review process.
    The State may also meet the requirements of subpart K of this part 
by adopting, again subject to the normal plan review process, any of the 
relevant methods in appendix A to 40 CFR part 60.

         Method 201--Determination of PM10 Emissions

                     (exhaust gas recycle procedure)

                     1. Applicability and Principle

    1.1 Applicability. This method applies to the in-stack measurement 
of particulate matter (PM) emissions equal to or less than an 
aerodynamic diameter of nominally 10 [micro]m (PM10) from 
stationary sources. The EPA recognizes that condensible emissions not 
collected by an in-stack method are also PM10, and that 
emissions that contribute to ambient PM10 levels are the sum 
of condensible emissions and emissions measured by an in-stack 
PM10 method, such as this method or Method 201A. Therefore, 
for establishing source contributions to ambient levels of 
PM10, such as for emission inventory purposes, EPA suggests 
that source PM10 measurement include both in-stack 
PM10 and condensible emissions. Condensible missions may be 
measured by an impinger analysis in combination with this method.
    1.2 Principle. A gas sample is isokinetically extracted from the 
source. An in-stack cyclone is used to separate PM greater than 
PM10, and an in-stack glass fiber filter is used to collect 
the PM10. To maintain isokinetic flow rate conditions at the 
tip of the probe and a constant flow rate through the cyclone, a clean, 
dried portion of the sample gas at stack temperature is recycled into 
the nozzle. The particulate mass is determined gravimetrically after 
removal of uncombined water.

                              2. Apparatus

    Note: Method 5 as cited in this method refers to the method in 40 
CFR part 60, appendix A.
    2.1 Sampling Train. A schematic of the exhaust of the exhaust gas 
recycle (EGR) train is shown in Figure 1 of this method.
    2.1.1 Nozzle with Recycle Attachment. Stainless steel (316 or 
equivalent) with a sharp tapered leading edge, and recycle attachment 
welded directly on the side of the nozzle (see schematic in Figure 2 of 
this method). The angle of the taper shall be on the outside. Use only 
straight sampling nozzles. ``Gooseneck'' or other nozzle extensions 
designed to turn the sample gas flow 90[deg], as in Method 5 are not 
acceptable. Locate a thermocouple in the recycle attachment to measure 
the temperature of the recycle gas as shown in Figure 3 of this method. 
The recycle attachment shall be made of stainless steel and shall be 
connected to the probe and nozzle with stainless steel fittings. Two 
nozzle sizes, e.g., 0.125 and 0.160 in., should be available to allow 
isokinetic sampling to be conducted over a range of flow rates. 
Calibrate each nozzle as described in Method 5, Section 5.1.
    2.1.2 PM10 Sizer. Cyclone, meeting the specifications in 
Section 5.7 of this method.
    2.1.3 Filter Holder. 63mm, stainless steel. An Andersen filter, part 
number SE274, has been found to be acceptable for the in-stack filter.


[[Page 395]]


    Note: Mention of trade names or specific products does not 
constitute endorsement by the Environmental Protection Agency.

    2.1.4 Pitot Tube. Same as in Method 5, Section 2.1.3. Attach the 
pitot to the pitot lines with stainless steel fittings and to the 
cyclone in a configuration similar to that shown in Figure 3 of this 
method. The pitot lines shall be made of heat resistant material and 
attached to the probe with stainless steel fittings.
    2.1.5 EGR Probe. Stainless steel, 15.9-mm (\5/8\-in.) ID tubing with 
a probe liner, stainless steel 9.53-mm (\3/8\-in.) ID stainless steel 
recycle tubing, two 6.35-mm (\1/4\-in.) ID stainless steel tubing for 
the pitot tube extensions, three thermocouple leads, and one power lead, 
all contained by stainless steel tubing with a diameter of approximately 
51 mm (2.0 in.). Design considerations should include minimum weight 
construction materials sufficient for probe structural strength. Wrap 
the sample and recycle tubes with a heating tape to heat the sample and 
recycle gases to stack temperature.
    2.1.6 Condenser. Same as in Method 5, Section 2.1.7.
    2.1.7 Umbilical Connector. Flexible tubing with thermocouple and 
power leads of sufficient length to connect probe to meter and flow 
control console.
    2.1.8 Vacuum Pump. Leak-tight, oil-less, noncontaminating, with an 
absolute filter, ``HEPA'' type, at the pump exit. A Gast Model 0522-V103 
G18DX pump has been found to be satisfactory.
    2.1.9 Meter and Flow Control Console. System consisting of a dry gas 
meter and calibrated orifice for measuring sample flow rate and capable 
of measuring volume to 2 percent, calibrated 
laminar flow elements (LFE's) or equivalent for measuring total and 
sample flow rates, probe heater control, and manometers and magnehelic 
gauges (as shown in Figures 4 and 5 of this method), or equivalent. 
Temperatures needed for calculations include stack, recycle, probe, dry 
gas meter, filter, and total flow. Flow measurements include velocity 
head ([Delta]p), orifice differential pressure ([Delta]H), total flow, 
recycle flow, and total back-pressure through the system.
    2.1.10 Barometer. Same as in Method 5, Section 2.1.9.
    2.1.11 Rubber Tubing. 6.35-mm (\1/4\-in.) ID flexible rubber tubing.
    2.2 Sample Recovery.
    2.2.1 Nozzle, Cyclone, and Filter Holder Brushes. Nylon bristle 
brushes property sized and shaped for cleaning the nozzle, cyclone, 
filter holder, and probe or probe liner, with stainless steel wire 
shafts and handles.
    2.2.2 Wash Bottles, Glass Sample Storage Containers, Petri Dishes, 
Graduated Cylinder and Balance, Plastic Storage Containers, and Funnels. 
Same as Method 5, Sections 2.2.2 through 2.2.6 and 2.2.8, respectively.
    2.3 Analysis. Same as in Method 5, Section 2.3.

                               3. Reagents

    The reagents used in sampling, sample recovery, and analysis are the 
same as that specified in Method 5, Sections 3.1, 3.2, and 3.3, 
respectively.

                              4. Procedure

    4.1 Sampling. The complexity of this method is such that, in order 
to obtain reliable results, testers should be trained and experienced 
with the test procedures.
    4.1.1 Pretest Preparation. Same as in Method 5, Section 4.1.1.
    4.1.2 Preliminary Determinations. Same as Method 5, Section 4.1.2, 
except use the directions on nozzle size selection in this section. Use 
of the EGR method may require a minimum sampling port diameter of 0.2 m 
(6 in.). Also, the required maximum number of sample traverse points at 
any location shall be 12.
    4.1.2.1 The cyclone and filter holder must be in-stack or at stack 
temperature during sampling. The blockage effects of the EGR sampling 
assembly will be minimal if the cross-sectional area of the sampling 
assembly is 3 percent or less of the cross-sectional area of the duct 
and a pitot coefficient of 0.84 may be assigned to the pitot. If the 
cross-sectional area of the assembly is greater than 3 percent of the 
cross-sectional area of the duct, then either determine the pitot 
coefficient at sampling conditions or use a standard pitot with a known 
coefficient in a configuration with the EGR sampling assembly such that 
flow disturbances are minimized.
    4.1.2.2 Construct a setup of pressure drops for various [Delta]p's 
and temperatures. A computer is useful for these calculations. An 
example of the output of the EGR setup program is shown in Figure 6 of 
this method, and directions on its use are in section 4.1.5.2 of this 
method. Computer programs, written in IBM BASIC computer language, to do 
these types of setup and reduction calculations for the EGR procedure, 
are available through the National Technical Information Services 
(NTIS), Accession number PB90-500000, 5285 Port Royal Road, Springfield, 
VA 22161.
    4.1.2.3 The EGR setup program allows the tester to select the nozzle 
size based on anticipated average stack conditions and prints a setup 
sheet for field use. The amount of recycle through the nozzle should be 
between 10 and 80 percent. Inputs for the EGR setup program are stack 
temperature (minimum, maximum, and average), stack velocity (minimum, 
maximum, and average), atmospheric pressure, stack static pressure, 
meter box temperature, stack moisture, percent 02,

[[Page 396]]

and percent CO2 in the stack gas, pitot coefficient 
(Cp), orifice [Delta] H2, flow rate measurement 
calibration values [slope (m) and y-intercept (b) of the calibration 
curve], and the number of nozzles available and their diameters.
    4.1.2.4 A less rigorous calculation for the setup sheet can be done 
manually using the equations on the example worksheets in Figures 7, 8, 
and 9 of this method, or by a Hewlett-Packard HP41 calculator using the 
program provided in appendix D of the EGR operators manual, entitled 
Applications Guide for Source PM10 Exhaust Gas Recycle 
Sampling System. This calculation uses an approximation of the total 
flow rate and agrees within 1 percent of the exact solution for pressure 
drops at stack temperatures from 38 to 260 [deg]C (100 to 500 [deg]F) 
and stack moisture up to 50 percent. Also, the example worksheets use a 
constant stack temperature in the calculation, ingoring the complicated 
temperature dependence from all three pressure drop equations. Errors 
for this at stack temperatures 28 [deg]C (50 [deg]F) of the temperature used in the setup 
calculations are within 5 percent for flow rate and within 5 percent for 
cyclone cut size.
    4.1.2.5 The pressure upstream of the LFE's is assumed to be constant 
at 0.6 in. Hg in the EGR setup calculations.
    4.1.2.6 The setup sheet constructed using this procedure shall be 
similar to Figure 6 of this method. Inputs needed for the calculation 
are the same as for the setup computer except that stack velocities are 
not needed.
    4.1.3 Preparation of Collection Train. Same as in Method 5, Section 
4.1.3, except use the following directions to set up the train.
    4.1.3.1 Assemble the EGR sampling device, and attach it to probe as 
shown in Figure 3 of this method. If stack temperatures exceed 260 
[deg]C (500 [deg]F), then assemble the EGR cyclone without the O-ring 
and reduce the vacuum requirement to 130 mm Hg (5.0 in. Hg) in the leak-
check procedure in Section 4.1.4.3.2 of this method.
    4.1.3.2 Connect the proble directly to the filter holder and 
condenser as in Method 5. Connect the condenser and probe to the meter 
and flow control console with the umbilical connector. Plug in the pump 
and attach pump lines to the meter and flow control console.
    4.1.4 Leak-Check Procedure. The leak-check for the EGR Method 
consists of two parts: the sample-side and the recycle-side. The sample-
side leak-check is required at the beginning of the run with the cyclone 
attached, and after the run with the cyclone removed. The cyclone is 
removed before the post-test leak-check to prevent any disturbance of 
the collected sample prior to analysis. The recycle-side leak-check 
tests the leak tight integrity of the recycle components and is required 
prior to the first test run and after each shipment.
    4.1.4.1 Pretest Leak-Check. A pretest leak-check of the entire 
sample-side, including the cyclone and nozzle, is required. Use the 
leak-check procedure in Section 4.1.4.3 of this method to conduct a 
pretest leak-check.
    4.1.4.2 Leak-Checks During Sample Run. Same as in Method 5, Section 
4.1.4.1.
    4.1.4.3 Post-Test Leak-Check. A leak-check is required at the 
conclusion of each sampling run. Remove the cyclone before the leak-
check to prevent the vacuum created by the cooling of the probe from 
disturbing the collected sample and use the following procedure to 
conduct a post-test leak-check.
    4.1.4.3.1 The sample-side leak-check is performed as follows: After 
removing the cyclone, seal the probe with a leak-tight stopper. Before 
starting pump, close the coarse total valve and both recycle valves, and 
open completely the sample back pressure valve and the fine total valve. 
After turning the pump on, partially open the coarse total valve slowly 
to prevent a surge in the manometer. Adjust the vacuum to at least 381 
mm Hg (15.0 in. Hg) with the fine total valve. If the desired vacuum is 
exceeded, either leak-check at this higher vacuum or end the leak-check 
as shown below and start over.

    Caution: Do not decrease the vacuum with any of the valves. This may 
cause a rupture of the filter.

    Note: A lower vacuum may be used, provided that it is not exceeded 
during the test.

    4.1.4.3.2 Leak rates in excess of 0.00057 m\3\/min (0.020 ft\3\/min) 
are unacceptable. If the leak rate is too high, void the sampling run.
    4.1.4.3.3 To complete the leak-check, slowly remove the stopper from 
the nozzle until the vacuum is near zero, then immediately turn off the 
pump. This procedure sequence prevents a pressure surge in the manometer 
fluid and rupture of the filter.
    4.1.4.3.4 The recycle-side leak-check is performed as follows: Close 
the coarse and fine total valves and sample back pressure valve. Plug 
the sample inlet at the meter box. Turn on the power and the pump, close 
the recycle valves, and open the total flow valves. Adjust the total 
flow fine adjust valve until a vacuum of 25 inches of mercury is 
achieved. If the desired vacuum is exceeded, either leak-check at this 
higher vacuum, or end the leak-check and start over. Minimum acceptable 
leak rates are the same as for the sample-side. If the leak rate is too 
high, void the sampling run.
    4.1.5 EGR Train Operation. Same as in Method 5, Section 4.1.5, 
except omit references to nomographs and recommendations about changing 
the filter assembly during a run.
    4.1.5.1 Record the data required on a data sheet such as the one 
shown in Figure 10 of this method. Make periodic checks of the manometer 
level and zero to ensure correct [Delta]H and [Delta]p values. An 
acceptable procedure

[[Page 397]]

for checking the zero is to equalize the pressure at both ends of the 
manometer by pulling off the tubing, allowing the fluid to equilibrate 
and, if necessary, to re-zero. Maintain the probe temperature to within 
11 [deg]C (20 [deg]F) of stack temperature.
    4.1.5.2 The procedure for using the example EGR setup sheet is as 
follows: Obtain a stack velocity reading from the pitot manometer 
([Delta]p), and find this value on the ordinate axis of the setup sheet. 
Find the stack temperature on the abscissa. Where these two values 
intersect are the differential pressures necessary to achieve 
isokineticity and 10 [micro]m cut size (interpolation may be necessary).
    4.1.5.3 The top three numbers are differential pressures (in. 
H2 O), and the bottom number is the percent recycle at these 
flow settings. Adjust the total flow rate valves, coarse and fine, to 
the sample value ([Delta]H) on the setup sheet, and the recycle flow 
rate valves, coarse and fine, to the recycle flow on the setup sheet.
    4.1.5.4 For startup of the EGR sample train, the following procedure 
is recommended. Preheat the cyclone in the stack for 30 minutes. Close 
both the sample and recycle coarse valves. Open the fine total, fine 
recycle, and sample back pressure valves halfway. Ensure that the nozzle 
is properly aligned with the sample stream. After noting the [Delta]p 
and stack temperature, select the appropriate [Delta]H and recycle from 
the EGR setup sheet. Start the pump and timing device simultaneously. 
Immediately open both the coarse total and the coarse recycle valves 
slowly to obtain the approximate desired values. Adjust both the fine 
total and the fine recycle valves to achieve more precisely the desired 
values. In the EGR flow system, adjustment of either valve will result 
in a change in both total and recycle flow rates, and a slight iteration 
between the total and recycle valves may be necessary. Because the 
sample back pressure valve controls the total flow rate through the 
system, it may be necessary to adjust this valve in order to obtain the 
correct flow rate.

    Note: Isokinetic sampling and proper operation of the cyclone are 
not achieved unless the correct [Delta]H and recycle flow rates are 
maintained.

    4.1.5.5 During the test run, monitor the probe and filter 
temperatures periodically, and make adjustments as necessary to maintain 
the desired temperatures. If the sample loading is high, the filter may 
begin to blind or the cyclone may clog. The filter or the cyclone may be 
replaced during the sample run. Before changing the filter or cyclone, 
conduct a leak-check (Section 4.1.4.2 of this method). The total 
particulate mass shall be the sum of all cyclone and the filter catch 
during the run. Monitor stack temperature and [Delta]p periodically, and 
make the necessary adjustments in sampling and recycle flow rates to 
maintain isokinetic sampling and the proper flow rate through the 
cyclone. At the end of the run, turn off the pump, close the coarse 
total valve, and record the final dry gas meter reading. Remove the 
probe from the stack, and conduct a post-test leak-check as outlined in 
Section 4.1.4.3 of this method.
    4.2 Sample Recovery. Allow the probe to cool. When the probe can be 
safely handled, wipe off all external PM adhering to the outside of the 
nozzle, cyclone, and nozzle attachment, and place a cap over the nozzle 
to prevent losing or gaining PM. Do not cap the nozzle tip tightly while 
the sampling train is cooling, as this action would create a vacuum in 
the filter holder. Disconnect the probe from the umbilical connector, 
and take the probe to the cleanup site. Sample recovery should be 
conducted in a dry indoor area or, if outside, in an area protected from 
wind and free of dust. Cap the ends of the impingers and carry them to 
the cleanup site. Inspect the components of the train prior to and 
during disassembly to note any abnormal conditions. Disconnect the pitot 
from the cyclone. Remove the cyclone from the probe. Recover the sample 
as follows:
    4.2.1 Container Number 1 (Filter). The recovery shall be the same as 
that for Container Number 1 in Method 5, Section 4.2.
    4.2.2 Container Number 2 (Cyclone or Large PM Catch). The cyclone 
must be disassembled and the nozzle removed in order to recover the 
large PM catch. Quantitatively recover the PM from the interior surfaces 
of the nozzle and the cyclone, excluding the ``turn around'' cup and the 
interior surfaces of the exit tube. The recovery shall be the same as 
that for Container Number 2 in Method 5, Section 4.2.
    4.2.3 Container Number 3 (PM10). Quantitatively recover 
the PM from all of the surfaces from cyclone exit to the front half of 
the in-stack filter holder, including the ``turn around'' cup and the 
interior of the exit tube. The recovery shall be the same as that for 
Container Number 2 in Method 5, Section 4.2.
    4.2.4 Container Number 4 (Silica Gel). Same as that for Container 
Number 3 in Method 5, Section 4.2.
    4.2.5 Impinger Water. Same as in Method 5, Section 4.2, under 
``Impinger Water.''
    4.3 Analysis. Same as in Method 5, Section 4.3, except handle EGR 
Container Numbers 1 and 2 like Container Number 1 in Method 5, EGR 
Container Numbers 3, 4, and 5 like Container Number 3 in Method 5, and 
EGR Container Number 6 like Container Number 3 in Method 5. Use Figure 
11 of this method to record the weights of PM collected.
    4.4 Quality Control Procedures. Same as in Method 5, Section 4.4.
    4.5 PM10 Emission Calculation and Acceptability of 
Results. Use the EGR reduction program or the procedures in section 6 of

[[Page 398]]

this method to calculate PM10 emissions and the criteria in 
section 6.7 of this method to determine the acceptability of the 
results.

                             5. Calibration

    Maintain an accurate laboratory log of all calibrations.
    5.1 Probe Nozzle. Same as in Method 5, Section 5.1.
    5.2 Pitot Tube. Same as in Method 5, Section 5.2.
    5.3 Meter and Flow Control Console.
    5.3.1 Dry Gas Meter. Same as in Method 5, Section 5.3.
    5.3.2 LFE Gauges. Calibrate the recycle, total, and inlet total LFE 
gauges with a manometer. Read and record flow rates at 10, 50, and 90 
percent of full scale on the total and recycle pressure gauges. Read and 
record flow rates at 10, 20, and 30 percent of full scale on the inlet 
total LFE pressure gauge. Record the total and recycle readings to the 
nearest 0.3 mm (0.01 in.). Record the inlet total LFE readings to the 
nearest 3 mm (0.1 in.). Make three separate measurements at each setting 
and calculate the average. The maximum difference between the average 
pressure reading and the average manometer reading shall not exceed 1 mm 
(0.05 in.). If the differences exceed the limit specified, adjust or 
replace the pressure gauge. After each field use, check the calibration 
of the pressure gauges.
    5.3.3 Total LFE. Same as the metering system in Method 5, Section 
5.3.
    5.3.4 Recycle LFE. Same as the metering system in Method 5, Section 
5.3, except completely close both the coarse and fine recycle valves.
    5.4 Probe Heater. Connect the probe to the meter and flow control 
console with the umbilical connector. Insert a thermocouple into the 
probe sample line approximately half the length of the probe sample 
line. Calibrate the probe heater at 66 [deg]C (150 [deg]F), 121 [deg]C 
(250 [deg]F), and 177 [deg]C (350 [deg]F). Turn on the power, and set 
the probe heater to the specified temperature. Allow the heater to 
equilibrate, and record the thermocouple temperature and the meter and 
flow control console temperature to the nearest 0.5 [deg]C (1 [deg]F). 
The two temperatures should agree within 5.5 [deg]C (10 [deg]F). If this 
agreement is not met, adjust or replace the probe heater controller.
    5.5 Temperature Gauges. Connect all thermocouples, and let the meter 
and flow control console equilibrate to ambient temperature. All 
thermocouples shall agree to within 1.1 [deg]C (2.0 [deg]F) with a 
standard mercury-in-glass thermometer. Replace defective thermocouples.
    5.6 Barometer. Calibrate against a standard mercury-in-glass 
barometer.
    5.7 Probe Cyclone and Nozzle Combinations. The probe cyclone and 
nozzle combinations need not be calibrated if the cyclone meets the 
design specifications in Figure 12 of this method and the nozzle meets 
the design specifications in appendix B of the Application Guide for the 
Source PM\3\10 Exhaust Gas Recycle Sampling System, EPA/600/
3-88-058. This document may be obtained from Roy Huntley at (919) 541-
1060. If the nozzles do not meet the design specifications, then test 
the cyclone and nozzle combination for conformity with the performance 
specifications (PS's) in Table 1 of this method. The purpose of the PS 
tests is to determine if the cyclone's sharpness of cut meets minimum 
performance criteria. If the cyclone does not meet design 
specifications, then, in addition to the cyclone and nozzle combination 
conforming to the PS's, calibrate the cyclone and determine the 
relationship between flow rate, gas viscosity, and gas density. Use the 
procedures in Section 5.7.5 of this method to conduct PS tests and the 
procedures in Section 5.8 of this method to calibrate the cyclone. 
Conduct the PS tests in a wind tunnel described in Section 5.7.1 of this 
method and using a particle generation system described in Section 5.7.2 
of this method. Use five particle sizes and three wind velocities as 
listed in Table 2 of this method. Perform a minimum of three replicate 
measurements of collection efficiency for each of the 15 conditions 
listed, for a minimum of 45 measurements.
    5.7.1 Wind Tunnel. Perform calibration and PS tests in a wind tunnel 
(or equivalent test apparatus) capable of establishing and maintaining 
the required gas stream velocities within 10 percent.
    5.7.2 Particle Generation System. The particle generation system 
shall be capable of producing solid monodispersed dye particles with the 
mass median aerodynamic diameters specified in Table 2 of this method. 
The particle size distribution verification should be performed on an 
integrated sample obtained during the sampling period of each test. An 
acceptable alternative is to verify the size distribution of samples 
obtained before and after each test, with both samples required to meet 
the diameter and monodispersity requirements for an acceptable test run.
    5.7.2.1 Establish the size of the solid dye particles delivered to 
the test section of the wind tunnel using the operating parameters of 
the particle generation system, and verify the size during the tests by 
microscopic examination of samples of the particles collected on a 
membrane filter. The particle size, as established by the operating 
parameters of the generation system, shall be within the tolerance 
specified in Table 2 of this method. The precision of the particle size 
verification technique shall be at least 0.5 
[micro]m, and the particle size determined by the verification technique 
shall not differ by more than 10 percent from that established by the 
operating parameters of the particle generation system.

[[Page 399]]

    5.7.2.2 Certify the monodispersity of the particles for each test 
either by microscopic inspection of collected particles on filters or by 
other suitable monitoring techniques such as an optical particle counter 
followed by a multichannel pulse height analyzer. If the proportion of 
multiplets and satellites in an aerosol exceeds 10 percent by mass, the 
particle generation system is unacceptable for purposes of this test. 
Multiplets are particles that are agglomerated, and satellites are 
particles that are smaller than the specified size range.
    5.7.3 Schematic Drawings. Schematic drawings of the wind tunnel and 
blower system and other information showing complete procedural details 
of the test atmosphere generation, verification, and delivery techniques 
shall be furnished with calibration data to the reviewing agency.
    5.7.4 Flow Rate Measurement. Determine the cyclone flow rates with a 
dry gas meter and a stopwatch, or a calibrated orifice system capable of 
measuring flow rates to within 2 percent.
    5.7.5 Performance Specification Procedure. Establish the test 
particle generator operation and verify the particle size 
microscopically. If mondispersity is to be verified by measurements at 
the beginning and the end of the run rather than by an integrated 
sample, these measurements may be made at this time.
    5.7.5.1 The cyclone cut size (D50) is defined as the 
aerodynamic diameter of a particle having a 50 percent probability of 
penetration. Determine the required cyclone flow rate at which 
D50 is 10 [micro]m. A suggested procedure is to vary the 
cyclone flow rate while keeping a constant particle size of 10 [micro]m. 
Measure the PM collected in the cyclone (mc), exit tube 
(mt), and filter (mf). Compute the cyclone 
efficiency (Ec) as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.016

    5.7.5.2 Perform three replicates and calculate the average cyclone 
efficiency as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.017

where E1, E2, and E3 are replicate 
measurements of Ec.
    5.7.5.3 Calculate the standard deviation ([sigma]) for the replicate 
measurements of Ec as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.018

if [sigma] exceeds 0.10, repeat the replicate runs.
    5.7.5.4 Using the cyclone flow rate that produces D50 for 
10 [micro]m, measure the overall efficiency of the cyclone and nozzle, 
Eo, at the particle sizes and nominal gas velocities in Table 
2 of this method using this following procedure.
    5.7.5.5 Set the air velocity in the wind tunnel to one of the 
nominal gas velocities from Table 2 of this method. Establish isokinetic 
sampling conditions and the correct flow rate through the sampler 
(cyclone and nozzle) using recycle capacity so that the D50 
is 10 [micro]m. Sample long enough to obtain 5 
percent precision on the total collected mass as determined by the 
precision and the sensitivity of the measuring technique. Determine 
separately the nozzle catch (mn), cyclone catch 
(mc), cyclone exit tube catch (mt), and collection 
filter catch (mf).
    5.7.5.6 Calculate the overall efficiency (Eo) as follows:
    [GRAPHIC] [TIFF OMITTED] TC08NO91.019
    
    5.7.5.7 Do three replicates for each combination of gas velocities 
and particle sizes in Table 2 of this method. Calculate Eo 
for each particle size following the procedures described in this 
section for determining efficiency. Calculate the standard deviation 
([sigma]) for the replicate measurements. If [sigma] exceeds 0.10, 
repeat the replicate runs.
    5.7.6 Criteria for Acceptance. For each of the three gas stream 
velocities, plot the average Eo as a function of particle 
size on Figure 13 of this method. Draw a smooth curve for each velocity 
through all particle sizes. The curve shall be within the banded region 
for all sizes, and the average Ec for a D50 for 10 
[micro]m shall be 50 0.5 percent.

[[Page 400]]

    5.8 Cyclone Calibration Procedure. The purpose of this section is to 
develop the relationship between flow rate, gas viscosity, gas density, 
and D50. This procedure only needs to be done on those 
cyclones that do not meet the design specifications in Figure 12 of this 
method.
    5.8.1 Calculate cyclone flow rate. Determine the flow rates and 
D50's for three different particle sizes between 5 [micro]m 
and 15 [micro]m, one of which shall be 10 [micro]m. All sizes must be 
within 0.5 [micro]m. For each size, use a different temperature within 
60 [deg]C (108 [deg]F) of the temperature at which the cyclone is to be 
used and conduct triplicate runs. A suggested procedure is to keep the 
particle size constant and vary the flow rate. Some of the values 
obtained in the PS tests in Section 5.7.5 may be used.
    5.8.1.1 On log-log graph paper, plot the Reynolds number (Re) on the 
abscissa, and the square root of the Stokes 50 number 
[(STK50)1/2] on the ordinate for each temperature. 
Use the following equations:
[GRAPHIC] [TIFF OMITTED] TC08NO91.020

[GRAPHIC] [TIFF OMITTED] TC08NO91.021

where:

Qcyc = Cyclone flow rate cm\3\/sec.
[rho] = Gas density, g/cm\3\.
dcyc = Diameter of cyclone inlet, cm.
[micro]cyc = Viscosity of gas through the cyclone, poise.
D50 = Cyclone cut size, cm.

    5.8.1.2 Use a linear regression analysis to determine the slope (m), 
and the y-intercept (b). Use the following formula to determine Q, the 
cyclone flow rate required for a cut size of 10 [micro]m.
[GRAPHIC] [TIFF OMITTED] TC08NO91.069

where:

Q = Cyclone flow rate for a cut size of 10 [micro]m, cm\3\/sec.
Ts = Stack gas temperature, [deg]K,
d = Diameter of nozzle, cm.
K1 = 4.077x10-3.

    5.8.2. Directions for Using Q. Refer to Section 5 of the EGR 
operators manual for directions in using this expression for Q in the 
setup calculations.

                             6. Calculations

    6.1 The EGR data reduction calculations are performed by the EGR 
reduction computer program, which is written in IBM BASIC computer 
language and is available through NTIS, Accession number PB90-500000, 
5285 Port Royal Road, Springfield, Virginia 22161. Examples of program 
inputs and outputs are shown in Figure 14 of this method.
    6.1.1 Calculations can also be done manually, as specified in Method 
5, Sections 6.3 through 6.7, and 6.9 through 6.12, with the addition of 
the following:
    6.1.2 Nomenclature.
Bc = Moisture fraction of mixed cyclone gas, by volume, 
dimensionless.
C1 = Viscosity constant, 51.12 micropoise for [deg]K (51.05 
micropoise for [deg] R).
C2 = Viscosity constant, 0.372 micropoise/[deg]K (0.207 
micropoise/[deg] R).
C3 = Viscosity constant, 1.05x10-4 micropoise/
[deg]K\2\ (3.24x10-5 micropoise/[deg] R\2\).
C4 = Viscosity constant, 53.147 micropoise/fraction 
O2.
C5 = Viscosity constant, 74.143 micropoise/fraction 
H2 O.
D50 = Diameter of particles having a 50 percent probability 
of penetration, [micro]m.
f02 = Stack gas fraction O2 by volume, dry basis.
K1 = 0.3858 [deg]K/mm Hg (17.64 [deg] R/in. Hg).
Mc = Wet molecular weight of mixed gas through the 
PM10 cyclone, g/g-mole (lb/lb-mole).
Md = Dry molecular weight of stack gas, g/g-mole (lb/lb-
mole).
Pbar = Barometer pressure at sampling site, mm Hg (in. Hg).
Pin1 = Gauge pressure at inlet to total LFE, mm H2 
O (in. H2 O).
P3 = Absolute stack pressure, mm Hg (in. Hg).
Q2 = Total cyclone flow rate at wet cyclone conditions, m\3\/
min (ft\3\/min).
Qs(std) = Total cyclone flow rate at standard conditons, 
dscm/min (dscf/min).
Tm = Average temperature of dry gas meter, [deg]K ([deg]R).
Ts = Average stack gas temperature, [deg]K ([deg]R).
Vw(std) = Volume of water vapor in gas sample (standard 
conditions), scm (scf).
XT = Total LFE linear calibration constant, m\3\/[(min)(mm 
H2 O]) { ft\3\/[(min)(in. H2 O)]{time} .

[[Page 401]]

YT = Total LFE linear calibration constant, dscm/min (dscf/
min).
[Delta] PT = Pressure differential across total LFE, mm 
H2 O, (in. H2 O).
[thetas] = Total sampling time, min.
[micro]cyc = Viscosity of mixed cyclone gas, micropoise.
[micro]LFE = Viscosity of gas laminar flow elements, 
micropoise.
[micro]std = Viscosity of standard air, 180.1 micropoise.
    6.2 PM10 Particulate Weight. Determine the weight of 
PM10 by summing the weights obtained from Container Numbers 1 
and 3, less the acetone blank.
    6.3 Total Particulate Weight. Determine the particulate catch for PM 
greater than PM10 from the weight obtained from Container 
Number 2 less the acetone blank, and add it to the PM10 
particulate weight.
    6.4 PM10 Fraction. Determine the PM10 fraction 
of the total particulate weight by dividing the PM10 
particulate weight by the total particulate weight.
    6.5 Total Cyclone Flow Rate. The average flow rate at standard 
conditions is determined from the average pressure drop across the total 
LFE and is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.022

    The flow rate, at actual cyclone conditions, is calculated as 
follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.023

    The flow rate, at actual cyclone conditions, is calculated as 
follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.024

    6.6 Aerodynamic Cut Size. Use the following procedure to determine 
the aerodynamic cut size (D50).
    6.6.1 Determine the water fraction of the mixed gas through the 
cyclone by using the equation below.
[GRAPHIC] [TIFF OMITTED] TC08NO91.025

    6.6.2 Calculate the cyclone gas viscosity as follows:
[micro]cyc = C1 + C2 Ts + 
C3 Ts2 + C4 f02 - 
C5 Bc
    6.6.3 Calculate the molecular weight on a wet basis of the cyclone 
gas as follows:
Mc = Md(1 - Bc) + 18.0(Bc)
    6.6.4 If the cyclone meets the design specification in Figure 12 of 
this method, calculate the actual D50 of the cyclone for the 
run as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.026

where [beta]1 = 0.1562.

    6.6.5 If the cyclone does not meet the design specifications in 
Figure 12 of this method, then use the following equation to calculate 
D50.
[GRAPHIC] [TIFF OMITTED] TC08NO91.027


[[Page 402]]


where:

m = Slope of the calibration curve obtained in Section 5.8.2.
b = y-intercept of the calibration curve obtained in Section 5.8.2.

    6.7 Acceptable Results. Acceptability of anisokinetic variation is 
the same as Method 5, Section 6.12.
    6.7.1 If 9.0 [micro]m <= D50 <=11 [micro]m and 90 <= I <= 
110, the results are acceptable. If D50 is greater than 11 
[micro]m, the Administrator may accept the results. If D50 is 
less than 9.0 [micro]m, reject the results and repeat the test.

                             7. Bibliography

    1. Same as Bibliography in Method 5.
    2. McCain, J.D., J.W. Ragland, and A.D. Williamson. Recommended 
Methodology for the Determination of Particles Size Distributions in 
Ducted Sources, Final Report. Prepared for the California Air Resources 
Board by Southern Research Institute. May 1986.
    3. Farthing, W.E., S.S. Dawes, A.D. Williamson, J.D. McCain, R.S. 
Martin, and J.W. Ragland. Development of Sampling Methods for Source PM-
10 Emissions. Southern Research Institute for the Environmental 
Protection Agency. April 1989.
    4. Application Guide for the Source PM10 Exhaust Gas 
Recycle Sampling System, EPA/600/3-88-058.

[[Page 403]]




[[Page 404]]





[[Page 405]]





[[Page 406]]





[[Page 407]]




                EXAMPLE EMISSION GAS RECYCLE SETUP SHEET

                          VERSION 3.1 MAY 1986

TEST I.D.: SAMPLE SETUP
RUN DATE: 11/24/86
LOCATION: SOURCE SIM
OPERATOR(S): RH JB
NOZZLE DIAMETER (IN): .25
STACK CONDITIONS:
    AVERAGE TEMPERATURE (F): 200.0
    AVERAGE VELOCITY (FT/SEC): 15.0
    AMBIENT PRESSURE (IN HG): 29.92
    STACK PRESSURE (IN H20): .10
GAS COMPOSITION:
 H20=10.0%...........................................MD=28.84
 O2=20.9%............................................MW=27.75
 CO2=.0%.........................................(LB/LB MOLE)

                          TARGET PRESSURE DROPS

                             TEMPERATURE (F)

DP(PTO)............             150        161        172        183        194        206        217        228
0.026..............          SAMPLE        .49        .49        .48        .47        .46        .45        .45

[[Page 408]]

 
                              TOTAL       1.90       1.90       1.91       1.92       1.92       1.92       1.93
                            RECYCLE       2.89       2.92       2.94       2.97       3.00       3.02       3.05
                              % RCL        61%        61%        62%        62%        63%        63%        63%
 
.031...............             .58        .56        .55        .55        .55        .54        .53        .52
                               1.88       1.89       1.89       1.90       1.91       1.91       1.91       1.92
                               2.71       2.74       2.77       2.80       2.82       2.85       2.88       2.90
                                57%        57%        58%        58%        59%        59%        60%        60%
 
.035...............             .67        .65        .64        .63        .62        .61       .670        .59
                               1.88       1.88       1.89       1.89       1.90       1.90       1.91       1.91
                               2.57       2.60       2.63       2.66       2.69       2.72       2.74       2.74
                                54%        55%        55%        56%        56%        57%        57%        57%
 
.039...............             .75        .74        .72        .71        .70        .69        .67        .66
                               1.87       1.88       1.88       1.89       1.89       1.90       1.90       1.91
                               2.44       2.47       2.50       2.53       2.56       2.59       2.62       2.65
                                51%        52%        52%        53%        53%        54%        54%        55%
 
                                       Figure 6. Example EGR setup sheet.
 


Barometric pressure, Pbar, in. Hg...   =   ------
Stack static pressure, Pg, in. H2 O.   =   ------
Average stack temperature, ts,         =   ------
 [deg]F.
Meter temperature, tm, [deg]F.......   =   ------
Gas analysis:
  %CO2..............................   =   ------
  %O2...............................   =   ------
  %N2+%CO...........................   =   ------
  Fraction moisture content, Bws....   =   ------
Calibration data:
  Nozzle diameter, Dn in............   =   ------
  Pitot coefficient, Cp.............   =   ------
  [Delta]H2, in. H2O................   =   ------
Molecular weight of stack gas, dry
 basis:
  Md=0.44
    (%CO2)+0.32                        =    lb/lb
                                             mole
    (%O2)+0.28
    (%N2+%CO)
Molecular weight of stack gas, wet
 basis:
  Mw=Md (1-Bws)+18Bws...............   =   ------  lb/lb mole
Absolute stack pressure:
  Ps=Pbar+(Pg/13.6)                    =   ------  in. Hg
 

                                                   [GRAPHIC] [TIFF OMITTED] TC08NO91.071
                                                   
Desired meter orifice pressure ([Delta]H) for velocity head of stack gas 
([Delta]p):
[GRAPHIC] [TIFF OMITTED] TC08NO91.072

    Figure 7. Example worksheet 1, meter orifice pressure head 
calculation.

Barometric pressure, Pbar, in. Hg......   =   ------
Absolute stack pressure, Ps, in. Hg....   =   ------
Average stack temperature, Ts, [deg]R..   =   ------
Meter temperature, Tm, [deg]R..........   =   ------
Molecular weight of stack gas, wet        =   ------
 basis, Md lb/lb mole.
Pressure upstream of LFE, in. Hg.......   =      0.6
Gas analysis:
  %O2..................................   =   ------
  Fraction moisture content, Bws.......   =   ------
Calibration data:
  Nozzle diameter, Dn, in..............   =   ------
  Pitot coefficient, Cp................   =   ------
  Total LFE calibration constant, Xt...   =   ------
  Total LFE calibration constant, Tt...   =   ------
Absolute pressure upstream of LFE:
  PLFE=Pbar+0.6........................   =   ------  in. Hg

[[Page 409]]

 
Viscosity of gas in total LFE:
  [micro]LFE=152.418+0.2552               =   ------
   Tm+3.2355x10-5 Tm2+0.53147 (%O2).
Viscosity of dry stack gas:
  [micro]d=152.418+0.2552 Ts+3.2355x10-   =   ------
   5 Ts2+0.53147 (%O2).
 


Constants:
[GRAPHIC] [TIFF OMITTED] TC08NO91.028

[GRAPHIC] [TIFF OMITTED] TC08NO91.029

[GRAPHIC] [TIFF OMITTED] TC08NO91.030

[GRAPHIC] [TIFF OMITTED] TC08NO91.031

[GRAPHIC] [TIFF OMITTED] TC08NO91.032

Total LFE pressure head:
[GRAPHIC] [TIFF OMITTED] TC08NO91.033

    Figure 8. Example worksheet 1, meter orifice pressure head 
calculation.

Barometric pressure, Pbar, in. Hg......   =   ------
Absolute stack pressure, Ps, in. Hg....   =   ------
Average stack temperature, Ts, [deg]R..   =   ------
Meter temperature, Tm, [deg]R..........   =   ------
Molecular weight of stack gas, dry        =   ------
 basis, Md lb/lb mole.
Viscosity of LFE gas[micro]LFE,poise...   =   ------
Absolute pressure upstream of LFE,        =   ------
 PPLEin. Hg.
Calibration data:......................
  Nozzle diameter, Dn, in..............   =   ------
  Pitot coefficient, Cp................   =   ------
Recycle LFE calibration constant, Xt      =   ------
Recycle LFE calibration constant, Yt      =   ------
 

                                             [GRAPHIC] [TIFF OMITTED] TC08NO91.034
                                             
                                             [GRAPHIC] [TIFF OMITTED] TC08NO91.035
                                             
                                             [GRAPHIC] [TIFF OMITTED] TC08NO91.036
                                             

[[Page 410]]

[GRAPHIC] [TIFF OMITTED] TC08NO91.037

[GRAPHIC] [TIFF OMITTED] TC08NO91.038

    Pressure head for recycle LFE:
    [GRAPHIC] [TIFF OMITTED] TC08NO91.039
    
    Figure 9. Example worksheet 3, recycle LFE pressure head.
    
    
Plant___________________________________________________________________
Date____________________________________________________________________
Run no._________________________________________________________________
Filter no.______________________________________________________________
Amount liquid lost during transport_____________________________________
Acetone blank volume, ml________________________________________________
Acetone wash volume, ml (2)------(3)____________________________________
Acetone blank conc., mg/mg (Equation 5-4, Method 5)_____________________

[[Page 411]]

Acetone wash blank, mg (Equation 5-5, Method 5)_________________________

------------------------------------------------------------------------
                                                 Weight of particulate
                                                       matter, mg
               Container number               --------------------------
                                                Final     Tare    Weight
                                                weight   weight    gain
------------------------------------------------------------------------
1............................................  .......  .......  .......
3............................................  .......  .......  .......
  Total......................................  .......  .......  .......
                                                                --------
  Less acetone blank.........................  .......  .......  .......
                                                                --------
  Weight of PM10.............................  .......  .......  .......
2............................................  .......  .......  .......
                                                                --------
  Less acetone blank.........................  .......  .......  .......
                                                                --------
  Total particulate weight...................  .......  .......  .......
                                                                --------
------------------------------------------------------------------------

    Figure 11. EGR method analysis sheet.

[[Page 412]]




 Table 1--Performance Specifications for Source PM10 Cyclones and Nozzle
                              Combinations
------------------------------------------------------------------------
            Parameter                    Units           Specification
------------------------------------------------------------------------
1. Collection efficiency........  Percent...........  Such that
                                                       collection
                                                       efficiency falls
                                                       within envelope
                                                       specified by
                                                       Section 5.7.6 and
                                                       Figure 13.
2. Cyclone cut size (D50).......  [micro]m..........  10 1 [micro]m
                                                       aerodynamic
                                                       diameter.
------------------------------------------------------------------------


[[Page 413]]


                        Table 2--Particle Sizes and Nominal Gas Velocities for Efficiency
----------------------------------------------------------------------------------------------------------------
                                                                   Target gas velocities (m/sec)
                                                  --------------------------------------------------------------
            Particle size ([micro]m)a               7 1.0           thn-eq>1.5           thn-eq>2.5
----------------------------------------------------------------------------------------------------------------
5 0.5......................  ...................  ...................  ...................
7 0.5......................  ...................  ...................  ...................
10 0.5.....................  ...................  ...................  ...................
14 1.0.....................  ...................  ...................  ...................
20 1.0.....................  ...................  ...................  ...................
----------------------------------------------------------------------------------------------------------------
(a) Mass median aerodynamic diameter.



       Emission Gas Recycle, Data Reduction, Version 3.4 MAY 1986

    Test ID. Code: Chapel Hill 2.
    Test Location: Baghouse Outlet.
    Test Site: Chapel Hill.
    Test Date: 10/20/86.
    Operators(s): JB RH MH.

                            Entered Run Data

Temperatures:
    T(STK)..............................  251.0 F
    T(RCL)..............................  259.0 F
    T(LFE)..............................  81.0 F
    T(DGM)..............................  76.0 F
System Pressures:
    DH(ORI).............................  1.18 INWG
    DP(TOT).............................  1.91 INWG
    P(INL)..............................  12.15 INWG
    DP(RCL).............................  2.21 INWG
    DP(PTO).............................  0.06 INWG
Miscellanea:
    P(BAR)..............................  29.99 INWG
    DP(STK).............................  0.10 INWG
    V(DGM)..............................  13.744 FT3
    TIME................................  60.00 MIN
    % CO2...............................  8.00
    % O2................................  20.00
    NOZ (IN)............................  0.2500

[[Page 414]]

 
Water Content:
    Estimate............................  0.0%
      or
    Condenser...........................  7.0 ML
    Column..............................  0.0 GM
Raw Masses:
    Cyclone 1...........................  21.7 MG
    Filter..............................  11.7 MG
    Impinger Residue....................  0.0 MG
Blank Values:
    CYC Rinse...........................  0.0 MG
    Filter Holder Rinse.................  0.0 MG
    Filter Blank........................  0.0 MG
    Impinger Rinse......................  0.0 MG
 


Calibration Values:
    CP(PITOT)................................................     0.840
    DH@(ORI).................................................    10.980
    M(TOT LFE)...............................................     0.2298
    B(TOT LFE)...............................................     -.0058
    M(RCL LFE)...............................................     0.0948
    B(RCL LFE)...............................................     -.0007
    DGM GAMMA................................................     0.9940
 

                              Reduced Data

Stack Velocity (FT/SEC)........................................  15.95
Stack Gas Moisture (%).........................................   2.4
Sample Flow Rate (ACFM)........................................   0.3104
Total Flow Rate (ACFM).........................................   0.5819
Recycle Flow Rate (ACFM).......................................   0.2760
Percent Recycle................................................  46.7
Isokinetic Ratio (%)...........................................  95.1
 


----------------------------------------------------------------------------------------------------------------
                                          (Particulate)
                                       ------------------    (MG/DNCM)      (GR/ACF)     (GR/DCF)   (LB/DSCF) (X
                                          (UM)    (% <)                                                 1E6)
----------------------------------------------------------------------------------------------------------------
Cyclone 1.............................    10.15     35.8            56.6      0.01794      0.02470       3.53701
Backup Filter.........................  .......  .......            30.5      0.00968      0.01332       1.907
Particulate Total.....................  .......  .......            87.2      0.02762      0.03802       5.444
----------------------------------------------------------------------------------------------------------------
Note: Figure 14. Example inputs and outputs of the EGR reduction program.

   Method 201A--Determination of PM10 Emissions (Constant 
                        Sampling Rate Procedure)

                     1. Applicability and Principle

    1.1 Applicability. This method applies to the in-stack measurement 
of particulate matter (PM) emissions equal to or less than an 
aerodynamic diameter of nominally 10 (PM10) from stationary 
sources. The EPA recognizes that condensible emissions not collected by 
an in-stack method are also PM10, and that emissions that 
contribute to ambient, PM10 levels are the sum of condensible 
emissions and emissions measured by an in-stack PM10 method, 
such as this method or Method 201. Therefore, for establishing source 
contributions to ambient levels of PM10, such as for emission 
inventory purposes, EPA suggests that source PM10 measurement 
include both in-stack PM10 and condensible emissions. 
Condensible emissions may be measured by an impinger analysis in 
combination with this method.
    1.2 Principle. A gas sample is extracted at a constant flow rate 
through an in-stack sizing device, which separates PM greater than 
PM10. Variations from isokinetic sampling conditions are 
maintained within well-defined limits. The particulate mass is 
determined gravimetrically after removal of uncombined water.

                              2. Apparatus

    Note: Methods cited in this method are part of 40 CFR part 60, 
appendix A.
    2.1 Sampling Train. A schematic of the Method 201A sampling train is 
shown in Figure 1 of this method. With the exception of the 
PM10 sizing device and in-stack filter, this train is the 
same as an EPA Method 17 train.
    2.1.1 Nozzle. Stainless steel (316 or equivalent) with a sharp 
tapered leading edge. Eleven nozzles that meet the design specification 
in Figure 2 of this method are recommended. A larger number of nozzles 
with small nozzle increments increase the likelihood that a single 
nozzle can be used for the entire traverse. If the nozzles do not meet 
the design specifications in Figure 2 of this method, then the nozzles 
must meet the criteria in Section 5.2 of this method.
    2.1.2 PM10 Sizer. Stainless steel (316 or equivalent), 
capable of determining the PM10 fraction. The sizing device 
shall be either a cyclone that meets the specifications in Section 5.2 
of this method or a cascade impactor that has been calibrated using the 
procedure in Section 5.4 of this method.
    2.1.3 Filter Holder. 63-mm, stainless steel. An Andersen filter, 
part number SE274, has been found to be acceptable for the in-stack 
filter. Note: Mention of trade names or specific products does not 
constitute endorsement by the Environmental Protection Agency.
    2.1.4 Pitot Tube. Same as in Method 5, Section 2.1.3. The pitot 
lines shall be made of heat resistant tubing and attached to the probe 
with stainless steel fittings.
    2.1.5 Probe Liner. Optional, same as in Method 5, Section 2.1.2.
    2.1.6 Differential Pressure Gauge, Condenser, Metering System, 
Barometer, and Gas Density Determination Equipment. Same as in Method 5, 
Sections 2.1.4, and 2.1.7 through 2.1.10, respectively.
    2.2 Sample Recovery.

[[Page 415]]

    2.2.1 Nozzle, Sizing Device, Probe, and Filter Holder Brushes. Nylon 
bristle brushes with stainless steel wire shafts and handles, properly 
sized and shaped for cleaning the nozzle, sizing device, probe or probe 
liner, and filter holders.
    2.2.2 Wash Bottles, Glass Sample Storage Containers, Petri Dishes, 
Graduated Cylinder and Balance, Plastic Storage Containers, Funnel and 
Rubber Policeman, and Funnel. Same as in Method 5, Sections 2.2.2 
through 2.2.8, respectively.
    2.3 Analysis. Same as in Method 5, Section 2.3.

                               3. Reagents

    The reagents for sampling, sample recovery, and analysis are the 
same as that specified in Method 5, Sections 3.1, 3.2, and 3.3, 
respectively.

                              4. Procedure

    4.1 Sampling. The complexity of this method is such that, in order 
to obtain reliable results, testers should be trained and experienced 
with the test procedures.
    4.1.1 Pretest Preparation. Same as in Method 5, Section 4.1.1.
    4.1.2 Preliminary Determinations. Same as in Method 5, Section 
4.1.2, except use the directions on nozzle size selection and sampling 
time in this method. Use of any nozzle greater than 0.16 in. in diameter 
requires a sampling port diameter of 6 inches. Also, the required 
maximum number of traverse points at any location shall be 12.
    4.1.2.1 The sizing device must be in-stack or maintained at stack 
temperature during sampling. The blockage effect of the CSR sampling 
assembly will be minimal if the cross-sectional area of the sampling 
assembly is 3 percent or less of the cross-sectional area of the duct. 
If the cross-sectional area of the assembly is greater than 3 percent of 
the cross-sectional area of the duct, then either determine the pitot 
coefficient at sampling conditions or use a standard pitot with a known 
coefficient in a configuration with the CSR sampling assembly such that 
flow disturbances are minimized.
    4.1.2.2 The setup calculations can be performed by using the 
following procedures.
    4.1.2.2.1 In order to maintain a cut size of 10 [micro]m in the 
sizing device, the flow rate through the sizing device must be 
maintained at a constant, discrete value during the run. If the sizing 
device is a cyclone that meets the design specifications in Figure 3 of 
this method, use the equations in Figure 4 of this method to calculate 
three orifice heads ([Delta]H): one at the average stack temperature, 
and the other two at temperatures 28 [deg]C 
(50 [deg]F) of the average stack temperature. Use 
[Delta]H calculated at the average stack temperature as the pressure 
head for the sample flow rate as long as the stack temperature during 
the run is within 28 [deg]C (50 [deg]F) of the average stack 
temperature. If the stack temperature varies by more than 28 [deg]C (50 
[deg]F), then use the appropriate [Delta]H.
    4.1.2.2.2 If the sizing device is a cyclone that does not meet the 
design specifications in Figure 3 of this method, use the equations in 
Figure 4 of this method, except use the procedures in Section 5.3 of 
this method to determine Qs, the correct cyclone flow rate 
for a 10 [micro]m size.
    4.1.2.2.3 To select a nozzle, use the equations in Figure 5 of this 
method to calculate [Delta]pmin and [Delta]pmax 
for each nozzle at all three temperatures. If the sizing device is a 
cyclone that does not meet the design specifications in Figure 3 of this 
method, the example worksheets can be used.
    4.1.2.2.4 Correct the Method 2 pitot readings to Method 201A pitot 
readings by multiplying the Method 2 pitot readings by the square of a 
ratio of the Method 201A pitot coefficient to the Method 2 pitot 
coefficient. Select the nozzle for which [Delta]pmin and 
[Delta]pmax bracket all of the corrected Method 2 pitot 
readings. If more than one nozzle meets this requirement, select the 
nozzle giving the greatest symmetry. Note that if the expected pitot 
reading for one or more points is near a limit for a chosen nozzle, it 
may be outside the limits at the time of the run.
    4.1.2.2.5 Vary the dwell time, or sampling time, at each traverse 
point proportionately with the point velocity. Use the equations in 
Figure 6 of this method to calculate the dwell time at the first point 
and at each subsequent point. It is recommended that the number of 
minutes sampled at each point be rounded to the nearest 15 seconds.
    4.1.3 Preparation of Collection Train. Same as in Method 5, Section 
4.1.3, except omit directions about a glass cyclone.
    4.1.4 Leak-Check Procedure. The sizing device is removed before the 
post-test leak-check to prevent any disturbance of the collected sample 
prior to analysis.
    4.1.4.1 Pretest Leak-Check. A pretest leak-check of the entire 
sampling train, including the sizing device, is required. Use the leak-
check procedure in Method 5, Section 4.1.4.1 to conduct a pretest leak-
check.
    4.1.4.2 Leak-Checks During Sample Run. Same as in Method 5, Section 
4.1.4.1.
    4.1.4.3 Post-Test Leak-Check. A leak-check is required at the 
conclusion of each sampling run. Remove the cyclone before the leak-
check to prevent the vacuum created by the cooling of the probe from 
disturbing the collected sample and use the procedure in Method 5, 
Section 4.1.4.3 to conduct a post-test leak-check.
    4.1.5 Method 201A Train Operation. Same as in Method 5, Section 
4.1.5, except use the procedures in this section for isokinetic sampling 
and flow rate adjustment. Maintain the flow rate calculated in Section 
4.1.2.2.1 of this method throughout the run provided the

[[Page 416]]

stack temperature is within 28 [deg]C (50 [deg]F) of the temperature 
used to calculate [Delta]H. If stack temperatures vary by more than 28 
[deg]C (50 [deg]F), use the appropriate [Delta]H value calculated in 
Section 4.1.2.2.1 of this method. Calculate the dwell time at each 
traverse point as in Figure 6 of this method.
    4.2 Sample Recovery. If a cascade impactor is used, use the 
manufacturer's recommended procedures for sample recovery. If a cyclone 
is used, use the same sample recovery as that in Method 5, Section 4.2, 
except an increased number of sample recovery containers is required.
    4.2.1 Container Number 1 (In-Stack Filter). The recovery shall be 
the same as that for Container Number 1 in Method 5, Section 4.2.
    4.2.3 Container Number 2 (Cyclone or Large PM Catch). This step is 
optional. The anisokinetic error for the cyclone PM is theoretically 
larger than the error for the PM10 catch. Therefore, adding 
all the fractions to get a total PM catch is not as accurate as Method 5 
or Method 201. Disassemble the cyclone and remove the nozzle to recover 
the large PM catch. Quantitatively recover the PM from the interior 
surfaces of the nozzle and cyclone, excluding the ``turn around'' cup 
and the interior surfaces of the exit tube. The recovery shall be the 
same as that for Container Number 2 in Method 5, Section 4.2.
    4.2.4 Container Number 3 (PM10). Quantitatively recover 
the PM from all of the surfaces from the cyclone exit to the front half 
of the in-stack filter holder, including the ``turn around'' cup inside 
the cyclone and the interior surfaces of the exit tube. The recovery 
shall be the same as that for Container Number 2 in Method 5, Section 
4.2.
    4.2.6 Container Number 4 (Silica Gel). The recovery shall be the 
same as that for Container Number 3 in Method 5, Section 4.2.
    4.2.7 Impinger Water. Same as in Method 5, Section 4.2, under 
``Impinger Water.''
    4.3 Analysis. Same as in Method 5, Section 4.3, except handle Method 
201A Container Number 1 like Container Number 1, Method 201A Container 
Numbers 2 and 3 like Container Number 2, and Method 201A Container 
Number 4 like Container Number 3. Use Figure 7 of this method to record 
the weights of PM collected. Use Figure 5-3 in Method 5, Section 4.3, to 
record the volume of water collected.
    4.4 Quality Control Procedures. Same as in Method 5, Section 4.4.
    4.5 PM10 Emission Calculation and Acceptability of 
Results. Use the procedures in section 6 to calculate PM10 
emissions and the criteria in section 6.3.5 to determine the 
acceptability of the results.

                             5. Calibration

    Maintain an accurate laboratory log of all calibrations.
    5.1 Probe Nozzle, Pitot Tube, Metering System, Probe Heater 
Calibration, Temperature Gauges, Leak-check of Metering System, and 
Barometer. Same as in Method 5, Section 5.1 through 5.7, respectively.
    5.2 Probe Cyclone and Nozzle Combinations. The probe cyclone and 
nozzle combinations need not be calibrated if both meet design 
specifications in Figures 2 and 3 of this method. If the nozzles do not 
meet design specifications, then test the cyclone and nozzle 
combinations for conformity with performance specifications (PS's) in 
Table 1 of this method. If the cyclone does not meet design 
specifications, then the cylcone and nozzle combination shall conform to 
the PS's and calibrate the cyclone to determine the relationship between 
flow rate, gas viscosity, and gas density. Use the procedures in Section 
5.2 of this method to conduct PS tests and the procedures in Section 5.3 
of this method to calibrate the cyclone. The purpose of the PS tests are 
to conform that the cyclone and nozzle combination has the desired 
sharpness of cut. Conduct the PS tests in a wind tunnel described in 
Section 5.2.1 of this method and particle generation system described in 
Section 5.2.2 of this method. Use five particle sizes and three wind 
velocities as listed in Table 2 of this method. A minimum of three 
replicate measurements of collection efficiency shall be performed for 
each of the 15 conditions listed, for a minimum of 45 measurements.
    5.2.1 Wind Tunnel. Perform the calibration and PS tests in a wind 
tunnel (or equivalent test apparatus) capable of establishing and 
maintaining the required gas stream velocities within 10 percent.
    5.2.2 Particle Generation System. The particle generation system 
shall be capable of producing solid monodispersed dye particles with the 
mass median aerodynamic diameters specified in Table 2 of this method. 
Perform the particle size distribution verification on an integrated 
sample obtained during the sampling period of each test. An acceptable 
alternative is to verify the size distribution of samples obtained 
before and after each test, with both samples required to meet the 
diameter and monodispersity requirements for an acceptable test run.
    5.2.2.1 Establish the size of the solid dye particles delivered to 
the test section of the wind tunnel by using the operating parameters of 
the particle generation system, and verify them during the tests by 
microscopic examination of samples of the particles collected on a 
membrane filter. The particle size, as established by the operating 
parameters of the generation system, shall be within the tolerance 
specified in Table 2 of this method. The precision of the particle size 
verification technique shall be at least 0.5, 
[micro]m, and particle size determined by the verification technique 
shall not differ by

[[Page 417]]

more than 10 percent from that established by the operating parameters 
of the particle generation system.
    5.2.2.2 Certify the monodispersity of the particles for each test 
either by microscopic inspection of collected particles on filters or by 
other suitable monitoring techniques such as an optical particle counter 
followed by a multichannel pulse height analyzer. If the proportion of 
multiplets and satellites in an aerosol exceeds 10 percent by mass, the 
particle generation system is unacceptable for the purpose of this test. 
Multiplets are particles that are agglomerated, and satellites are 
particles that are smaller than the specified size range.
    5.2.3 Schematic Drawings. Schematic drawings of the wind tunnel and 
blower system and other information showing complete procedural details 
of the test atmosphere generation, verification, and delivery techniques 
shall be furnished with calibration data to the reviewing agency.
    5.2.4 Flow Measurements. Measure the cyclone air flow rates with a 
dry gas meter and a stopwatch, or a calibrated orifice system capable of 
measuring flow rates to within 2 percent.
    5.2.5 Performance Specification Procedure. Establish test particle 
generator operation and verify particle size microscopically. If 
monodisperity is to be verified by measurements at the beginning and the 
end of the run rather than by an integrated sample, these measurements 
may be made at this time.
    5.2.5.1 The cyclone cut size, or D50, of a cyclone is 
defined here as the particle size having a 50 percent probability of 
penetration. Determine the cyclone flow rate at which D50 is 
10 [micro]m. A suggested procedure is to vary the cyclone flow rate 
while keeping a constant particle size of 10 [micro]m. Measure the PM 
collected in the cyclone (mc), the exit tube (mt), 
and the filter (mf). Calculate cyclone efficiency 
(Ec) for each flow rate as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.040

    5.2.5.2. Do three replicates and calculate the average cyclone 
efficiency [Ec(avg)] as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.041

Where E1, E2, and E3 are replicate 
measurements of Ec.
    5.2.5.3 Calculate the standard deviation ([sigma]) for the replicate 
measurements of Ec as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.042

If [sigma] exceeds 0.10, repeat the replicated runs.
    5.2.5.4 Measure the overall efficiency of the cyclone and nozzle, 
Eo, at the particle sizes and nominal gas velocities in Table 
2 of this method using the following procedure.
    5.2.5.5 Set the air velocity and particle size from one of the 
conditions in Table 2 of this method. Establish isokinetic sampling 
conditions and the correct flow rate in the cyclone (obtained by 
procedures in this section) such that the D50 is 10 [micro]m. 
Sample long enough to obtain 5 percent precision 
on total collected mass as determined by the precision and the 
sensitivity of measuring technique. Determine separately the nozzle 
catch (mn), cyclone catch (mc), cyclone exit tube 
(Mt), and collection filter catch (mf) for each 
particle size and nominal gas velocity in Table 2 of this method. 
Calculate overall efficiency (Eo) as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.043

    5.2.5.6 Do three replicates for each combination of gas velocity and 
particle size in Table 2 of this method. Use the equation below to 
calculate the average overall efficiency [Eo(avg)] for each 
combination following the procedures described in this section for 
determining efficiency.
[GRAPHIC] [TIFF OMITTED] TC08NO91.044

Where E1, E2, and E3 are replicate 
measurements of Eo.

    5.2.5.7 Use the formula in Section 5.2.5.3 to calculate [sigma] for 
the replicate measurements. If [sigma] exceeds 0.10 or if the particle 
sizes and nominal gas velocities are not within the

[[Page 418]]

limits specified in Table 2 of this method, repeat the replicate runs.
    5.2.6 Criteria for Acceptance. For each of the three gas stream 
velocities, plot the Eo(avg) as a function of particle size 
on Figure 8 of this method. Draw smooth curves through all particle 
sizes. Eo(avg) shall be within the banded region for all 
sizes, and the Ec(avg) shall be 50 0.5 
percent at 10 [micro]m.
    5.3 Cyclone Calibration Procedure. The purpose of this procedure is 
to develop the relationship between flow rate, gas viscosity, gas 
density, and D50.
    5.3.1 Calculate Cyclone Flow Rate. Determine flow rates and 
D50's for three different particle sizes between 5 [micro]m 
and 15 [micro]m, one of which shall be 10 [micro]m. All sizes must be 
determined within 0.5 [micro]m. For each size, use a different 
temperature within 60 [deg]C (108 [deg]F) of the temperature at which 
the cyclone is to be used and conduct triplicate runs. A suggested 
procedure is to keep the particle size constant and vary the flow rate.
    5.3.1.1 On log-log graph paper, plot the Reynolds number (Re) on the 
abscissa, and the square root of the Stokes 50 number 
[(Stk50)\12\] on the ordinate for each temperature. Use the 
following equations to compute both values:
[GRAPHIC] [TIFF OMITTED] TC08NO91.045

[GRAPHIC] [TIFF OMITTED] TC08NO91.046

where:

Qcyc = Cyclone flow rate, cm\3\/sec.
[rho] = Gas density, g/cm\3\.
dcyc = Diameter of cyclone inlet, cm.
[micro]s = Viscosity of stack gas, micropoise.
D50 = Aerodynamic diameter of a particle having a 50 percent 
probability of penetration, cm.

    5.3.1.2 Use a linear regression analysis to determine the slope (m) 
and the Y-intercept (b). Use the following formula to determine Q, the 
cyclone flow rate required for a cut size of 10 [micro]m.
[GRAPHIC] [TIFF OMITTED] TC08NO91.047

where:

m = Slope of the calibration line.
b = y-intercept of the calibration line.
Qs = Cyclone flow rate for a cut size of 10 [micro]m, cm\3\/
sec.
d = Diameter of nozzle, cm.
Ts = Stack gas temperature, [middot] R.
Ps = Absolute stack pressure, in. Hg.
Mw = Wet molecular weight of the stack gas, lb/1b-mole.
K1 = 4.077x10-3.

    5.3.1.3 Refer to the Method 201A operators manual, entitled 
Application Guide for Source PM10 Measurement with Constant 
Sampling Rate, for directions in the use of this equation for Q in the 
setup calculations.
    5.4 Cascade Impactor. The purpose of calibrating a cascade impactor 
is to determine the empirical constant (STK50), which is 
specific to the impactor and which permits the accurate determination of 
the cut size of the impactor stages at field conditions. It is not 
necessary to calibrate each individual impactor. Once an impactor has 
been calibrated, the calibration data can be applied to other impactors 
of identical design.
    5.4.1 Wind Tunnel. Same as in Section 5.2.1 of this method.
    5.4.2 Particle Generation System. Same as in Section 5.2.2 of this 
method.
    5.4.3 Hardware Configuration for Calibrations. An impaction stage 
constrains an aerosol to form circular or rectangular jets, which are 
directed toward a suitable substrate where the larger aerosol particles 
are collected. For calibration purposes, three stages of the cascade 
impactor shall be discussed and designated calibration stages 1, 2, and 
3. The first calibration stage consists of the collection substrate of 
an impaction stage and all upstream surfaces up to and including the 
nozzle. This may include other preceding impactor stages. The second and 
third calibration stages consist of each respective collection substrate 
and all upstream surfaces up to but excluding the collection substrate 
of the preceding calibration stage. This may include intervening 
impactor stages which are not designated as calibration stages. The cut 
size, or D50, of the adjacent calibration stages shall differ 
by a factor of not less than 1.5 and not more than 2.0. For example, if 
the first calibration stage has a D50 of 12 [micro]m, then 
the D50 of the downstream stage shall be between 6 and 8 
[micro]m.
    5.4.3.1 It is expected, but not necessary, that the complete 
hardware assembly will be used in each of the sampling runs of the 
calibration and performance determinations.

[[Page 419]]

Only the first calibration stage must be tested under isokinetic 
sampling conditions. The second and third calibration stages must be 
calibrated with the collection substrate of the preceding calibration 
stage in place, so that gas flow patterns existing in field operation 
will be simulated.
    5.4.3.2 Each of the PM10 stages should be calibrated with 
the type of collection substrate, viscid material (such as grease) or 
glass fiber, used in PM10 measurements. Note that most 
materials used as substrates at elevated temperatures are not viscid at 
normal laboratory conditions. The substrate material used for 
calibrations should minimize particle bounce, yet be viscous enough to 
withstand erosion or deformation by the impactor jets and not interfere 
with the procedure for measuring the collected PM.
    5.4.4 Calibration Procedure. Establish test particle generator 
operation and verify particle size microscopically. If monodispersity is 
to be verified by measurements at the beginning and the end of the run 
rather than by an integrated sample, these measurements shall be made at 
this time. Measure in triplicate the PM collected by the calibration 
stage (m) and the PM on all surfaces downstream of the respective 
calibration stage (m') for all of the flow rates and particle size 
combinations shown in Table 2 of this method. Techniques of mass 
measurement may include the use of a dye and spectrophotometer. 
Particles on the upstream side of a jet plate shall be included with the 
substrate downstream, except agglomerates of particles, which shall be 
included with the preceding or upstream substrate. Use the following 
formula to calculate the collection efficiency (E) for each stage.
    5.4.4.1 Use the formula in Section 5.2.5.3 of this method to 
calculate the standard deviation ([sigma]) for the replicate 
measurements. If [sigma] exceeds 0.10, repeat the replicate runs.
    5.4.4.2 Use the following formula to calculate the average 
collection efficiency (Eavg) for each set of replicate 
measurements.

    Eavg=(E1+E2+E3)/3

where E1, E2, and E3 are replicate 
measurements of E.

    5.4.4.3 Use the following formula to calculate Stk for each 
Eavg.
[GRAPHIC] [TIFF OMITTED] TC08NO91.048

where:

D = Aerodynamic diameter of the test particle, cm (g/
cm\3\)1/2.
Q = Gas flow rate through the calibration stage at inlet conditions, 
cm\3\/sec.
[mu] = Gas viscosity, micropoise.
A = Total cross-sectional area of the jets of the calibration stage, 
cm\2\.
dj = Diameter of one jet of the calibration stage, cm.

    5.4.4.4 Determine Stk50 for each calibration stage by 
plotting Eavg versus Stk on log-log paper. Stk50 
is the Stk number at 50 percent efficiency. Note that particle bounce 
can cause efficiency to decrease at high values of Stk. Thus, 50 percent 
efficiency can occur at multiple values of Stk. The calibration data 
should clearly indicate the value of Stk50 for minimum 
particle bounce. Impactor efficiency versus Stk with minimal particle 
bounce is characterized by a monotonically increasing function with 
constant or increasing slope with increasing Stk.
    5.4.4.5 The Stk50 of the first calibration stage can 
potentially decrease with decreasing nozzle size. Therefore, 
calibrations should be performed with enough nozzle sizes to provide a 
measured value within 25 percent of any nozzle size used in 
PM10 measurements.
    5.4.5 Criteria For Acceptance. Plot Eavg for the first 
calibration stage versus the square root of the ratio of Stk to 
Stk50 on Figure 9 of this method. Draw a smooth curve through 
all of the points. The curve shall be within the banded region.

                             6. Calculations

Calculations are as specified in Method 5, sections 6.3 through 6.7, and 
6.9 through 6.11, with the addition of the following:

6.1 Nomenclature.
Bws=Moisture fraction of stack, by volume, dimensionless.
C1=Viscosity constant, 51.12 micropoise for [deg]K (51.05 
micropoise for [deg]R).
C2=Viscosity constant, 0.372 micropoise/ [deg]K (0.207 
micropoise/[deg]R).
C3=Viscosity constant, 1.05x10-4 micropoise/ 
[deg]K\2\ (3.24x10-5 micropoise/[deg]R\2\).
C4=Viscosity constant, 53.147 micropoise/fraction 
O2.
C5=Viscosity constant, 74.143 micropoise/fraction 
H2O.
D50=Diameter of particles having a 50 percent probability of 
penetration, [micro]m.
fo=Stack gas fraction O2, by volume, dry basis.
K1=0.3858 [deg]K/mm Hg (17.64 [deg]R/in. Hg).
Mw=Wet molecular weight of stack gas, g/g-mole (lb/lb-mole).
Md=Dry molecular weight of stack gas, g/g-mole (1b/1b-mole).
Pbar=Barometric pressure at sampling site, mm Hg (in. Hg).
Ps=Absolute stack pressure, mm Hg (in. Hg).
Qs=Total cyclone flow rate at wet cyclone conditions, m\3\/
min (ft\3\/min).
Qs(std)=Total cyclone flow rate at standard conditions, dscm/
min (dscf/min).
Tm=Average absolute temperature of dry meter, [deg]K 
([deg]R).
Ts=Average absolute stack gas temperature, [deg]K ([deg]R).

[[Page 420]]

Vw(std)=Volume of water vapor in gas sample (standard 
conditions), scm (scf).
[thetas]=Total sampling time, min.
[mu]s=Viscosity of stack gas, micropoise.

    6.2 Analysis of Cascade Impactor Data. Use the manufacturer's 
recommended procedures to analyze data from cascade impactors.
    6.3 Analysis of Cyclone Data. Use the following procedures to 
analyze data from a single stage cyclone.
    6.3.1 PM10 Weight. Determine the PM catch in the 
PM10 range from the sum of the weights obtained from 
Container Numbers 1 and 3 less the acetone blank.
    6.3.2 Total PM Weight (optional). Determine the PM catch for greater 
than PM10 from the weight obtained from Container Number 2 
less the acetone blank, and add it to the PM10 weight.
    6.3.3 PM10 Fraction. Determine the PM10 
fraction of the total particulate weight by dividing the PM10 
particulate weight by the total particulate weight.
    6.3.4 Aerodynamic Cut Size. Calculate the stack gas viscosity as 
follows:

[mu]s=C1+C2Ts+C3Ts
2+C4f02-C5Bws

    6.3.4.1 The PM10 flow rate, at actual cyclone conditions, 
is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.049

    6.3.4.2 Calculate the molecular weight on a wet basis of the stack 
gas as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.050

    6.3.4.3 Calculate the actual D50 of the cyclone for the 
given conditions as follows:
[GRAPHIC] [TIFF OMITTED] TC08NO91.051

where [beta]1=0.027754 for metric units (0.15625 for English 
units).

    6.3.5 Acceptable Results. The results are acceptable if two 
conditions are met. The first is that 9.0 [micro]m <= D50 <= 
11.0 [micro]m. The second is that no sampling points are outside 
[Delta]pmin and [Delta]pmax, or that 80 percent <= 
I <= 120 percent and no more than one sampling point is outside 
[Delta]pmin and [Delta]pmax. If D50 is 
less than 9.0 [micro]m, reject the results and repeat the test.

                             7. Bibliography

    1. Same as Bibliography in Method 5.
    2. McCain, J.D., J.W. Ragland, and A.D. Williamson. Recommended 
Methodology for the Determination of Particle Size Distributions in 
Ducted Sources, Final Report. Prepared for the California Air Resources 
Board by Southern Research Institute. May 1986.
    3. Farthing, W.E., S.S. Dawes, A.D. Williamson, J.D. McCain, R.S. 
Martin, and J.W. Ragland. Development of Sampling Methods for Source 
PM10 Emissions. Southern Research Institute for the 
Environmental Protection Agency. April 1989. NTIS PB 89 190375, EPA/600/
3-88-056.
    4. Application Guide for Source PM10 Measurement with 
Constant Sampling Rate, EPA/600/3-88-057.

[[Page 421]]




[[Page 422]]





[[Page 423]]




    Barometric pressure,
Pbar, in. Hg= ------
    Stack static pressure,
Pg, in. H2 O= ------
    Average stack temperature,
ts, [deg]F= ------
    Meter temperature, tm, [deg]F= ------
    Orifice [Delta]H2, in. H2 O= ------
Gas analysis:

%CO2= ------
%O2= ------
%N2+%CO= ------
    Fraction moisture content,
Bws= ------
Molecular weight of stack gas, dry basis:
Md=0.44 (%CO2)+0.32 (%O2)+0.28 
(%N2+%CO)= ------ lb/lb mole
Molecular weight of stack gas, wet basis:
Mw=Md (1-Bws)+18 (Bws)= ----
-- lb/lb mole
Absolute stack pressure:
[GRAPHIC] [TIFF OMITTED] TC08NO91.073

Viscosity of stack gas:
[mu]s=152.418+0.2552 ts+3.2355x10-5 
ts2+0.53147 (%02)-74.143 Bws= ------ 
micropoise
Cyclone flow rate:

[[Page 424]]

[GRAPHIC] [TIFF OMITTED] TC08NO91.052

    Figure 4. Example worksheet 1, cyclone flow rate and [Delta]H.

Orifice pressure head ([Delta]H) needed for cyclone flow rate:
[GRAPHIC] [TIFF OMITTED] TC08NO91.053

Calculate [Delta] H for three temperatures:

------------------------------------------------------------------------
    ts, [deg]F
------------------------------------------------------------------------
 [Delta]H, in. H2O
 
------------------------------------------------------------------------

    Stack viscosity, [mu]s,
micropoise = ------
    Absolute stack pressure,
Ps, in. Hg = ------
    Average stack temperature,
ts, [deg]F = ------
    Meter temperature, tm, [deg]F = ------
    Method 201A pitot coefficient,
Cp = ------
    Cyclone flow rate, ft\3\/min,
Qs = ------
    Method 2 pitot coefficient,
Cp' = ------
    Molecular weight of stack gas, wet basis,
Mw = ------
    Nozzle diameter, Dn, in. = ------

Nozzle velocity:
[GRAPHIC] [TIFF OMITTED] TC08NO91.054

[GRAPHIC] [TIFF OMITTED] TC08NO91.055

[GRAPHIC] [TIFF OMITTED] TC08NO91.056

    Maximum and minimum velocities:
    Calculate Rmin
    [GRAPHIC] [TIFF OMITTED] TC08NO91.057
    
    If Rmin is less than 0.5, or if an imaginary number 
occurs when calculating Rmin, use Equation 1 to calculate 
vmin. Otherwise, use Equation 2.
    Eq. 1 vmin = vn (0.5) = ---- ft/sec

[[Page 425]]

    Eq. 2 vmin =vn Rmin = ---- ft/sec
    Calculate Rmax.
    [GRAPHIC] [TIFF OMITTED] TC08NO91.058
    
    If Rmax is greater than 1.5, use Equation 3 to calculate 
vmax. Otherwise, use Equation 4.
    Eq. 3 vmax = vn (1.5) = ---- ft/sec
    Eq. 4 vmax =vn Rmax = ---- ft/sec
    Figure 5. Example worksheet 2, nozzle selection.

Maximum and minimum velocity head values:
[GRAPHIC] [TIFF OMITTED] TC08NO91.059

[GRAPHIC] [TIFF OMITTED] TC08NO91.060


------------------------------------------------------------------------
                     Nozzle No.
------------------------------------------------------------------------
Dn, in..............................................  ...  ...  ...  ...
vn, ft/sec..........................................  ...  ...  ...  ...
vmin, ft/sec........................................  ...  ...  ...  ...
vmax, ft/sec........................................  ...  ...  ...  ...
[Delta]pmin, in. H2O................................  ...  ...  ...  ...
[Delta]pmax, in. H2O................................  ...  ...  ...  ...
------------------------------------------------------------------------

Velocity traverse data:
[GRAPHIC] [TIFF OMITTED] TC08NO91.061

    Total run time, minutes = ------
Number of traverse points =
[GRAPHIC] [TIFF OMITTED] TC08NO91.062

where:

t1 = dwell time at first traverse point, minutes.
[Delta]p'1 = the velocity head at the first traverse point 
(from a previous traverse), in. H20.
[Delta]p'avg = the square of the average square root of the 
[Delta]p's (from a previous velocity traverse), in. H20.

At subsequent traverse points, measure the velocity [Delta]p and 
calculate the dwell time by using the following equation:
[GRAPHIC] [TIFF OMITTED] TC08NO91.063


[[Page 426]]


where:

tn = dwell time at traverse point n, minutes.
[Delta]pn = measured velocity head at point n, in. 
H20.
[Delta]p1 = measured velocity head at point 1 in. 
H20.

    Figure 6. Example worksheet 3, dwell time.

----------------------------------------------------------------------------------------------------------------
                           Port
   Point No.    ------------------------------------------------------------------------------------------------
                   [Delta]p        t        [Delta]p       t        [Delta]p       t        [Delta]p       t
----------------------------------------------------------------------------------------------------------------
            1    ............  .........  ...........  .........  ...........  .........  ...........  .........
            2    ............  .........  ...........  .........  ...........  .........  ...........  .........
            3    ............  .........  ...........  .........  ...........  .........  ...........  .........
            4    ............  .........  ...........  .........  ...........  .........  ...........  .........
            5    ............  .........  ...........  .........  ...........  .........  ...........  .........
            6    ............  .........  ...........  .........  ...........  .........  ...........  .........
----------------------------------------------------------------------------------------------------------------

    Plant ------
    Date ------
    Run no. ------
    Filter no. ------
    Amount of liquid lost during
transport ------
    Acetone blank volume, ml ------
    Acetone wash volume, ml (4) ------
(5) ------
    Acetone blank conc., mg/mg (Equation 5-4,
Method 5) ------
    Acetone wash blank, mg (Equation 5-5,
Method 5) ------

------------------------------------------------------------------------
                                                 Weight of PM10 (mg)
                                           -----------------------------
               Container No.                  Final     Tare     Weight
                                             weight    weight     gain
------------------------------------------------------------------------
1.........................................  ........  ........  ........
3.........................................  ........  ........  ........
                                                               ---------
    Total.................................  ........  ........  ........
                                                               ---------
    Less acetone blank....................  ........  ........  ........
                                                               ---------
    Weight of PM10........................  ........  ........  ........
------------------------------------------------------------------------

    Figure 7. Method 201A analysis sheet.

 Table 1--Performance Specifications for Source PM10 Cyclones and Nozzle
                              Combinations
------------------------------------------------------------------------
            Parameter                    Units          Specifications
------------------------------------------------------------------------
1. Collection efficiency.........  Percent.........  Such that
                                                      collection
                                                      efficiency falls
                                                      within envelope
                                                      specified by
                                                      Section 5.2.6 and
                                                      Figure 8.
2. Cyclone cut size (D50)........  [micro]m........  10 1 [micro]m
                                                      aerodynamic
                                                      diameter.
------------------------------------------------------------------------


                        Table 2--Particle Sizes and Nominal Gas Velocities for Efficiency
----------------------------------------------------------------------------------------------------------------
                                                                   Target gas velocities (m/sec)
                                                  --------------------------------------------------------------
            Particle size ([micro]m)a               7 1.0           thn-eq>1.5           thn-eq>2.5
----------------------------------------------------------------------------------------------------------------
5 0.5......................  ...................  ...................  ...................
7 0.5......................  ...................  ...................  ...................
10 0.5.....................  ...................  ...................  ...................
14 1.0.....................  ...................  ...................  ...................
20 1.0.....................  ...................  ...................  ...................
----------------------------------------------------------------------------------------------------------------

(a) Mass median aerodynamic diameter.

[[Page 427]]




[[Page 428]]




  Method 202--Determination of Condensible Particulate Emissions From 
                           Stationary Sources

                     1. Applicability and Principle

    1.1 Applicability.
    1.1.1 This method applies to the determination of condensible 
particulate matter (CPM) emissions from stationary sources. It is 
intended to represent condensible matter as material that condenses 
after passing through a filter and as measured by this method (Note: The 
filter catch can be analyzed according to the appropriate method).
    1.1.2 This method may be used in conjunction with Method 201 or 201A 
if the probes are glass-lined. Using Method 202 in conjunction with 
Method 201 or 201A, only the impinger train configuration and analysis 
is addressed by this method. The sample train operation and front end 
recovery and analysis shall be conducted according to Method 201 or 
201A.
    1.1.3 This method may also be modified to measure material that 
condenses at other temperatures by specifying the filter and probe 
temperature. A heated Method 5 out-of-stack filter may be used instead 
of the in-stack filter to determine condensible emissions at wet 
sources.
    1.2 Principle.
    1.2.1 The CPM is collected in the impinger portion of a Method 17 
(appendix A, 40 CFR part 60) type sampling train. The impinger contents 
are immediately purged after the run with nitrogen (N2) to 
remove dissolved sulfur dioxide (SO2) gases from the impinger 
contents. The impinger solution is then extracted with methylene 
chloride (MeCl2). The organic and aqueous fractions are then 
taken to dryness and the residues weighed. The total of both fractions 
represents the CPM.
    1.2.2 The potential for low collection efficiency exist at oil-fired 
boilers. To improve the collection efficiency at these type of sources, 
an additional filter placed between the second and third impinger is 
recommended.

[[Page 429]]

                      2. Precision and Interference

    2.1 Precision. The precision based on method development tests at an 
oil-fired boiler and a catalytic cracker were 11.7 and 4.8 percent, 
respectively.
    2.2 Interference. Ammonia. In sources that use ammonia injection as 
a control technique for hydrogen chloride (HC1), the ammonia interferes 
by reacting with HC1 in the gas stream to form ammonium chloride 
(NH4 C1) which would be measured as CPM. The sample may be 
analyzed for chloride and the equivalent amount of NH4 C1 can 
be subtracted from the CPM weight. However, if NH4 C1 is to 
be counted as CPM, the inorganic fraction should be taken to near 
dryness (less than 1 ml liquid) in the oven and then allowed to air dry 
at ambient temperature to prevent any NH4 C1 from vaporizing.

                              3. Apparatus

    3.1 Sampling Train. Same as in Method 17, section 2.1, with the 
following exceptions noted below (see Figure 202-1). Note: Mention of 
trade names or specific products does not constitute endorsement by EPA.
    3.1.1 The probe extension shall be glass-lined or Teflon.
    3.1.2 Both the first and second impingers shall be of the Greenburg-
Smith design with the standard tip.
    3.1.3 All sampling train glassware shall be cleaned prior to the 
test with soap and tap water, water, and rinsed using tap water, water, 
acetone, and finally, MeCl2. It is important to completely 
remove all silicone grease from areas that will be exposed to the 
MeCl2 during sample recovery.
    3.2 Sample Recovery. Same as in Method 17, section 2.2, with the 
following additions:
    3.2.1 N2 Purge Line. Inert tubing and fittings capable of 
delivering 0 to 28 liters/min of N2 gas to the impinger train 
from a standard gas cylinder (see Figure 202-2). Standard 0.95 cm (\3/
8\-inch) plastic tubing and compression fittings in conjunction with an 
adjustable pressure regulator and needle valve may be used.
    3.2.2 Rotameter. Capable of measuring gas flow at 20 liters/min.
    3.3 Analysis. The following equipment is necessary in addition to 
that listed in Method 17, section 2.3:
    3.3.1 Separatory Funnel. Glass, 1-liter.
    3.3.2 Weighing Tins. 350-ml.
    3.3.3 Dry Equipment. Hot plate and oven with temperature control.
    3.3.4 Pipets. 5-ml.
    3.3.5 Ion Chromatograph. Same as in Method 5F, Section 2.1.6.

                               4. Reagents

    Unless otherwise indicated, all reagents must conform to the 
specifications established by the Committee on Analytical Reagents of 
the American Chemical Society. Where such specifications are not 
available, use the best available grade.
    4.1 Sampling. Same as in Method 17, section 3.1, with the addition 
of deionized distilled water to conform to the American Society for 
Testing and Materials Specification D 1193-74, Type II and the omittance 
of section 3.1.4.
    4.2 Sample Recovery. Same as in Method 17, section 3.2, with the 
following additions:
    4.2.1 N2 Gas. Zero N2 gas at delivery 
pressures high enough to provide a flow of 20 liters/min for 1 hour 
through the sampling train.
    4.2.2 Methylene Chloride, ACS grade. Blanks shall be run prior to 
use and only methylene chloride with low blank values (0.001 percent) 
shall be used.
    4.2.3 Water. Same as in section 4.1.
    4.3 Analysis. Same as in Method 17, section 3.3, with the following 
additions:
    4.3.1 Methylene Chloride. Same as section 4.2.2.
    4.3.2 Ammonium Hydroxide. Concentrated (14.8 M) NH4 OH.
    4.3.3 Water. Same as in section 4.1.
    4.3.4 Phenolphthalein. The pH indicator solution, 0.05 percent in 50 
percent alcohol.

                              5. Procedure

    5.1 Sampling. Same as in Method 17, section 4.1, with the following 
exceptions:
    5.1.1 Place 100 ml of water in the first three impingers.
    5.1.2 The use of silicone grease in train assembly is not 
recommended because it is very soluble in MeCl2 which may 
result in sample contamination. Teflon tape or similar means may be used 
to provide leak-free connections between glassware.
    5.2 Sample Recovery. Same as in Method 17, section 4.2 with the 
addition of a post-test N2 purge and specific changes in 
handling of individual samples as described below.
    5.2.1 Post-test N2 Purge for Sources Emitting 
SO2. (Note: This step is recommended, but is optional. With 
little or no SO2 is present in the gas stream, i.e., the pH 
of the impinger solution is greater than 4.5, purging has been found to 
be unnecessary.) As soon as possible after the post-test leak check, 
detach the probe and filter from the impinger train. Leave the ice in 
the impinger box to prevent removal of moisture during the purge. If 
necessary, add more ice during the purge to maintain the gas temperature 
below 20 [deg]C. With no flow of gas through the clean purge line and 
fittings, attach it to the input of the impinger train (see Figure 202-
2). To avoid over- or under-pressurizing the impinger array, slowly 
commence the N2 gas flow through the line while 
simultaneously opening the meter box pump valve(s). When using the gas 
cylinder pressure to push the purge gas through the sample train, adjust 
the flow rate to 20 liters/min through the rotameter. When pulling the

[[Page 430]]

purge gas through the sample train using the meter box vacuum pump, set 
the orifice pressure differential to [Delta]H2 and maintain 
an overflow rate through the rotameter of less than 2 liters/min. This 
will guarantee that the N2 delivery system is operating at 
greater than ambient pressure and prevents the possibility of passing 
ambient air (rather than N2) through the impingers. Continue 
the purge under these conditions for 1 hour, checking the rotameter and 
[Delta]H value(s) periodically. After 1 hour, simultaneously turn off 
the delivery and pumping systems.
    5.2.2 Sample Handling.
    5.2.2.1 Container Nos. 1, 2, and 3. If filter catch is to be 
determined, as detailed in Method 17, section 4.2.
    5.2.2.2 Container No. 4 (Impinger Contents). Measure the liquid in 
the first three impingers to within 1 ml using a clean graduated 
cylinder or by weighing it to within 0.5 g using a balance. Record the 
volume or weight of liquid present to be used to calculate the moisture 
content of the effluent gas. Quantitatively transfer this liquid into a 
clean sample bottle (glass or plastic); rinse each impinger and the 
connecting glassware, including probe extension, twice with water, 
recover the rinse water, and add it to the same sample bottle. Mark the 
liquid level on the bottle.
    5.2.2.3 Container No. 5 (MeCl2 Rinse). Follow the water 
rinses of each impinger and the connecting glassware, including the 
probe extension with two rinses of MeCl2; save the rinse 
products in a clean, glass sample jar. Mark the liquid level on the jar.
    5.2.2.4 Container No. 6 (Water Blank). Once during each field test, 
place 500 ml of water in a separate sample container.
    5.2.2.5 Container No. 7 (MeCl2 Blank). Once during each 
field test, place in a separate glass sample jar a volume of 
MeCl2 approximately equivalent to the volume used to conduct 
the MeCl2 rinse of the impingers.
    5.3 Analysis. Record the data required on a sheet such as the one 
shown in Figure 202-3. Handle each sample container as follows:
    5.3.1 Container Nos. 1, 2, and 3. If filter catch is analyzed, as 
detailed in Method 17, section 4.3.
    5.3.2 Container Nos. 4 and 5. Note the level of liquid in the 
containers and confirm on the analytical data sheet whether leakage 
occurred during transport. If a noticeable amount of leakage has 
occurred, either void the sample or use methods, subject to the approval 
of the Administrator, to correct the final results. Measure the liquid 
in Container No. 4 either volumetrically to 1 ml 
or gravimetrically to 0.5 g. Remove a 5-ml aliquot 
and set aside for later ion chromatographic (IC) analysis of sulfates. 
(Note: Do not use this aliquot to determine chlorides since the HCl will 
be evaporated during the first drying step; Section 8.2 details a 
procedure for this analysis.)
    5.3.2.1 Extraction. Separate the organic fraction of the sample by 
adding the contents of Container No. 4 (MeCl2) to the 
contents of Container No. 4 in a 1000-ml separatory funnel. After 
mixing, allow the aqueous and organic phases to fully separate, and 
drain off most of the organic/MeCl2 phase. Then add 75 ml of 
MeCl2 to the funnel, mix well, and drain off the lower 
organic phase. Repeat with another 75 ml of MeCl2. This 
extraction should yield about 250 ml of organic extract. Each time, 
leave a small amount of the organic/MeCl2 phase in the 
separatory funnel ensuring that no water is collected in the organic 
phase. Place the organic extract in a tared 350-ml weighing tin.
    5.3.2.2 Organic Fraction Weight Determination (Organic Phase from 
Container Nos. 4 and 5). Evaporate the organic extract at room 
temperature and pressure in a laboratory hood. Following evaporation, 
desiccate the organic fraction for 24 hours in a desiccator containing 
anhydrous calcium sulfate. Weigh to a constant weight and report the 
results to the nearest 0.1 mg.
    5.3.2.3 Inorganic Fraction Weight Determination. (Note: If 
NH4 Cl is to be counted as CPM, the inorganic fraction should 
be taken to near dryness (less than 1 ml liquid) in the oven and then 
allow to air dry at ambient temperature. If multiple acid emissions are 
suspected, the ammonia titration procedure in section 8.1 may be 
preferred.) Using a hot plate, or equivalent, evaporate the aqueous 
phase to approximately 50 ml; then, evaporate to dryness in a 105 [deg]C 
oven. Redissovle the residue in 100 ml of water. Add five drops of 
phenolphthalein to this solution; then, add concentrated (14.8 M) 
NH4 OH until the sample turns pink. Any excess NH2 
OH will be evaporated during the drying step. Evaporate the sample to 
dryness in a 105 [deg]C oven, desiccate the sample for 24 hours, weigh 
to a constant weight, and record the results to the nearest 0.1 mg. 
(Note: The addition of NH4 OH is recommended, but is optional 
when little or no SO2 is present in the gas stream, i.e., 
when the pH of the impinger solution is greater than 4.5, the addition 
of NH4 OH is not necessary.)
    5.3.2.4 Analysis of Sulfate by IC to Determine Ammonium Ion 
(NH4+) Retained in the Sample. (Note: If NH4 OH is 
not added, omit this step.) Determine the amount of sulfate in the 
aliquot taken from Container No. 4 earlier as described in Method 5F 
(appendix A, 40 CFR part 60). Based on the IC SO4-2 analysis 
of the aliquot, calculate the correction factor to subtract the 
NH4+ retained in the sample and to add the combined water 
removed by the acid-base reaction (see section 7.2).
    5.3.3 Analysis of Water and MeCl2 Blanks (Container Nos. 
6 and 7). Analyze these sample blanks as described above in sections 
5.3.2.3 and 5.3.2.2, respectively.

[[Page 431]]

    5.3.4 Analysis of Acetone Blank (Container No. 8). Same as in Method 
17, section 4.3.

                             6. Calibration

    Same as in Method 17, section 5, except for the following:
    6.1 IC Calibration. Same as Method 5F, section 5.
    6.2 Audit Procedure. Concurrently, analyze the audit sample and a 
set of compliance samples in the same manner to evaluate the technique 
of the analyst and the standards preparation. The same analyst, 
analytical reagents, and analytical system shall be used both for 
compliance samples and the EPA audit sample. If this condition is met, 
auditing of subsequent compliance analyses for the same enforcement 
agency within 30 days is not required. An audit sample set may not be 
used to validate different sets of compliance samples under the 
jurisdiction of different enforcement agencies, unless prior 
arrangements are made with both enforcement agencies.
    6.3 Audit Samples. Audit Sample Availability. Audit samples will be 
supplied only to enforcement agencies for compliance tests. The 
availability of audit samples may be obtained by writing:

Source Test Audit Coordinator (MD-77B), Quality Assurance Division, 
Atmospheric Research and Exposure Assessment Laboratory, U.S. 
Environmental Protection Agency, Research Triangle, Park, NC 27711

or by calling the Source Test Audit Coordinator (STAC) at (919) 541-
7834. The request for the audit sample must be made at least 30 days 
prior to the scheduled compliance sample analysis.
    6.4 Audit Results. Calculate the audit sample concentration 
according to the calculation procedure described in the audit 
instructions included with the audit sample. Fill in the audit sample 
concentration and the analyst's name on the audit response form included 
with the audit instructions. Send one copy to the EPA Regional Office or 
the appropriate enforcement agency and a second copy to the STAC. The 
EPA Regional Office or the appropriate enforcement agency will report 
the results of the audit to the laboratory being audited. Include this 
response with the results of the compliance samples in relevant reports 
to the EPA Regional Office or the appropriate enforcement agency.

                             7. Calculations

    Same as in Method 17, section 6, with the following additions:
    7.1 Nomenclature. Same as in Method 17, section 6.1 with the 
following additions.

Ccpm=Concentration of the CPM in the stack gas, dry basis, 
corrected to standard conditions, g/dscm (g/dscf).
CSO4=Concentration of SO4-2 in the sample, mg/ml.
mb=Sum of the mass of the water and MeCl2 blanks, 
mg.
mc=Mass of the NH4+ added to sample to form 
ammonium sulfate, mg.
mi=Mass of inorganic CPM matter, mg.
mo=Mass of organic CPM, mg.
mr=Mass of dried sample from inorganic fraction, mg.
Vb=Volume of aliquot taken for IC analysis, ml.
Vic=Volume of impinger contents sample, ml.

    7.2 Correction for NH4+ and H2O. Calculate the 
correction factor to subtract the NH4+ retained in the sample 
based on the IC SO4-2 and if desired, add the combined water 
removed by the acid-base reaction.
[GRAPHIC] [TIFF OMITTED] TC08NO91.064

 =0.1840, when only correcting for NH4+.

    7.3 Mass of Inorganic CPM.
    [GRAPHIC] [TIFF OMITTED] TC08NO91.065
    
7.4
    Concentration of CPM.
    [GRAPHIC] [TIFF OMITTED] TC08NO91.066
    
                        8. Alternative Procedures

    8.1 Determination of NH4+ Retained in Sample by 
Titration.
    8.1.1 An alternative procedure to determine the amount of 
NH4+ added to the inorganic fraction by titration may be 
used. After dissolving the inorganic residue in 100 ml of water, titrate 
the solution with 0.1 N NH4 OH to a pH of 7.0, as indicated 
by a pH meter. The 0.1 N NH4 OH is made as follows: Add 7 ml 
of concentrated (14.8 M) NH4 OH to 1 liter of water. 
Standardize against standardized 0.1 N H2 SO4 and 
calculate the exact normality using a procedure parallel to that 
described in section 5.5 of Method 6 (appendix A, 40 CFR part 60). 
Alternatively, purchase 0.1 N NH4 OH that has been 
standardized against a National Institute of Standards and Technology 
reference material.
    8.1.2 Calculate the concentration of SO4-2 in the sample 
using the following equation.
[GRAPHIC] [TIFF OMITTED] TC08NO91.067

where

N = Normality of the NH4OH, mg/ml.
Vt = Volume of NH4 OH titrant, ml.
48.03 = mg/meq.
100 = Volume of solution, ml.


[[Page 432]]


    8.3.1 Calculate the CPM as described in section 7.
    8.2 Analysis of Chlorides by IC. At the conclusion of the final 
weighing as described in section 5.3.2.3, redissolve the inorganic 
fraction in 100 ml of water. Analyze an aliquot of the redissolved 
sample for chlorides by IC using techniques similar to those described 
in Method 5F for sulfates. Previous drying of the sample should have 
removed all HCl. Therefore, the remaining chlorides measured by IC can 
be assumed to be NH4 Cl, and this weight can be subtracted 
from the weight determined for CPM.
    8.3 Air Purge to Remove SO2 from Impinger Contents. As an 
alternative to the post-test N2 purge described in section 
5.2.1, the tester may opt to conduct the post-test purge with air at 20 
liter/min. Note: The use of an air purge is not as effective as a 
N2 purge.
    8.4 Chloroform-ether Extraction. As an alternative to the methylene 
chloride extraction described in section 5.3.2.1, the tester may opt to 
conduct a chloroform-ether extraction. Note: The Chloroform-ether was 
not as effective as the MeCl2 in removing the organics, but 
it was found to be an acceptable organic extractant. Chloroform and 
diethylether of ACS grade, with low blank values (0.001 percent), shall 
be used. Analysis of the chloroform and diethylether blanks shall be 
conducted according to Section 5.3.3 for MeCl2.
    8.4.1 Add the contents of Container No. 4 to a 1000-ml separatory 
funnel. Then add 75 ml of chloroform to the funnel, mix well, and drain 
off the lower organic phase. Repeat two more times with 75 ml of 
chloroform. Then perform three extractions with 75 ml of diethylether. 
This extraction should yield approximately 450 ml of organic extraction. 
Each time, leave a small amount of the organic/MeCl2 phase in 
the separatory funnel ensuring that no water is collected in the organic 
phase.
    8.4.2 Add the contents of Container No. 5 to the organic extraction. 
Place approximately 300 ml of the organic extract in a tared 350-ml 
weighing tin while storing the remaining organic extract in a sample 
container. As the organic extract evaporates, add the remaining extract 
to the weighing tin.
    8.4.3 Determine the weight of the organic phase as described in 
Section 5.3.2.2.
    8.5 Improving Collection Efficiency. If low impinger collection 
efficiency is suspected, the following procedure may be used.
    8.5.1 Place an out-of-stock filter as described in Method 8 between 
the second and third impingers.
    8.5.2 Recover and analyze the filter according to Method 17, Section 
4.2. Include the filter holder as part of the connecting glassware and 
handle as described in sections 5.2.2.2 and 5.2.2.3.
    8.5.3 Calculate the Concentration of CPM as follows:
    [GRAPHIC] [TIFF OMITTED] TC08NO91.068
    
where:

mf = amount of CPM collected on out-of-stack filter, mg.

    8.6 Wet Source Testing. When testing at a wet source, use a heated 
out-of-stack filter as described in Method 5.

                             9. Bibliography

    1. DeWees, W.D., S.C. Steinsberger, G.M. Plummer, L.T. Lay, G.D. 
McAlister, and R.T. Shigehara. ``Laboratory and Field Evaluation of the 
EPA Method 5 Impinger Catch for Measuring Condensible Matter from 
Stationary Sources.'' Paper presented at the 1989 EPA/AWMA International 
Symposium on Measurement of Toxic and Related Air Pollutants. Raleigh, 
North Carolina. May 1-5, 1989.
    2. DeWees, W.D. and K.C. Steinsberger. ``Method Development and 
Evaluation of Draft Protocol for Measurement of Condensible Particulate 
Emissions.'' Draft Report. November 17, 1989.
    3. Texas Air Control Board, Laboratory Division. ``Determination of 
Particulate in Stack Gases Containing Sulfuric Acid and/or Sulfur 
Dioxide.'' Laboratory Methods for Determination of Air Pollutants. 
Modified December 3, 1976.
    4. Nothstein, Greg. Masters Thesis. University of Washington. 
Department of Environmental Health. Seattle, Washington.
    5. ``Particulate Source Test Procedures Adopted by Puget Sound Air 
Pollution Control Agency Board of Directors.'' Puget Sound Air Pollution 
Control Agency, Engineering Division. Seattle, Washington. August 11, 
1983.
    6. Commonwealth of Pennsylvania, Department of Environmental 
Resources. Chapter 139, Sampling and Testing (Title 25, Rules and 
Regulations, Part I, Department of Environmental Resources, Subpart C, 
Protection of Natural Resources, Article III, Air Resources). January 8, 
1960.
    7. Wisconsin Department of Natural Resources. Air Management 
Operations Handbook, Revision 3. January 11, 1988.

[[Page 433]]




[[Page 434]]




                         Moisture Determination

Volume or weight of liquid in impingers: ------ ml or g
Weight of moisture in silica gel: ------ g

                  Sample Preparation (Container No. 4)

Amount of liquid lost during transport: ------ ml
Final volume: ------ ml
pH of sample prior to analysis: ------

[[Page 435]]

Addition of NH4 OH required: ------
Sample extracted 2X with 75 ml MeCl2?: ------

                        For Titration of Sulfate

Normality of NH2 OH: ------ N
Volume of sample titrated: ------ ml
Volume of titrant: ------ ml

                             Sample Analysis

------------------------------------------------------------------------
                                                 Weight of condensible
                                                    particulate, mg
               Container number               --------------------------
                                                Final     Tare    Weight
                                                weight   weight    gain
------------------------------------------------------------------------
4 (Inorganic)................................  .......  .......  .......
4 & 5 (Organic)..............................  .......  .......  .......
------------------------------------------------------------------------

Total: ------
Less Blank: ------
Weight of Consensible Particulate:
Figure 202-3. Analytical data sheet.

 Method 204--Criteria for and Verification of a Permanent or Temporary 
                             Total Enclosure

                        1. Scope and Application

    This procedure is used to determine whether a permanent or temporary 
enclosure meets the criteria for a total enclosure. An existing building 
may be used as a temporary or permanent enclosure as long as it meets 
the appropriate criteria described in this method.

                          2. Summary of Method

    An enclosure is evaluated against a set of criteria. If the criteria 
are met and if all the exhaust gases from the enclosure are ducted to a 
control device, then the volatile organic compounds (VOC) capture 
efficiency (CE) is assumed to be 100 percent, and CE need not be 
measured. However, if part of the exhaust gas stream is not ducted to a 
control device, CE must be determined.

                             3. Definitions

    3.1 Natural Draft Opening (NDO). Any permanent opening in the 
enclosure that remains open during operation of the facility and is not 
connected to a duct in which a fan is installed.
    3.2 Permanent Total Enclosure (PE). A permanently installed 
enclosure that completely surrounds a source of emissions such that all 
VOC emissions are captured and contained for discharge to a control 
device.
    3.3 Temporary Total Enclosure (TTE). A temporarily installed 
enclosure that completely surrounds a source of emissions such that all 
VOC emissions that are not directed through the control device (i.e. 
uncaptured) are captured by the enclosure and contained for discharge 
through ducts that allow for the accurate measurement of the uncaptured 
VOC emissions.
    3.4 Building Enclosure (BE). An existing building that is used as a 
TTE.

                                4. Safety

    An evaluation of the proposed building materials and the design for 
the enclosure is recommended to minimize any potential hazards.

                5. Criteria for Temporary Total Enclosure

    5.1 Any NDO shall be at least four equivalent opening diameters from 
each VOC emitting point unless otherwise specified by the Administrator.
    5.2 Any exhaust point from the enclosure shall be at least four 
equivalent duct or hood diameters from each NDO.
    5.3 The total area of all NDO's shall not exceed 5 percent of the 
surface area of the enclosure's four walls, floor, and ceiling.
    5.4 The average facial velocity (FV) of air through all NDO's shall 
be at least 3,600 m/hr (200 fpm). The direction of air flow through all 
NDO's shall be into the enclosure.
    5.5 All access doors and windows whose areas are not included in 
section 5.3 and are not included in the calculation in section 5.4 shall 
be closed during routine operation of the process.

               6. Criteria for a Permanent Total Enclosure

    6.1 Same as sections 5.1 and 5.3 through 5.5.
    6.2 All VOC emissions must be captured and contained for discharge 
through a control device.

                           7. Quality Control

    7.1 The success of this method lies in designing the TTE to simulate 
the conditions that exist without the TTE (i.e., the effect of the TTE 
on the normal flow patterns around the affected facility or the amount 
of uncaptured VOC emissions should be minimal). The TTE must enclose the 
application stations, coating reservoirs, and all areas from the 
application station to the oven. The oven does not have to be enclosed 
if it is under negative pressure. The NDO's of the temporary enclosure 
and an exhaust fan must be properly sized and placed.
    7.2 Estimate the ventilation rate of the TTE that best simulates the 
conditions that exist without the TTE (i.e., the effect of the TTE on 
the normal flow patterns around the affected facility or the amount of 
uncaptured VOC emissions should be minimal). Figure 204-1 or the 
following equation may be used as an aid.
[GRAPHIC] [TIFF OMITTED] TR16JN97.000


[[Page 436]]


Measure the concentration (CG) and flow rate (QG) 
of the captured gas stream, specify a safe concentration (CF) 
for the uncaptured gas stream, estimate the CE, and then use the plot in 
Figure 204-1 or Equation 204-1 to determine the volumetric flow rate of 
the uncaptured gas stream (QF). An exhaust fan that has a variable flow 
control is desirable.
    7.3 Monitor the VOC concentration of the captured gas steam in the 
duct before the capture device without the TTE. To minimize the effect 
of temporal variation on the captured emissions, the baseline 
measurement should be made over as long a time period as practical. 
However, the process conditions must be the same for the measurement in 
section 7.5 as they are for this baseline measurement. This may require 
short measuring times for this quality control check before and after 
the construction of the TTE.
    7.4 After the TTE is constructed, monitor the VOC concentration 
inside the TTE. This concentration should not continue to increase, and 
must not exceed the safe level according to Occupational Safety and 
Health Administration requirements for permissible exposure limits. An 
increase in VOC concentration indicates poor TTE design.
    7.5 Monitor the VOC concentration of the captured gas stream in the 
duct before the capture device with the TTE. To limit the effect of the 
TTE on the process, the VOC concentration with and without the TTE must 
be within 10 percent. If the measurements do not agree, adjust the 
ventilation rate from the TTE until they agree within 10 percent.

                              8. Procedure

    8.1 Determine the equivalent diameters of the NDO's and determine 
the distances from each VOC emitting point to all NDO's. Determine the 
equivalent diameter of each exhaust duct or hood and its distance to all 
NDO's. Calculate the distances in terms of equivalent diameters. The 
number of equivalent diameters shall be at least four.
    8.2 Measure the total surface area (AT) of the enclosure 
and the total area (AN) of all NDO's in the enclosure. 
Calculate the NDO to enclosure area ratio (NEAR) as follows:
[GRAPHIC] [TIFF OMITTED] TR16JN97.001

The NEAR must be <=10.05.
    8.3 Measure the volumetric flow rate, corrected to standard 
conditions, of each gas stream exiting the enclosure through an exhaust 
duct or hood using EPA Method 2. In some cases (e.g., when the building 
is the enclosure), it may be necessary to measure the volumetric flow 
rate, corrected to standard conditions, of each gas stream entering the 
enclosure through a forced makeup air duct using Method 2. Calculate FV 
using the following equation:
[GRAPHIC] [TIFF OMITTED] TR16JN97.002

where:

QO = the sum of the volumetric flow from all gas streams 
exiting the enclosure through an exhaust duct or hood.
QI = the sum of the volumetric flow from all gas streams into 
the enclosure through a forced makeup air duct; zero, if there is no 
forced makeup air into the enclosure.
AN = total area of all NDO's in enclosure.

    The FV shall be at least 3,600 m/hr (200 fpm). Alternatively, 
measure the pressure differential across the enclosure. A pressure drop 
of 0.013 mm Hg (0.007 in. H2O) corresponds to an FV of 3,600 
m/hr (200 fpm).
    8.4 Verify that the direction of air flow through all NDO's is 
inward. If FV is less than 9,000 m/hr (500 fpm), the continuous inward 
flow of air shall be verified using streamers, smoke tubes, or tracer 
gases. Monitor the direction of air flow for at least 1 hour, with 
checks made no more than 10 minutes apart. If FV is greater than 9,000 
m/hr (500 fpm), the direction of air flow through the NDOs shall be 
presumed to be inward at all times without verification.

                               9. Diagrams

[[Page 437]]

[GRAPHIC] [TIFF OMITTED] TR16JN97.026

 Method 204A--Volatile Organic Compounds Content in Liquid Input Stream

                        1. Scope and Application

    1.1 Applicability. This procedure is applicable for determining the 
input of volatile organic compounds (VOC). It is intended to be used in 
the development of liquid/gas protocols for determining VOC capture 
efficiency (CE) for surface coating and printing operations.
    1.2 Principle. The amount of VOC introduced to the process (L) is 
the sum of the products of the weight (W) of each VOC containing liquid 
(ink, paint, solvent, etc.) used and its VOC content (V).

[[Page 438]]

    1.3 Sampling Requirements. A CE test shall consist of at least three 
sampling runs. Each run shall cover at least one complete production 
cycle, but shall be at least 3 hours long. The sampling time for each 
run need not exceed 8 hours, even if the production cycle has not been 
completed. Alternative sampling times may be used with the approval of 
the Administrator.

                          2. Summary of Method

    The amount of VOC containing liquid introduced to the process is 
determined as the weight difference of the feed material before and 
after each sampling run. The VOC content of the liquid input material is 
determined by volatilizing a small aliquot of the material and analyzing 
the volatile material using a flame ionization analyzer (FIA). A sample 
of each VOC containing liquid is analyzed with an FIA to determine V.

                                3. Safety

    Because this procedure is often applied in highly explosive areas, 
caution and care should be exercised in choosing, installing, and using 
the appropriate equipment.

                        4. Equipment and Supplies

    Mention of trade names or company products does not constitute 
endorsement. All gas concentrations (percent, ppm) are by volume, unless 
otherwise noted.
    4.1 Liquid Weight.
    4.1.1 Balances/Digital Scales. To weigh drums of VOC containing 
liquids to within 0.2 lb or 1.0 percent of the total weight of VOC 
liquid used.
    4.1.2 Volume Measurement Apparatus (Alternative). Volume meters, 
flow meters, density measurement equipment, etc., as needed to achieve 
the same accuracy as direct weight measurements.
    4.2 VOC Content (FIA Technique). The liquid sample analysis system 
is shown in Figures 204A-1 and 204A-2. The following equipment is 
required:
    4.2.1 Sample Collection Can. An appropriately-sized metal can to be 
used to collect VOC containing materials. The can must be constructed in 
such a way that it can be grounded to the coating container.
    4.2.2 Needle Valves. To control gas flow.
    4.2.3 Regulators. For carrier gas and calibration gas cylinders.
    4.2.4 Tubing. Teflon or stainless steel tubing with diameters and 
lengths determined by connection requirements of equipment. The tubing 
between the sample oven outlet and the FIA shall be heated to maintain a 
temperature of 120 5 [deg]C.
    4.2.5 Atmospheric Vent. A tee and 0- to 0.5-liter/min rotameter 
placed in the sampling line between the carrier gas cylinder and the VOC 
sample vessel to release the excess carrier gas. A toggle valve placed 
between the tee and the rotameter facilitates leak tests of the analysis 
system.
    4.2.6 Thermometer. Capable of measuring the temperature of the hot 
water bath to within 1 [deg]C.
    4.2.7 Sample Oven. Heated enclosure, containing calibration gas coil 
heaters, critical orifice, aspirator, and other liquid sample analysis 
components, capable of maintaining a temperature of 120 5 [deg]C.
    4.2.8 Gas Coil Heaters. Sufficient lengths of stainless steel or 
Teflon tubing to allow zero and calibration gases to be heated to the 
sample oven temperature before entering the critical orifice or 
aspirator.
    4.2.9 Water Bath. Capable of heating and maintaining a sample vessel 
temperature of 100 5 [deg]C.
    4.2.10 Analytical Balance. To measure 0.001 g.
    4.2.11 Disposable Syringes. 2-cc or 5-cc.
    4.2.12 Sample Vessel. Glass, 40-ml septum vial. A separate vessel is 
needed for each sample.
    4.2.13 Rubber Stopper. Two-hole stopper to accommodate 3.2-mm (\1/
8\-in.) Teflon tubing, appropriately sized to fit the opening of the 
sample vessel. The rubber stopper should be wrapped in Teflon tape to 
provide a tighter seal and to prevent any reaction of the sample with 
the rubber stopper. Alternatively, any leak-free closure fabricated of 
nonreactive materials and accommodating the necessary tubing fittings 
may be used.
    4.2.14 Critical Orifices. Calibrated critical orifices capable of 
providing constant flow rates from 50 to 250 ml/min at known pressure 
drops. Sapphire orifice assemblies (available from O'Keefe Controls 
Company) and glass capillary tubing have been found to be adequate for 
this application.
    4.2.15 Vacuum Gauge. Zero to 760-mm (0- to 30-in.) Hg U-Tube 
manometer or vacuum gauge.
    4.2.16 Pressure Gauge. Bourdon gauge capable of measuring the 
maximum air pressure at the aspirator inlet (e.g., 100 psig).
    4.2.17 Aspirator. A device capable of generating sufficient vacuum 
at the sample vessel to create critical flow through the calibrated 
orifice when sufficient air pressure is present at the aspirator inlet. 
The aspirator must also provide sufficient sample pressure to operate 
the FIA. The sample is also mixed with the dilution gas within the 
aspirator.
    4.2.18 Soap Bubble Meter. Of an appropriate size to calibrate the 
critical orifices in the system.
    4.2.19 Organic Concentration Analyzer. An FIA with a span value of 
1.5 times the expected concentration as propane; however, other span 
values may be used if it can be demonstrated that they would provide 
more accurate measurements. The FIA instrument should be the same 
instrument used in the gaseous analyses adjusted with the same

[[Page 439]]

fuel, combustion air, and sample back-pressure (flow rate) settings. The 
system shall be capable of meeting or exceeding the following 
specifications:
    4.2.19.1 Zero Drift. Less than 3.0 percent of 
the span value.
    4.2.19.2 Calibration Drift. Less than 3.0 
percent of the span value.
    4.2.19.3 Calibration Error. Less than 5.0 
percent of the calibration gas value.
    4.2.20 Integrator/Data Acquisition System. An analog or digital 
device or computerized data acquisition system used to integrate the FIA 
response or compute the average response and record measurement data. 
The minimum data sampling frequency for computing average or integrated 
values is one measurement value every 5 seconds. The device shall be 
capable of recording average values at least once per minute.
    4.2.21 Chart Recorder (Optional). A chart recorder or similar device 
is recommended to provide a continuous analog display of the measurement 
results during the liquid sample analysis.

                        5. Reagents and Standards

    5.1 Calibration and Other Gases. Gases used for calibration, fuel, 
and combustion air (if required) are contained in compressed gas 
cylinders. All calibration gases shall be traceable to National 
Institute of Standards and Technology standards and shall be certified 
by the manufacturer to 1 percent of the tag value. 
Additionally, the manufacturer of the cylinder should provide a 
recommended shelf life for each calibration gas cylinder over which the 
concentration does not change more than 2 percent 
from the certified value. For calibration gas values not generally 
available, dilution systems calibrated using Method 205 may be used. 
Alternative methods for preparing calibration gas mixtures may be used 
with the approval of the Administrator.
    5.1.1 Fuel. The FIA manufacturer's recommended fuel should be used. 
A 40 percent H2/60 percent He or 40 percent H2/60 percent 
N2 gas mixture is recommended to avoid an oxygen synergism 
effect that reportedly occurs when oxygen concentration varies 
significantly from a mean value. Other mixtures may be used provided the 
tester can demonstrate to the Administrator that there is no oxygen 
synergism effect.
    5.1.2 Carrier Gas. High purity air with less than 1 ppm of organic 
material (as propane) or less than 0.1 percent of the span value, 
whichever is greater.
    5.1.3 FIA Linearity Calibration Gases. Low-, mid-, and high-range 
gas mixture standards with nominal propane concentrations of 20-30, 45-
55, and 70-80 percent of the span value in air, respectively. Other 
calibration values and other span values may be used if it can be shown 
to the Administrator's satisfaction that equally accurate measurements 
would be achieved.
    5.1.4 System Calibration Gas. Gas mixture standard containing 
propane in air, approximating the undiluted VOC concentration expected 
for the liquid samples.

             6. Sample Collection, Preservation and Storage

    6.1 Samples must be collected in a manner that prevents or minimizes 
loss of volatile components and that does not contaminate the coating 
reservoir.
    6.2 Collect a 100-ml or larger sample of the VOC containing liquid 
mixture at each application location at the beginning and end of each 
test run. A separate sample should be taken of each VOC containing 
liquid added to the application mixture during the test run. If a fresh 
drum is needed during the sampling run, then obtain a sample from the 
fresh drum.
    6.3 When collecting the sample, ground the sample container to the 
coating drum. Fill the sample container as close to the rim as possible 
to minimize the amount of headspace.
    6.4 After the sample is collected, seal the container so the sample 
cannot leak out or evaporate.
    6.5 Label the container to clearly identify the contents.

                           7. Quality Control

    7.1 Required instrument quality control parameters are found in the 
following sections:
    7.1.1 The FIA system must be calibrated as specified in section 8.1.
    7.1.2 The system drift check must be performed as specified in 
section 8.2.
    7.2 Audits.
    7.2.1 Audit Procedure. Concurrently, analyze the audit sample and a 
set of compliance samples in the same manner to evaluate the technique 
of the analyst and the standards preparation. The same analyst, 
analytical reagents, and analytical system shall be used both for 
compliance samples and the EPA audit sample. If this condition is met, 
auditing of subsequent compliance analyses for the same enforcement 
agency within 30 days is not required. An audit sample set may not be 
used to validate different sets of compliance samples under the 
jurisdiction of different enforcement agencies, unless prior 
arrangements are made with both enforcement agencies.
    7.2.2 Audit Samples and Audit Sample Availability. Audit samples 
will be supplied only to enforcement agencies for compliance tests. The 
availability of audit samples may be obtained by writing: Source Test 
Audit Coordinator (STAC) (MD-77B), Quality Assurance Division, 
Atmospheric Research and

[[Page 440]]

Exposure Assessment Laboratory, U.S. Environmental Protection Agency, 
Research Triangle Park, NC 27711 or by calling the STAC at (919) 541-
7834. The request for the audit sample must be made at least 30 days 
prior to the scheduled compliance sample analysis.
    7.2.3 Audit Results. Calculate the audit sample concentration 
according to the calculation procedure described in the audit 
instructions included with the audit sample. Fill in the audit sample 
concentration and the analyst's name on the audit response form included 
with the audit instructions. Send one copy to the EPA Regional Office or 
the appropriate enforcement agency, and a second copy to the STAC. The 
EPA Regional Office or the appropriate enforcement agency will report 
the results of the audit to the laboratory being audited. Include this 
response with the results of the compliance samples in relevant reports 
to the EPA Regional Office or the appropriate enforcement agency.

                   8. Calibration and Standardization

    8.1 FIA Calibration and Linearity Check. Make necessary adjustments 
to the air and fuel supplies for the FIA and ignite the burner. Allow 
the FIA to warm up for the period recommended by the manufacturer. 
Inject a calibration gas into the measurement system and adjust the 
back-pressure regulator to the value required to achieve the flow rates 
specified by the manufacturer. Inject the zero- and the high-range 
calibration gases and adjust the analyzer calibration to provide the 
proper responses. Inject the low- and mid-range gases and record the 
responses of the measurement system. The calibration and linearity of 
the system are acceptable if the responses for all four gases are within 
5 percent of the respective gas values. If the performance of the system 
is not acceptable, repair or adjust the system and repeat the linearity 
check. Conduct a calibration and linearity check after assembling the 
analysis system and after a major change is made to the system.
    8.2 Systems Drift Checks. After each sample, repeat the system 
calibration checks in section 9.2.7 before any adjustments to the FIA or 
measurement system are made. If the zero or calibration drift exceeds 
3 percent of the span value, discard the result 
and repeat the analysis.
    Alternatively, recalibrate the FIA as in section 8.1 and report the 
results using both sets of calibration data (i.e., data determined prior 
to the test period and data determined following the test period). The 
data that results in the lowest CE value shall be reported as the 
results for the test run.
    8.3 Critical Orifice Calibration.
    8.3.1 Each critical orifice must be calibrated at the specific 
operating conditions under which it will be used. Therefore, assemble 
all components of the liquid sample analysis system as shown in Figure 
204A-3. A stopwatch is also required.
    8.3.2 Turn on the sample oven, sample line, and water bath heaters, 
and allow the system to reach the proper operating temperature. Adjust 
the aspirator to a vacuum of 380 mm (15 in.) Hg vacuum. Measure the time 
required for one soap bubble to move a known distance and record 
barometric pressure.
    8.3.3 Repeat the calibration procedure at a vacuum of 406 mm (16 
in.) Hg and at 25-mm (1-in.) Hg intervals until three consecutive 
determinations provide the same flow rate. Calculate the critical flow 
rate for the orifice in ml/min at standard conditions. Record the vacuum 
necessary to achieve critical flow.

                              9. Procedure

    9.1 Determination of Liquid Input Weight.
    9.1.1 Weight Difference. Determine the amount of material introduced 
to the process as the weight difference of the feed material before and 
after each sampling run. In determining the total VOC containing liquid 
usage, account for:
    (a) The initial (beginning) VOC containing liquid mixture.
    (b) Any solvent added during the test run.
    (c) Any coating added during the test run.
    (d) Any residual VOC containing liquid mixture remaining at the end 
of the sample run.
    9.1.1.1 Identify all points where VOC containing liquids are 
introduced to the process. To obtain an accurate measurement of VOC 
containing liquids, start with an empty fountain (if applicable). After 
completing the run, drain the liquid in the fountain back into the 
liquid drum (if possible) and weigh the drum again. Weigh the VOC 
containing liquids to 0.5 percent of the total 
weight (full) or 1.0 percent of the total weight 
of VOC containing liquid used during the sample run, whichever is less. 
If the residual liquid cannot be returned to the drum, drain the 
fountain into a preweighed empty drum to determine the final weight of 
the liquid.
    9.1.1.2 If it is not possible to measure a single representative 
mixture, then weigh the various components separately (e.g., if solvent 
is added during the sampling run, weigh the solvent before it is added 
to the mixture). If a fresh drum of VOC containing liquid is needed 
during the run, then weigh both the empty drum and fresh drum.
    9.1.2 Volume Measurement (Alternative). If direct weight 
measurements are not feasible, the tester may use volume meters or flow 
rate meters and density measurements to determine the weight of liquids 
used if it can be demonstrated that the technique produces results 
equivalent to the direct weight measurements. If a single representative

[[Page 441]]

mixture cannot be measured, measure the components separately.
    9.2 Determination of VOC Content in Input Liquids
    9.2.1 Assemble the liquid VOC content analysis system as shown in 
Figure 204A-1.
    9.2.2 Permanently identify all of the critical orifices that may be 
used. Calibrate each critical orifice under the expected operating 
conditions (i.e., sample vacuum and temperature) against a volume meter 
as described in section 8.3.
    9.2.3 Label and tare the sample vessels (including the stoppers and 
caps) and the syringes.
    9.2.4 Install an empty sample vessel and perform a leak test of the 
system. Close the carrier gas valve and atmospheric vent and evacuate 
the sample vessel to 250 mm (10 in.) Hg absolute or less using the 
aspirator. Close the toggle valve at the inlet to the aspirator and 
observe the vacuum for at least 1 minute. If there is any change in the 
sample pressure, release the vacuum, adjust or repair the apparatus as 
necessary, and repeat the leak test.
    9.2.5 Perform the analyzer calibration and linearity checks 
according to the procedure in section 5.1. Record the responses to each 
of the calibration gases and the back-pressure setting of the FIA.
    9.2.6 Establish the appropriate dilution ratio by adjusting the 
aspirator air supply or substituting critical orifices. Operate the 
aspirator at a vacuum of at least 25 mm (1 in.) Hg greater than the 
vacuum necessary to achieve critical flow. Select the dilution ratio so 
that the maximum response of the FIA to the sample does not exceed the 
high-range calibration gas.
    9.2.7 Perform system calibration checks at two levels by introducing 
compressed gases at the inlet to the sample vessel while the aspirator 
and dilution devices are operating. Perform these checks using the 
carrier gas (zero concentration) and the system calibration gas. If the 
response to the carrier gas exceeds 0.5 percent of 
span, clean or repair the apparatus and repeat the check. Adjust the 
dilution ratio as necessary to achieve the correct response to the 
upscale check, but do not adjust the analyzer calibration. Record the 
identification of the orifice, aspirator air supply pressure, FIA back-
pressure, and the responses of the FIA to the carrier and system 
calibration gases.
    9.2.8 After completing the above checks, inject the system 
calibration gas for approximately 10 minutes. Time the exact duration of 
the gas injection using a stopwatch. Determine the area under the FIA 
response curve and calculate the system response factor based on the 
sample gas flow rate, gas concentration, and the duration of the 
injection as compared to the integrated response using Equations 204A-2 
and 204A-3.
    9.2.9 Verify that the sample oven and sample line temperatures are 
120 5 [deg]C and that the water bath temperature 
is 100 5 [deg]C.
    9.2.10 Fill a tared syringe with approximately 1 g of the VOC 
containing liquid and weigh it. Transfer the liquid to a tared sample 
vessel. Plug the sample vessel to minimize sample loss. Weigh the sample 
vessel containing the liquid to determine the amount of sample actually 
received. Also, as a quality control check, weigh the empty syringe to 
determine the amount of material delivered. The two coating sample 
weights should agree within 0.02 g. If not, repeat the procedure until 
an acceptable sample is obtained.
    9.2.11 Connect the vessel to the analysis system. Adjust the 
aspirator supply pressure to the correct value. Open the valve on the 
carrier gas supply to the sample vessel and adjust it to provide a 
slight excess flow to the atmospheric vent. As soon as the initial 
response of the FIA begins to decrease, immerse the sample vessel in the 
water bath. (Applying heat to the sample vessel too soon may cause the 
FIA response to exceed the calibrated range of the instrument and, thus, 
invalidate the analysis.)
    9.2.12 Continuously measure and record the response of the FIA until 
all of the volatile material has been evaporated from the sample and the 
instrument response has returned to the baseline (i.e., response less 
than 0.5 percent of the span value). Observe the aspirator supply 
pressure, FIA back-pressure, atmospheric vent, and other system 
operating parameters during the run; repeat the analysis procedure if 
any of these parameters deviate from the values established during the 
system calibration checks in section 9.2.7. After each sample, perform 
the drift check described in section 8.2. If the drift check results are 
acceptable, calculate the VOC content of the sample using the equations 
in section 11.2. Alternatively, recalibrate the FIA as in section 8.1 
and report the results using both sets of calibration data (i.e., data 
determined prior to the test period and data determined following the 
test period). The data that results in the lowest CE value shall be 
reported as the results for the test run. Integrate the area under the 
FIA response curve, or determine the average concentration response and 
the duration of sample analysis.

                   10. Data Analysis and Calculations

    10.1 Nomenclature.
AL=area under the response curve of the liquid sample, area 
count.
AS=area under the response curve of the calibration gas, area 
count.
CS=actual concentration of system calibration gas, ppm 
propane.
K=1.830 x 10-9 g/(ml-ppm).
L=total VOC content of liquid input, kg.

[[Page 442]]

ML=mass of liquid sample delivered to the sample vessel, g.
q = flow rate through critical orifice, ml/min.
RF=liquid analysis system response factor, g/area count.
[thetas]S=total gas injection time for system calibration gas 
during integrator calibration, min.
VFj=final VOC fraction of VOC containing liquid j.
VIj=initial VOC fraction of VOC containing liquid j.
VAj=VOC fraction of VOC containing liquid j added during the 
run.
V=VOC fraction of liquid sample.
WFj=weight of VOC containing liquid j remaining at end of the 
run, kg.
WIj=weight of VOC containing liquid j at beginning of the 
run, kg.
WAj=weight of VOC containing liquid j added during the run, 
kg.
    10.2 Calculations
    10.2.1 Total VOC Content of the Input VOC Containing Liquid.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.003
    
    10.2.2 Liquid Sample Analysis System Response Factor for Systems 
Using Integrators, Grams/Area Count.
[GRAPHIC] [TIFF OMITTED] TR16JN97.004

    10.2.3 VOC Content of the Liquid Sample.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.005
    
                         11. Method Performance

    The measurement uncertainties are estimated for each VOC containing 
liquid as follows: W = 2.0 percent and V = 4.0 percent. Based on these numbers, the probable 
uncertainty for L is estimated at about 4.5 
percent for each VOC containing liquid.

                              12. Diagrams

[[Page 443]]

[GRAPHIC] [TIFF OMITTED] TR16JN97.036


[[Page 444]]


[GRAPHIC] [TIFF OMITTED] TR16JN97.037


[[Page 445]]


[GRAPHIC] [TIFF OMITTED] TR16JN97.038


[[Page 446]]



  Method 204B--Volatile Organic Compounds Emissions in Captured Stream

                        1. Scope and Application

    1.1 Applicability. This procedure is applicable for determining the 
volatile organic compounds (VOC) content of captured gas streams. It is 
intended to be used in the development of a gas/gas protocol for 
determining VOC capture efficiency (CE) for surface coating and printing 
operations. The procedure may not be acceptable in certain site-specific 
situations [e.g., when: (1) direct-fired heaters or other circumstances 
affect the quantity of VOC at the control device inlet; and (2) 
particulate organic aerosols are formed in the process and are present 
in the captured emissions].
    1.2 Principle. The amount of VOC captured (G) is calculated as the 
sum of the products of the VOC content (CGj), the flow rate 
(QGj), and the sample time ([Theta]C) from each 
captured emissions point.
    1.3 Sampling Requirements. A CE test shall consist of at least three 
sampling runs. Each run shall cover at least one complete production 
cycle, but shall be at least 3 hours long. The sampling time for each 
run need not exceed 8 hours, even if the production cycle has not been 
completed. Alternative sampling times may be used with the approval of 
the Administrator.

                          2. Summary of Method

    A gas sample is extracted from the source though a heated sample 
line and, if necessary, a glass fiber filter to a flame ionization 
analyzer (FIA).

                                3. Safety

    Because this procedure is often applied in highly explosive areas, 
caution and care should be exercised in choosing, installing, and using 
the appropriate equipment.

                        4. Equipment and Supplies

    Mention of trade names or company products does not constitute 
endorsement. All gas concentrations (percent, ppm) are by volume, unless 
otherwise noted.
    4.1 Gas VOC Concentration. A schematic of the measurement system is 
shown in Figure 204B-1. The main components are as follows:
    4.1.1 Sample Probe. Stainless steel or equivalent. The probe shall 
be heated to prevent VOC condensation.
    4.1.2 Calibration Valve Assembly. Three-way valve assembly at the 
outlet of the sample probe to direct the zero and calibration gases to 
the analyzer. Other methods, such as quick-connect lines, to route 
calibration gases to the outlet of the sample probe are acceptable.
    4.1.3 Sample Line. Stainless steel or Teflon tubing to transport the 
sample gas to the analyzer. The sample line must be heated to prevent 
condensation.
    4.1.4 Sample Pump. A leak-free pump, to pull the sample gas through 
the system at a flow rate sufficient to minimize the response time of 
the measurement system. The components of the pump that contact the gas 
stream shall be constructed of stainless steel or Teflon. The sample 
pump must be heated to prevent condensation.
    4.1.5 Sample Flow Rate Control. A sample flow rate control valve and 
rotameter, or equivalent, to maintain a constant sampling rate within 10 
percent. The flow rate control valve and rotameter must be heated to 
prevent condensation. A control valve may also be located on the sample 
pump bypass loop to assist in controlling the sample pressure and flow 
rate.
    4.1.6 Organic Concentration Analyzer. An FIA with a span value of 
1.5 times the expected concentration as propane; however, other span 
values may be used if it can be demonstrated to the Administrator's 
satisfaction that they would provide equally accurate measurements. The 
system shall be capable of meeting or exceeding the following 
specifications:
    4.1.6.1 Zero Drift. Less than 3.0 percent of 
the span value.
    4.1.6.2 Calibration Drift. Less than 3.0 
percent of the span value.
    4.1.6.3 Calibration Error. Less than 5.0 
percent of the calibration gas value.
    4.1.6.4 Response Time. Less than 30 seconds.
    4.1.7 Integrator/Data Acquisition System. An analog or digital 
device, or computerized data acquisition system used to integrate the 
FIA response or compute the average response and record measurement 
data. The minimum data sampling frequency for computing average or 
integrated values is one measurement value every 5 seconds. The device 
shall be capable of recording average values at least once per minute.
    4.2 Captured Emissions Volumetric Flow Rate.
    4.2.1 Method 2 or 2A Apparatus. For determining volumetric flow 
rate.
    4.2.2 Method 3 Apparatus and Reagents. For determining molecular 
weight of the gas stream. An estimate of the molecular weight of the gas 
stream may be used if approved by the Administrator.
    4.2.3 Method 4 Apparatus and Reagents. For determining moisture 
content, if necessary.

                        5. Reagents and Standards

    5.1 Calibration and Other Gases. Gases used for calibration, fuel, 
and combustion air (if required) are contained in compressed gas 
cylinders. All calibration gases shall be traceable to National 
Institute of Standards and Technology standards and shall be certified 
by the manufacturer to 1 percent of

[[Page 447]]

the tag value. Additionally, the manufacturer of the cylinder should 
provide a recommended shelf life for each calibration gas cylinder over 
which the concentration does not change more than 2 percent from the certified value. For calibration gas 
values not generally available, dilution systems calibrated using Method 
205 may be used. Alternative methods for preparing calibration gas 
mixtures may be used with the approval of the Administrator.
    5.1.1 Fuel. The FIA manufacturer's recommended fuel should be used. 
A 40 percent H2/60 percent He or 40 percent H2/60 
percent N2 gas mixture is recommended to avoid an oxygen 
synergism effect that reportedly occurs when oxygen concentration varies 
significantly from a mean value. Other mixtures may be used provided the 
tester can demonstrate to the Administrator that there is no oxygen 
synergism effect.
    5.1.2 Carrier Gas. High purity air with less than 1 ppm of organic 
material (as propane or carbon equivalent) or less than 0.1 percent of 
the span value, whichever is greater.
    5.1.3 FIA Linearity Calibration Gases. Low-, mid-, and high-range 
gas mixture standards with nominal propane concentrations of 20-30, 45-
55, and 70-80 percent of the span value in air, respectively. Other 
calibration values and other span values may be used if it can be shown 
to the Administrator's satisfaction that equally accurate measurements 
would be achieved.
    5.2 Particulate Filter. An in-stack or an out-of-stack glass fiber 
filter is recommended if exhaust gas particulate loading is significant. 
An out-of-stack filter must be heated to prevent any condensation unless 
it can be demonstrated that no condensation occurs.

                           6. Quality Control

    6.1 Required instrument quality control parameters are found in the 
following sections:
    6.1.1 The FIA system must be calibrated as specified in section 7.1.
    6.1.2 The system drift check must be performed as specified in 
section 7.2.
    6.1.3 The system check must be conducted as specified in section 
7.3.
    6.2 Audits.
    6.2.1 Analysis Audit Procedure. Immediately before each test, 
analyze an audit cylinder as described in section 7.2. The analysis 
audit must agree with the audit cylinder concentration within 10 
percent.
    6.2.2 Audit Samples and Audit Sample Availability. Audit samples 
will be supplied only to enforcement agencies for compliance tests. The 
availability of audit samples may be obtained by writing: Source Test 
Audit Coordinator (STAC) (MD-77B), Quality Assurance Division, 
Atmospheric Research and Exposure Assessment Labortory, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711 or by 
calling the STAC at (919) 541-7834. The request for the audit sample 
must be made at least 30 days prior to the scheduled compliance sample 
analysis.
    6.2.3 Audit Results. Calculate the audit sample concentration 
according to the calculation procedure described in the audit 
instructions included with the audit sample. Fill in the audit sample 
concentration and the analyst's name on the audit response form included 
with the audit instructions. Send one copy to the EPA Regional Office or 
the appropriate enforcement agency, and a second copy to the STAC. The 
EPA Regional Office or the appropriate enforcement agency will report 
the results of the audit to the laboratory being audited. Include this 
response with the results of the compliance samples in relevant reports 
to the EPA Regional Office or the appropriate enforcement agency.

                   7. Calibration and Standardization

    7.1 FIA Calibration and Linearity Check. Make necessary adjustments 
to the air and fuel supplies for the FIA and ignite the burner. Allow 
the FIA to warm up for the period recommended by the manufacturer. 
Inject a calibration gas into the measurement system and adjust the 
back-pressure regulator to the value required to achieve the flow rates 
specified by the manufacturer. Inject the zero-and the high-range 
calibration gases and adjust the analyzer calibration to provide the 
proper responses. Inject the low- and mid-range gases and record the 
responses of the measurement system. The calibration and linearity of 
the system are acceptable if the responses for all four gases are within 
5 percent of the respective gas values. If the performance of the system 
is not acceptable, repair or adjust the system and repeat the linearity 
check. Conduct a calibration and linearity check after assembling the 
analysis system and after a major change is made to the system.
    7.2 Systems Drift Checks. Select the calibration gas that most 
closely approximates the concentration of the captured emissions for 
conducting the drift checks. Introduce the zero and calibration gases at 
the calibration valve assembly and verify that the appropriate gas flow 
rate and pressure are present at the FIA. Record the measurement system 
responses to the zero and calibration gases. The performance of the 
system is acceptable if the difference between the drift check 
measurement and the value obtained in section 7.1 is less than 3 percent 
of the span value. Alternatively, recalibrate the FIA as in section 7.1 
and report the results using both sets of calibration data (i.e., data 
determined prior to the test period and data determined following the 
test period). The data that results in the lowest CE value

[[Page 448]]

shall be reported as the results for the test run. Conduct the system 
drift checks at the end of each run.
    7.3 System Check. Inject the high-range calibration gas at the inlet 
of the sampling probe and record the response. The performance of the 
system is acceptable if the measurement system response is within 5 
percent of the value obtained in section 7.1 for the high-range 
calibration gas. Conduct a system check before and after each test run.

                              8. Procedure

    8.1. Determination of Volumetric Flow Rate of Captured Emissions.
    8.1.1 Locate all points where emissions are captured from the 
affected facility. Using Method 1, determine the sampling points. Be 
sure to check each site for cyclonic or swirling flow.
    8.1.2 Measure the velocity at each sampling site at least once every 
hour during each sampling run using Method 2 or 2A.
    8.2 Determination of VOC Content of Captured Emissions.
    8.2.1 Analysis Duration. Measure the VOC responses at each captured 
emissions point during the entire test run or, if applicable, while the 
process is operating. If there are multiple captured emission locations, 
design a sampling system to allow a single FIA to be used to determine 
the VOC responses at all sampling locations.
    8.2.2 Gas VOC Concentration.
    8.2.2.1 Assemble the sample train as shown in Figure 204B-1. 
Calibrate the FIA according to the procedure in section 7.1.
    8.2.2.2 Conduct a system check according to the procedure in section 
7.3.
    8.2.2.3 Install the sample probe so that the probe is centrally 
located in the stack, pipe, or duct, and is sealed tightly at the stack 
port connection.
    8.2.2.4 Inject zero gas at the calibration valve assembly. Allow the 
measurement system response to reach zero. Measure the system response 
time as the time required for the system to reach the effluent 
concentration after the calibration valve has been returned to the 
effluent sampling position.
    8.2.2.5 Conduct a system check before, and a system drift check 
after, each sampling run according to the procedures in sections 7.2 and 
7.3. If the drift check following a run indicates unacceptable 
performance (see section 7.3), the run is not valid. Alternatively, 
recalibrate the FIA as in section 7.1 and report the results using both 
sets of calibration data (i.e., data determined prior to the test period 
and data determined following the test period). The data that results in 
the lowest CE value shall be reported as the results for the test run. 
The tester may elect to perform system drift checks during the run not 
to exceed one drift check per hour.
    8.2.2.6 Verify that the sample lines, filter, and pump temperatures 
are 120 5 [deg]C.
    8.2.2.7 Begin sampling at the start of the test period and continue 
to sample during the entire run. Record the starting and ending times 
and any required process information as appropriate. If multiple 
captured emission locations are sampled using a single FIA, sample at 
each location for the same amount of time (e.g., 2 minutes) and continue 
to switch from one location to another for the entire test run. Be sure 
that total sampling time at each location is the same at the end of the 
test run. Collect at least four separate measurements from each sample 
point during each hour of testing. Disregard the measurements at each 
sampling location until two times the response time of the measurement 
system has elapsed. Continue sampling for at least 1 minute and record 
the concentration measurements.
    8.2.3 Background Concentration.

    Note: Not applicable when the building is used as the temporary 
total enclosure (TTE).

    8.2.3.1 Locate all natural draft openings (NDO's) of the TTE. A 
sampling point shall be at the center of each NDO, unless otherwise 
specified by the Administrator. If there are more than six NDO's, choose 
six sampling points evenly spaced among the NDO's.
    8.2.3.2 Assemble the sample train as shown in Figure 204B-2. 
Calibrate the FIA and conduct a system check according to the procedures 
in sections 7.1 and 7.3.

    Note: This sample train shall be separate from the sample train used 
to measure the captured emissions.

    8.2.3.3 Position the probe at the sampling location.
    8.2.3.4 Determine the response time, conduct the system check, and 
sample according to the procedures described in sections 8.2.2.4 through 
8.2.2.7.
    8.2.4 Alternative Procedure. The direct interface sampling and 
analysis procedure described in section 7.2 of Method 18 may be used to 
determine the gas VOC concentration. The system must be designed to 
collect and analyze at least one sample every 10 minutes. If the 
alternative procedure is used to determine the VOC concentration of the 
captured emissions, it must also be used to determine the VOC 
concentration of the uncaptured emissions.

                    9. Data Analysis and Calculations

    9.1 Nomenclature.

Ai=area of NDO i, ft\2\.
AN=total area of all NDO's in the enclosure, ft\2\.
CBi=corrected average VOC concentration of background 
emissions at point i, ppm propane.
CB=average background concentration, ppm propane.

[[Page 449]]

CGj=corrected average VOC concentration of captured emissions 
at point j, ppm propane.
CDH=average measured concentration for the drift check 
calibration gas, ppm propane.
CDO=average system drift check concentration for zero 
concentration gas, ppm propane.
CH=actual concentration of the drift check calibration gas, 
ppm propane.
Ci=uncorrected average background VOC concentration measured 
at point i, ppm propane.
Cj=uncorrected average VOC concentration measured at point j, 
ppm propane.
G=total VOC content of captured emissions, kg.
K1=1.830x10-6 kg/(m\3\-ppm).
n=number of measurement points.
QGj=average effluent volumetric flow rate corrected to 
standard conditions at captured emissions point j, m\3\/min.
[Theta]C=total duration of captured emissions.
    9.2 Calculations.
    9.2.1 Total VOC Captured Emissions.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.006
    
    9.2.2 VOC Concentration of the Captured Emissions at Point j.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.007
    
    9.2.3 Background VOC Concentration at Point i.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.008
    
    9.2.4 Average Background Concentration.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.009
    
    Note: If the concentration at each point is within 20 percent of the 
average concentration of all points, then use the arithmetic average.

                         10. Method Performance

    The measurement uncertainties are estimated for each captured or 
uncaptured emissions point as follows: QGj=5.5 percent and CGj=5.0 
percent. Based on these numbers, the probable uncertainty for G is 
estimated at about 7.4 percent.

                              11. Diagrams

[[Page 450]]

[GRAPHIC] [TIFF OMITTED] TR16JN97.027


[[Page 451]]


[GRAPHIC] [TIFF OMITTED] TR16JN97.028


[[Page 452]]



  Method 204C--Volatile Organic Compounds Emissions in Captured Stream 
                          (Dilution Technique)

                        1. Scope and Application

    1.1 Applicability. This procedure is applicable for determining the 
volatile organic compounds (VOC) content of captured gas streams. It is 
intended to be used in the development of a gas/gas protocol in which 
uncaptured emissions are also measured for determining VOC capture 
efficiency (CE) for surface coating and printing operations. A dilution 
system is used to reduce the VOC concentration of the captured emissions 
to about the same concentration as the uncaptured emissions. The 
procedure may not be acceptable in certain site-specific situations 
[e.g., when: (1) direct-fired heaters or other circumstances affect the 
quantity of VOC at the control device inlet; and (2) particulate organic 
aerosols are formed in the process and are present in the captured 
emissions].
    1.2 Principle. The amount of VOC captured (G) is calculated as the 
sum of the products of the VOC content (CGj), the flow rate 
(QGj), and the sampling time ([Theta]C) from each 
captured emissions point.
    1.3 Sampling Requirements. A CE test shall consist of at least three 
sampling runs. Each run shall cover at least one complete production 
cycle, but shall be at least 3 hours long. The sampling time for each 
run need not exceed 8 hours, even if the production cycle has not been 
completed. Alternative sampling times may be used with the approval of 
the Administrator.

                          2. Summary of Method

    A gas sample is extracted from the source using an in-stack dilution 
probe through a heated sample line and, if necessary, a glass fiber 
filter to a flame ionization analyzer (FIA). The sample train contains a 
sample gas manifold which allows multiple points to be sampled using a 
single FIA.

                                3. Safety

    Because this procedure is often applied in highly explosive areas, 
caution and care should be exercised in choosing, installing, and using 
the appropriate equipment.

                        4. Equipment and Supplies

    Mention of trade names or company products does not constitute 
endorsement. All gas concentrations (percent, ppm) are by volume, unless 
otherwise noted.
    4.1 Gas VOC Concentration. A schematic of the measurement system is 
shown in Figure 204C-1. The main components are as follows:
    4.1.1 Dilution System. A Kipp in-stack dilution probe and controller 
or similar device may be used. The dilution rate may be changed by 
substituting different critical orifices or adjustments of the aspirator 
supply pressure. The dilution system shall be heated to prevent VOC 
condensation. Note: An out-of-stack dilution device may be used.
    4.1.2 Calibration Valve Assembly. Three-way valve assembly at the 
outlet of the sample probe to direct the zero and calibration gases to 
the analyzer. Other methods, such as quick-connect lines, to route 
calibration gases to the outlet of the sample probe are acceptable.
    4.1.3 Sample Line. Stainless steel or Teflon tubing to transport the 
sample gas to the analyzer. The sample line must be heated to prevent 
condensation.
    4.1.4 Sample Pump. A leak-free pump, to pull the sample gas through 
the system at a flow rate sufficient to minimize the response time of 
the measurement system. The components of the pump that contact the gas 
stream shall be constructed of stainless steel or Teflon. The sample 
pump must be heated to prevent condensation.
    4.1.5 Sample Flow Rate Control. A sample flow rate control valve and 
rotameter, or equivalent, to maintain a constant sampling rate within 10 
percent. The flow control valve and rotameter must be heated to prevent 
condensation. A control valve may also be located on the sample pump 
bypass loop to assist in controlling the sample pressure and flow rate.
    4.1.6 Sample Gas Manifold. Capable of diverting a portion of the 
sample gas stream to the FIA, and the remainder to the bypass discharge 
vent. The manifold components shall be constructed of stainless steel or 
Teflon. If captured or uncaptured emissions are to be measured at 
multiple locations, the measurement system shall be designed to use 
separate sampling probes, lines, and pumps for each measurement location 
and a common sample gas manifold and FIA. The sample gas manifold and 
connecting lines to the FIA must be heated to prevent condensation.

    Note: Depending on the number of sampling points and their location, 
it may not be possible to use only one FIA. However to reduce the effect 
of calibration error, the number of FIA's used during a test should be 
keep as small as possible.

    4.1.7 Organic Concentration Analyzer. An FIA with a span value of 
1.5 times the expected concentration as propane; however, other span 
values may be used if it can be demonstrated to the Administrator's 
satisfaction that they would provide equally accurate measurements. The 
system shall be capable of meeting or exceeding the following 
specifications:
    4.1.7.1 Zero Drift. Less than 3.0 percent of 
the span value.
    4.1.7.2 Calibration Drift. Less than 3.0 
percent of the span value.

[[Page 453]]

    4.1.7.3 Calibration Error. Less than 5.0 
percent of the calibration gas value.
    4.1.7.4 Response Time. Less than 30 seconds.
    4.1.8 Integrator/Data Acquisition System. An analog or digital 
device or computerized data acquisition system used to integrate the FIA 
response or compute the average response and record measurement data. 
The minimum data sampling frequency for computing average or integrated 
values is one measurement value every 5 seconds. The device shall be 
capable of recording average values at least once per minute.
    4.2 Captured Emissions Volumetric Flow Rate.
    4.2.1 Method 2 or 2A Apparatus. For determining volumetric flow 
rate.
    4.2.2 Method 3 Apparatus and Reagents. For determining molecular 
weight of the gas stream. An estimate of the molecular weight of the gas 
stream may be used if approved by the Administrator.
    4.2.3 Method 4 Apparatus and Reagents. For determining moisture 
content, if necessary.

                        5. Reagents and Standards

    5.1 Calibration and Other Gases. Gases used for calibration, fuel, 
and combustion air (if required) are contained in compressed gas 
cylinders. All calibration gases shall be traceable to National 
Institute of Standards and Technology standards and shall be certified 
by the manufacturer to 1 percent of the tag value. 
Additionally, the manufacturer of the cylinder should provide a 
recommended shelf life for each calibration gas cylinder over which the 
concentration does not change more than 2 percent 
from the certified value. For calibration gas values not generally 
available, dilution systems calibrated using Method 205 may be used. 
Alternative methods for preparing calibration gas mixtures may be used 
with the approval of the Administrator.
    5.1.1 Fuel. The FIA manufacturer's recommended fuel should be used. 
A 40 percent H2/60 percent He or 40 percent H2/60 
percent N2 gas mixture is recommended to avoid an oxygen 
synergism effect that reportedly occurs when oxygen concentration varies 
significantly from a mean value. Other mixtures may be used provided the 
tester can demonstrate to the Administrator that there is no oxygen 
synergism effect
    5.1.2 Carrier Gas and Dilution Air Supply. High purity air with less 
than 1 ppm of organic material (as propane or carbon equivalent), or 
less than 0.1 percent of the span value, whichever is greater.
    5.1.3 FIA Linearity Calibration Gases. Low-, mid-, and high-range 
gas mixture standards with nominal propane concentrations of 20-30, 45-
55, and 70-80 percent of the span value in air, respectively. Other 
calibration values and other span values may be used if it can be shown 
to the Administrator's satisfaction that equally accurate measurements 
would be achieved.
    5.1.4 Dilution Check Gas. Gas mixture standard containing propane in 
air, approximately half the span value after dilution.
    5.2 Particulate Filter. An in-stack or an out-of-stack glass fiber 
filter is recommended if exhaust gas particulate loading is significant. 
An out-of-stack filter must be heated to prevent any condensation unless 
it can be demonstrated that no condensation occurs.

                           6. Quality Control

    6.1 Required instrument quality control parameters are found in the 
following sections:
    6.1.1 The FIA system must be calibrated as specified in section 7.1.
    6.1.2 The system drift check must be performed as specified in 
section 7.2.
    6.1.3 The dilution factor must be determined as specified in section 
7.3.
    6.1.4 The system check must be conducted as specified in section 
7.4.
    6.2 Audits.
    6.2.1 Analysis Audit Procedure. Immediately before each test, 
analyze an audit cylinder as described in section 7.2. The analysis 
audit must agree with the audit cylinder concentration within 10 
percent.
    6.2.2 Audit Samples and Audit Sample Availability. Audit samples 
will be supplied only to enforcement agencies for compliance tests. The 
availability of audit samples may be obtained by writing: Source Test 
Audit Coordinator (STAC) (MD-77B), Quality Assurance Division, 
Atmospheric Research and Exposure Assessment Laboratory, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711 or by 
calling the STAC at (919) 541-7834. The request for the audit sample 
must be made at least 30 days prior to the scheduled compliance sample 
analysis.
    6.2.3 Audit Results. Calculate the audit sample concentration 
according to the calculation procedure described in the audit 
instructions included with the audit sample. Fill in the audit sample 
concentration and the analyst's name on the audit response form included 
with the audit instructions. Send one copy to the EPA Regional Office or 
the appropriate enforcement agency, and a second copy to the STAC. The 
EPA Regional Office or the appropriate enforcement agency will report 
the results of the audit to the laboratory being audited. Include this 
response with the results of the compliance samples in relevant reports 
to the EPA Regional Office or the appropriate enforcement agency.

[[Page 454]]

                   7. Calibration and Standardization

    7.1 FIA Calibration and Linearity Check. Make necessary adjustments 
to the air and fuel supplies for the FIA and ignite the burner. Allow 
the FIA to warm up for the period recommended by the manufacturer. 
Inject a calibration gas into the measurement system after the dilution 
system and adjust the back-pressure regulator to the value required to 
achieve the flow rates specified by the manufacturer. Inject the zero-
and the high-range calibration gases and adjust the analyzer calibration 
to provide the proper responses. Inject the low-and mid-range gases and 
record the responses of the measurement system. The calibration and 
linearity of the system are acceptable if the responses for all four 
gases are within 5 percent of the respective gas values. If the 
performance of the system is not acceptable, repair or adjust the system 
and repeat the linearity check. Conduct a calibration and linearity 
check after assembling the analysis system and after a major change is 
made to the system.
    7.2 Systems Drift Checks. Select the calibration gas that most 
closely approximates the concentration of the diluted captured emissions 
for conducting the drift checks. Introduce the zero and calibration 
gases at the calibration valve assembly, and verify that the appropriate 
gas flow rate and pressure are present at the FIA. Record the 
measurement system responses to the zero and calibration gases. The 
performance of the system is acceptable if the difference between the 
drift check measurement and the value obtained in section 7.1 is less 
than 3 percent of the span value. Alternatively, recalibrate the FIA as 
in section 7.1 and report the results using both sets of calibration 
data (i.e., data determined prior to the test period and data determined 
following the test period). The data that results in the lowest CE value 
shall be reported as the results for the test run. Conduct the system 
drift check at the end of each run.
    7.3 Determination of Dilution Factor. Inject the dilution check gas 
into the measurement system before the dilution system and record the 
response. Calculate the dilution factor using Equation 204C-3.
    7.4 System Check. Inject the high-range calibration gas at the inlet 
to the sampling probe while the dilution air is turned off. Record the 
response. The performance of the system is acceptable if the measurement 
system response is within 5 percent of the value obtained in section 7.1 
for the high-range calibration gas. Conduct a system check before and 
after each test run.

                              8. Procedure

    8.1 Determination of Volumetric Flow Rate of Captured Emissions
    8.1.1 Locate all points where emissions are captured from the 
affected facility. Using Method 1, determine the sampling points. Be 
sure to check each site for cyclonic or swirling flow.
    8.2.2 Measure the velocity at each sampling site at least once every 
hour during each sampling run using Method 2 or 2A.
    8.2 Determination of VOC Content of Captured Emissions
    8.2.1 Analysis Duration. Measure the VOC responses at each captured 
emissions point during the entire test run or, if applicable, while the 
process is operating. If there are multiple captured emissions 
locations, design a sampling system to allow a single FIA to be used to 
determine the VOC responses at all sampling locations.
    8.2.2 Gas VOC Concentration.
    8.2.2.1 Assemble the sample train as shown in Figure 204C-1. 
Calibrate the FIA according to the procedure in section 7.1.
    8.2.2.2 Set the dilution ratio and determine the dilution factor 
according to the procedure in section 7.3.
    8.2.2.3 Conduct a system check according to the procedure in section 
7.4.
    8.2.2.4 Install the sample probe so that the probe is centrally 
located in the stack, pipe, or duct, and is sealed tightly at the stack 
port connection.
    8.2.2.5 Inject zero gas at the calibration valve assembly. Measure 
the system response time as the time required for the system to reach 
the effluent concentration after the calibration valve has been returned 
to the effluent sampling position.
    8.2.2.6 Conduct a system check before, and a system drift check 
after, each sampling run according to the procedures in sections 7.2 and 
7.4. If the drift check following a run indicates unacceptable 
performance (see section 7.4), the run is not valid. Alternatively, 
recalibrate the FIA as in section 7.1 and report the results using both 
sets of calibration data (i.e., data determined prior to the test period 
and data determined following the test period). The data that results in 
the lowest CE value shall be reported as the results for the test run. 
The tester may elect to perform system drift checks during the run not 
to exceed one drift check per hour.
    8.2.2.7 Verify that the sample lines, filter, and pump temperatures 
are 120 5 [deg]C.
    8.2.2.8 Begin sampling at the start of the test period and continue 
to sample during the entire run. Record the starting and ending times 
and any required process information as appropriate. If multiple 
captured emission locations are sampled using a single FIA, sample at 
each location for the same amount of time (e.g., 2 min.) and continue to 
switch from one location to another for the entire test run. Be sure 
that total sampling time at each location is the same at the end of the 
test run. Collect at least four separate measurements from each sample 
point during each hour of testing. Disregard the measurements at each 
sampling

[[Page 455]]

location until two times the response time of the measurement system has 
elapsed. Continue sampling for at least 1 minute and record the 
concentration measurements.
    8.2.3 Background Concentration.

    Note: Not applicable when the building is used as the temporary 
total enclosure (TTE).

    8.2.3.1 Locate all natural draft openings (NDO's) of the TTE. A 
sampling point shall be at the center of each NDO, unless otherwise 
approved by the Administrator. If there are more than six NDO's, choose 
six sampling points evenly spaced among the NDO's.
    8.2.3.2 Assemble the sample train as shown in Figure 204C-2. 
Calibrate the FIA and conduct a system check according to the procedures 
in sections 7.1 and 7.4.
    8.2.3.3 Position the probe at the sampling location.
    8.2.3.4 Determine the response time, conduct the system check, and 
sample according to the procedures described in sections 8.2.2.4 through 
8.2.2.8.
    8.2.4 Alternative Procedure. The direct interface sampling and 
analysis procedure described in section 7.2 of Method 18 may be used to 
determine the gas VOC concentration. The system must be designed to 
collect and analyze at least one sample every 10 minutes. If the 
alternative procedure is used to determine the VOC concentration of the 
captured emissions, it must also be used to determine the VOC 
concentration of the uncaptured emissions.

                    9. Data Analysis and Calculations

    9.1 Nomenclature.

Ai=area of NDO i, ft\2\.
AN=total area of all NDO's in the enclosure, ft\2\.
CA = actual concentration of the dilution check gas, ppm 
propane.
CBi=corrected average VOC concentration of background 
emissions at point i, ppm propane.
CB=average background concentration, ppm propane.
CDH=average measured concentration for the drift check 
calibration gas, ppm propane.
CD0=average system drift check concentration for zero 
concentration gas, ppm propane.
CH=actual concentration of the drift check calibration gas, 
ppm propane.
Ci=uncorrected average background VOC concentration measured 
at point i, ppm propane.
Cj=uncorrected average VOC concentration measured at point j, 
ppm propane.
CM=measured concentration of the dilution check gas, ppm 
propane.
DF=dilution factor.
G=total VOC content of captured emissions, kg.
K1=1.830x10-6 kg/(m\3\-ppm).
n=number of measurement points.
QGj=average effluent volumetric flow rate corrected to 
standard conditions at captured emissions point j, m\3\/min.
[Theta]C=total duration of CE sampling run, min.
    9.2 Calculations.
    9.2.1 Total VOC Captured Emissions.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.010
    
    9.2.2 VOC Concentration of the Captured Emissions at Point j.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.011
    
    9.2.3 Dilution Factor.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.012
    
    9.2.4 Background VOC Concentration at Point i.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.013
    
    9.2.5 Average Background Concentration.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.014
    
    Note: If the concentration at each point is within 20 percent of the 
average concentration of all points, then use the arithmetic average.

                         10. Method Performance

    The measurement uncertainties are estimated for each captured or 
uncaptured emissions point as follows: QGj=5.5 percent and CGj= 5 
percent. Based on these numbers, the probable uncertainty for G is 
estimated at about 7.4 percent.

                              11. Diagrams

[[Page 456]]

[GRAPHIC] [TIFF OMITTED] TR16JN97.029


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[GRAPHIC] [TIFF OMITTED] TR16JN97.030

 Method 204D--Volatile Organic Compounds Emissions in Uncaptured Stream 
                     From Temporary Total Enclosure

                        1. Scope and Application

    1.1 Applicability. This procedure is applicable for determining the 
uncaptured volatile organic compounds (VOC) emissions from a temporary 
total enclosure (TTE). It is intended to be used as a segment in the 
development of liquid/gas or gas/gas protocols for determining VOC 
capture efficiency (CE) for surface coating and printing operations.

[[Page 458]]

    1.2 Principle. The amount of uncaptured VOC emissions (F) from the 
TTE is calculated as the sum of the products of the VOC content 
(CFj), the flow rate (QFj) from each uncaptured 
emissions point, and the sampling time ([Theta]F).
    1.3 Sampling Requirements. A CE test shall consist of at least three 
sampling runs. Each run shall cover at least one complete production 
cycle, but shall be at least 3 hours long. The sampling time for each 
run need not exceed 8 hours, even if the production cycle has not been 
completed. Alternative sampling times may be used with the approval of 
the Administrator.

                          2. Summary of Method

    A gas sample is extracted from the uncaptured exhaust duct of a TTE 
through a heated sample line and, if necessary, a glass fiber filter to 
a flame ionization analyzer (FIA).

                                3. Safety

    Because this procedure is often applied in highly explosive areas, 
caution and care should be exercised in choosing, installing, and using 
the appropriate equipment.

                        4. Equipment and Supplies

    Mention of trade names or company products does not constitute 
endorsement. All gas concentrations (percent, ppm) are by volume, unless 
otherwise noted.
    4.1 Gas VOC Concentration. A schematic of the measurement system is 
shown in Figure 204D-1. The main components are as follows:
    4.1.1 Sample Probe. Stainless steel or equivalent. The probe shall 
be heated to prevent VOC condensation.
    4.1.2 Calibration Valve Assembly. Three-way valve assembly at the 
outlet of the sample probe to direct the zero and calibration gases to 
the analyzer. Other methods, such as quick-connect lines, to route 
calibration gases to the outlet of the sample probe are acceptable.
    4.1.3 Sample Line. Stainless steel or Teflon tubing to transport the 
sample gas to the analyzer. The sample line must be heated to prevent 
condensation.
    4.1.4 Sample Pump. A leak-free pump, to pull the sample gas through 
the system at a flow rate sufficient to minimize the response time of 
the measurement system. The components of the pump that contact the gas 
stream shall be constructed of stainless steel or Teflon. The sample 
pump must be heated to prevent condensation.
    4.1.5 Sample Flow Rate Control. A sample flow rate control valve and 
rotameter, or equivalent, to maintain a constant sampling rate within 10 
percent. The flow control valve and rotameter must be heated to prevent 
condensation. A control valve may also be located on the sample pump 
bypass loop to assist in controlling the sample pressure and flow rate.
    4.1.6 Sample Gas Manifold. Capable of diverting a portion of the 
sample gas stream to the FIA, and the remainder to the bypass discharge 
vent. The manifold components shall be constructed of stainless steel or 
Teflon. If emissions are to be measured at multiple locations, the 
measurement system shall be designed to use separate sampling probes, 
lines, and pumps for each measurement location and a common sample gas 
manifold and FIA. The sample gas manifold and connecting lines to the 
FIA must be heated to prevent condensation.
    4.1.7 Organic Concentration Analyzer. An FIA with a span value of 
1.5 times the expected concentration as propane; however, other span 
values may be used if it can be demonstrated to the Administrator's 
satisfaction that they would provide more accurate measurements. The 
system shall be capable of meeting or exceeding the following 
specifications:
    4.1.7.1 Zero Drift. Less than 3.0 percent of 
the span value.
    4.1.7.2 Calibration Drift. Less than 3.0 
percent of the span value.
    4.1.7.3 Calibration Error. Less than 5.0 
percent of the calibration gas value.
    4.1.7.4 Response Time. Less than 30 seconds.
    4.1.8 Integrator/Data Acquisition System. An analog or digital 
device or computerized data acquisition system used to integrate the FIA 
response or compute the average response and record measurement data. 
The minimum data sampling frequency for computing average or integrated 
values is one measurement value every 5 seconds. The device shall be 
capable of recording average values at least once per minute.
    4.2 Uncaptured Emissions Volumetric Flow Rate.
    4.2.1 Method 2 or 2A Apparatus. For determining volumetric flow 
rate.
    4.2.2 Method 3 Apparatus and Reagents. For determining molecular 
weight of the gas stream. An estimate of the molecular weight of the gas 
stream may be used if approved by the Administrator.
    4.2.3 Method 4 Apparatus and Reagents. For determining moisture 
content, if necessary.
    4.3 Temporary Total Enclosure. The criteria for designing an 
acceptable TTE are specified in Method 204.

                        5. Reagents and Standards

    5.1 Calibration and Other Gases. Gases used for calibration, fuel, 
and combustion air (if required) are contained in compressed gas 
cylinders. All calibration gases shall be traceable to National 
Institute of Standards and Technology standards and shall be certified 
by the manufacturer to 1 percent of

[[Page 459]]

the tag value. Additionally, the manufacturer of the cylinder should 
provide a recommended shelf life for each calibration gas cylinder over 
which the concentration does not change more than 2 percent from the certified value. For calibration gas 
values not generally available, dilution systems calibrated using Method 
205 may be used. Alternative methods for preparing calibration gas 
mixtures may be used with the approval of the Administrator.
    5.1.1 Fuel. The FIA manufacturer's recommended fuel should be used. 
A 40 percent H2/60 percent He or 40 percent H2/60 
percent N2 gas mixture is recommended to avoid an oxygen 
synergism effect that reportedly occurs when oxygen concentration varies 
significantly from a mean value. Other mixtures may be used provided the 
tester can demonstrate to the Administrator that there is no oxygen 
synergism effect.
    5.1.2 Carrier Gas. High purity air with less than 1 ppm of organic 
material (as propane or carbon equivalent) or less than 0.1 percent of 
the span value, whichever is greater.
    5.1.3 FIA Linearity Calibration Gases. Low-, mid-, and high-range 
gas mixture standards with nominal propane concentrations of 20-30, 45-
55, and 70-80 percent of the span value in air, respectively. Other 
calibration values and other span values may be used if it can be shown 
to the Administrator's satisfaction that equally accurate measurements 
would be achieved.
    5.2 Particulate Filter. An in-stack or an out-of-stack glass fiber 
filter is recommended if exhaust gas particulate loading is significant. 
An out-of-stack filter must be heated to prevent any condensation unless 
it can be demonstrated that no condensation occurs.

                           6. Quality Control

    6.1 Required instrument quality control parameters are found in the 
following sections:
    6.1.1 The FIA system must be calibrated as specified in section 7.1.
    6.1.2 The system drift check must be performed as specified in 
section 7.2.
    6.1.3 The system check must be conducted as specified in section 
7.3.
    6.2 Audits.
    6.2.1 Analysis Audit Procedure. Immediately before each test, 
analyze an audit cylinder as described in section 7.2. The analysis 
audit must agree with the audit cylinder concentration within 10 
percent.
    6.2.2 Audit Samples and Audit Sample Availability. Audit samples 
will be supplied only to enforcement agencies for compliance tests. The 
availability of audit samples may be obtained by writing: Source Test 
Audit Coordinator (STAC) (MD-77B) Quality Assurance Division, 
Atmospheric Research and Exposure Assessment Laboratory, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711 or by 
calling the STAC at (919) 541-7834. The request for the audit sample 
must be made at least 30 days prior to the scheduled compliance sample 
analysis.
    6.2.3 Audit Results. Calculate the audit sample concentration 
according to the calculation procedure described in the audit 
instructions included with the audit sample. Fill in the audit sample 
concentration and the analyst's name on the audit response form included 
with the audit instructions. Send one copy to the EPA Regional Office or 
the appropriate enforcement agency, and a second copy to the STAC. The 
EPA Regional Office or the appropriate enforcement agency will report 
the results of the audit to the laboratory being audited. Include this 
response with the results of the compliance samples in relevant reports 
to the EPA Regional Office or the appropriate enforcement agency.

                   7. Calibration and Standardization

    7.1 FIA Calibration and Linearity Check. Make necessary adjustments 
to the air and fuel supplies for the FIA and ignite the burner. Allow 
the FIA to warm up for the period recommended by the manufacturer. 
Inject a calibration gas into the measurement system and adjust the 
back-pressure regulator to the value required to achieve the flow rates 
specified by the manufacturer. Inject the zero-and the high-range 
calibration gases and adjust the analyzer calibration to provide the 
proper responses. Inject the low-and mid-range gases and record the 
responses of the measurement system. The calibration and linearity of 
the system are acceptable if the responses for all four gases are within 
5 percent of the respective gas values. If the performance of the system 
is not acceptable, repair or adjust the system and repeat the linearity 
check. Conduct a calibration and linearity check after assembling the 
analysis system and after a major change is made to the system.
    7.2 Systems Drift Checks. Select the calibration gas concentration 
that most closely approximates that of the uncaptured gas emissions 
concentration to conduct the drift checks. Introduce the zero and 
calibration gases at the calibration valve assembly and verify that the 
appropriate gas flow rate and pressure are present at the FIA. Record 
the measurement system responses to the zero and calibration gases. The 
performance of the system is acceptable if the difference between the 
drift check measurement and the value obtained in section 7.1 is less 
than 3 percent of the span value. Alternatively, recalibrate the FIA as 
in section 7.1 and report the results using both sets of calibration 
data (i.e., data determined prior to the test period and data determined 
following the test period). The data that results in the

[[Page 460]]

lowest CE value shall be reported as the results for the test run. 
Conduct a system drift check at the end of each run.
    7.3 System Check. Inject the high-range calibration gas at the inlet 
of the sampling probe and record the response. The performance of the 
system is acceptable if the measurement system response is within 5 
percent of the value obtained in section 7.1 for the high-range 
calibration gas. Conduct a system check before each test run.

                              8. Procedure

    8.1 Determination of Volumetric Flow Rate of Uncaptured Emissions
    8.1.1 Locate all points where uncaptured emissions are exhausted 
from the TTE. Using Method 1, determine the sampling points. Be sure to 
check each site for cyclonic or swirling flow.
    8.1.2 Measure the velocity at each sampling site at least once every 
hour during each sampling run using Method 2 or 2A.
    8.2 Determination of VOC Content of Uncaptured Emissions.
    8.2.1 Analysis Duration. Measure the VOC responses at each 
uncaptured emission point during the entire test run or, if applicable, 
while the process is operating. If there are multiple emission 
locations, design a sampling system to allow a single FIA to be used to 
determine the VOC responses at all sampling locations.
    8.2.2 Gas VOC Concentration.
    8.2.2.1 Assemble the sample train as shown in Figure 204D-1. 
Calibrate the FIA and conduct a system check according to the procedures 
in sections 7.1 and 7.3, respectively.
    8.2.2.2 Install the sample probe so that the probe is centrally 
located in the stack, pipe, or duct, and is sealed tightly at the stack 
port connection.
    8.2.2.3 Inject zero gas at the calibration valve assembly. Allow the 
measurement system response to reach zero. Measure the system response 
time as the time required for the system to reach the effluent 
concentration after the calibration valve has been returned to the 
effluent sampling position.
    8.2.2.4 Conduct a system check before, and a system drift check 
after, each sampling run according to the procedures in sections 7.2 and 
7.3. If the drift check following a run indicates unacceptable 
performance (see section 7.3), the run is not valid. Alternatively, 
recalibrate the FIA as in section 7.1 and report the results using both 
sets of calibration data (i.e., data determined prior to the test period 
and data determined following the test period). The data that results in 
the lowest CE value shall be reported as the results for the test run. 
The tester may elect to perform system drift checks during the run not 
to exceed one drift check per hour.
    8.2.2.5 Verify that the sample lines, filter, and pump temperatures 
are 120 5 [deg]C.
    8.2.2.6 Begin sampling at the start of the test period and continue 
to sample during the entire run. Record the starting and ending times 
and any required process information, as appropriate. If multiple 
emission locations are sampled using a single FIA, sample at each 
location for the same amount of time (e.g., 2 min.) and continue to 
switch from one location to another for the entire test run. Be sure 
that total sampling time at each location is the same at the end of the 
test run. Collect at least four separate measurements from each sample 
point during each hour of testing. Disregard the response measurements 
at each sampling location until 2 times the response time of the 
measurement system has elapsed. Continue sampling for at least 1 minute 
and record the concentration measurements.
    8.2.3 Background Concentration.
    8.2.3.1 Locate all natural draft openings (NDO's) of the TTE. A 
sampling point shall be at the center of each NDO, unless otherwise 
approved by the Administrator. If there are more than six NDO's, choose 
six sampling points evenly spaced among the NDO's.
    8.2.3.2 Assemble the sample train as shown in Figure 204D-2. 
Calibrate the FIA and conduct a system check according to the procedures 
in sections 7.1 and 7.3.
    8.2.3.3 Position the probe at the sampling location.
    8.2.3.4 Determine the response time, conduct the system check, and 
sample according to the procedures described in sections 8.2.2.3 through 
8.2.2.6.
    8.2.4 Alternative Procedure. The direct interface sampling and 
analysis procedure described in section 7.2 of Method 18 may be used to 
determine the gas VOC concentration. The system must be designed to 
collect and analyze at least one sample every 10 minutes. If the 
alternative procedure is used to determine the VOC concentration of the 
uncaptured emissions in a gas/gas protocol, it must also be used to 
determine the VOC concentration of the captured emissions. If a tester 
wishes to conduct a liquid/gas protocol using a gas chromatograph, the 
tester must use Method 204F for the liquid steam. A gas chromatograph is 
not an acceptable alternative to the FIA in Method 204A.

                    9. Data Analysis and Calculations

    9.1 Nomenclature.
Ai=area of NDO i, ft\2\.
AN=total area of all NDO's in the enclosure, ft\2\.
CBi=corrected average VOC concentration of background 
emissions at point i, ppm propane.
CB=average background concentration, ppm propane.
CDH=average measured concentration for the drift check 
calibration gas, ppm propane.

[[Page 461]]

CD0=average system drift check concentration for zero 
concentration gas, ppm propane.
CFj=corrected average VOC concentration of uncaptured 
emissions at point j, ppm propane.
CH=actual concentration of the drift check calibration gas, 
ppm propane.
Ci=uncorrected average background VOC concentration at point 
i, ppm propane.
Cj=uncorrected average VOC concentration measured at point j, 
ppm propane.
F=total VOC content of uncaptured emissions, kg.
K1=1.830x10-6 kg/(m\3\-ppm).
n=number of measurement points.
QFj=average effluent volumetric flow rate corrected to 
standard conditions at uncaptured emissions point j, m\3\/min.
[Theta]F=total duration of uncaptured emissions sampling run, 
min.
    9.2 Calculations.
    9.2.1 Total Uncaptured VOC Emissions.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.015
    
    9.2.2 VOC Concentration of the Uncaptured Emissions at Point j.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.016
    
    9.2.3 Background VOC Concentration at Point i.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.017
    
    9.2.4 Average Background Concentration.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.018
    
    Note: If the concentration at each point is within 20 percent of the 
average concentration of all points, use the arithmetic average.

                         10. Method Performance

    The measurement uncertainties are estimated for each uncaptured 
emission point as follows: QFj=5.5 
percent and CFj=5.0 percent. Based on 
these numbers, the probable uncertainty for F is estimated at about 
7.4 percent.

                              11. Diagrams

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[GRAPHIC] [TIFF OMITTED] TR16JN97.031


[[Page 463]]


[GRAPHIC] [TIFF OMITTED] TR16JN97.032


[[Page 464]]



 Method 204E--Volatile Organic Compounds Emissions in Uncaptured Stream 
                         From Building Enclosure

                        1. Scope and Application

    1.1 Applicability. This procedure is applicable for determining the 
uncaptured volatile organic compounds (VOC) emissions from a building 
enclosure (BE). It is intended to be used in the development of liquid/
gas or gas/gas protocols for determining VOC capture efficiency (CE) for 
surface coating and printing operations.
    1.2 Principle. The total amount of uncaptured VOC emissions 
(FB) from the BE is calculated as the sum of the products of 
the VOC content (CFj) of each uncaptured emissions point, the 
flow rate (QFj) at each uncaptured emissions point, and time 
([Theta]F).
    1.3 Sampling Requirements. A CE test shall consist of at least three 
sampling runs. Each run shall cover at least one complete production 
cycle, but shall be at least 3 hours long. The sampling time for each 
run need not exceed 8 hours, even if the production cycle has not been 
completed. Alternative sampling times may be used with the approval of 
the Administrator.

                          2. Summary of Method

    A gas sample is extracted from the uncaptured exhaust duct of a BE 
through a heated sample line and, if necessary, a glass fiber filter to 
a flame ionization analyzer (FIA).

                                3. Safety

    Because this procedure is often applied in highly explosive areas, 
caution and care should be exercised in choosing, installing, and using 
the appropriate equipment.

                        4. Equipment and Supplies

    Mention of trade names or company products does not constitute 
endorsement. All gas concentrations (percent, ppm) are by volume, unless 
otherwise noted.
    4.1 Gas VOC Concentration. A schematic of the measurement system is 
shown in Figure 204E-1. The main components are as follows:
    4.1.1 Sample Probe. Stainless steel or equivalent. The probe shall 
be heated to prevent VOC condensation.
    4.1.2 Calibration Valve Assembly. Three-way valve assembly at the 
outlet of the sample probe to direct the zero and calibration gases to 
the analyzer. Other methods, such as quick-connect lines, to route 
calibration gases to the outlet of the sample probe are acceptable.
    4.1.3 Sample Line. Stainless steel or Teflon tubing to transport the 
sample gas to the analyzer. The sample line must be heated to prevent 
condensation.
    4.1.4 Sample Pump. A leak-free pump, to pull the sample gas through 
the system at a flow rate sufficient to minimize the response time of 
the measurement system. The components of the pump that contact the gas 
stream shall be constructed of stainless steel or Teflon. The sample 
pump must be heated to prevent condensation.
    4.1.5 Sample Flow Rate Control. A sample flow rate control valve and 
rotameter, or equivalent, to maintain a constant sampling rate within 10 
percent. The flow rate control valve and rotameter must be heated to 
prevent condensation. A control valve may also be located on the sample 
pump bypass loop to assist in controlling the sample pressure and flow 
rate.
    4.1.6 Sample Gas Manifold. Capable of diverting a portion of the 
sample gas stream to the FIA, and the remainder to the bypass discharge 
vent. The manifold components shall be constructed of stainless steel or 
Teflon. If emissions are to be measured at multiple locations, the 
measurement system shall be designed to use separate sampling probes, 
lines, and pumps for each measurement location, and a common sample gas 
manifold and FIA. The sample gas manifold must be heated to prevent 
condensation.
    4.1.7 Organic Concentration Analyzer. An FIA with a span value of 
1.5 times the expected concentration as propane; however, other span 
values may be used if it can be demonstrated to the Administrator's 
satisfaction that they would provide equally accurate measurements. The 
system shall be capable of meeting or exceeding the following 
specifications:
    4.1.7.1 Zero Drift. Less than 3.0 percent of 
the span value.
    4.1.7.2 Calibration Drift. Less than 3.0 
percent of the span value.
    4.1.7.3 Calibration Error. Less than 5.0 
percent of the calibration gas value.
    4.1.7.4 Response Time. Less than 30 seconds.
    4.1.8 Integrator/Data Acquisition System. An analog or digital 
device or computerized data acquisition system used to integrate the FIA 
response or compute the average response and record measurement data. 
The minimum data sampling frequency for computing average or integrated 
values is one measurement value every 5 seconds. The device shall be 
capable of recording average values at least once per minute.
    4.2 Uncaptured Emissions Volumetric Flow Rate.
    4.2.1 Flow Direction Indicators. Any means of indicating inward or 
outward flow, such as light plastic film or paper streamers, smoke 
tubes, filaments, and sensory perception.
    4.2.2 Method 2 or 2A Apparatus. For determining volumetric flow 
rate. Anemometers or similar devices calibrated according to the 
manufacturer's instructions may be used

[[Page 465]]

when low velocities are present. Vane anemometers (Young-maximum 
response propeller), specialized pitots with electronic manometers 
(e.g., Shortridge Instruments Inc., Airdata Multimeter 860) are 
commercially available with measurement thresholds of 15 and 8 mpm (50 
and 25 fpm), respectively.
    4.2.3 Method 3 Apparatus and Reagents. For determining molecular 
weight of the gas stream. An estimate of the molecular weight of the gas 
stream may be used if approved by the Administrator.
    4.2.4 Method 4 Apparatus and Reagents. For determining moisture 
content, if necessary.
    4.3 Building Enclosure. The criteria for an acceptable BE are 
specified in Method 204.

                        5. Reagents and Standards

    5.1 Calibration and Other Gases. Gases used for calibration, fuel, 
and combustion air (if required) are contained in compressed gas 
cylinders. All calibration gases shall be traceable to National 
Institute of Standards and Technology standards and shall be certified 
by the manufacturer to 1 percent of the tag value. 
Additionally, the manufacturer of the cylinder should provide a 
recommended shelf life for each calibration gas cylinder over which the 
concentration does not change more than 2 percent 
from the certified value. For calibration gas values not generally 
available, dilution systems calibrated using Method 205 may be used. 
Alternative methods for preparing calibration gas mixtures may be used 
with the approval of the Administrator.
    5.1.1 Fuel. The FIA manufacturer's recommended fuel should be used. 
A 40 percent H2/60 percent He or 40 percent H2/60 
percent N2 gas mixture is recommended to avoid an oxygen 
synergism effect that reportedly occurs when oxygen concentration varies 
significantly from a mean value. Other mixtures may be used provided the 
tester can demonstrate to the Administrator that there is no oxygen 
synergism effect.
    5.1.2 Carrier Gas. High purity air with less than 1 ppm of organic 
material (propane or carbon equivalent) or less than 0.1 percent of the 
span value, whichever is greater.
    5.1.3 FIA Linearity Calibration Gases. Low-, mid-, and high-range 
gas mixture standards with nominal propane concentrations of 20-30, 45-
55, and 70-80 percent of the span value in air, respectively. Other 
calibration values and other span values may be used if it can be shown 
to the Administrator's satisfaction that equally accurate measurements 
would be achieved.
    5.2 Particulate Filter. An in-stack or an out-of-stack glass fiber 
filter is recommended if exhaust gas particulate loading is significant. 
An out-of-stack filter must be heated to prevent any condensation unless 
it can be demonstrated that no condensation occurs.

                           6. Quality Control

    6.1 Required instrument quality control parameters are found in the 
following sections:
    6.1.1 The FIA system must be calibrated as specified in section 7.1.
    6.1.2 The system drift check must be performed as specified in 
section 7.2.
    6.1.3 The system check must be conducted as specified in section 
7.3.
    6.2 Audits.
    6.2.1 Analysis Audit Procedure. Immediately before each test, 
analyze an audit cylinder as described in section 7.2. The analysis 
audit must agree with the audit cylinder concentration within 10 
percent.
    6.2.2 Audit Samples and Audit Sample Availability. Audit samples 
will be supplied only to enforcement agencies for compliance tests. The 
availability of audit samples may be obtained by writing: Source Test 
Audit Coordinator (STAC) (MD-77B), Quality Assurance Division, 
Atmospheric Research and Exposure Assessment Laboratory, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711 or by 
calling the STAC at (919) 541-7834. The request for the audit sample 
must be made at least 30 days prior to the scheduled compliance sample 
analysis.
    6.2.3 Audit Results. Calculate the audit sample concentration 
according to the calculation procedure described in the audit 
instructions included with the audit sample. Fill in the audit sample 
concentration and the analyst's name on the audit response form included 
with the audit instructions. Send one copy to the EPA Regional Office or 
the appropriate enforcement agency, and a second copy to the STAC. The 
EPA Regional Office or the appropriate enforcement agency will report 
the results of the audit to the laboratory being audited. Include this 
response with the results of the compliance samples in relevant reports 
to the EPA Regional Office or the appropriate enforcement agency.

                   7. Calibration and Standardization

    7.1 FIA Calibration and Linearity Check. Make necessary adjustments 
to the air and fuel supplies for the FIA and ignite the burner. Allow 
the FIA to warm up for the period recommended by the manufacturer. 
Inject a calibration gas into the measurement system and adjust the 
back-pressure regulator to the value required to achieve the flow rates 
specified by the manufacturer. Inject the zero-and the high-range 
calibration gases, and adjust the analyzer calibration to provide the 
proper responses. Inject the low-and mid-range gases and record the 
responses of the measurement system. The

[[Page 466]]

calibration and linearity of the system are acceptable if the responses 
for all four gases are within 5 percent of the respective gas values. If 
the performance of the system is not acceptable, repair or adjust the 
system and repeat the linearity check. Conduct a calibration and 
linearity check after assembling the analysis system and after a major 
change is made to the system.
    7.2 Systems Drift Checks. Select the calibration gas that most 
closely approximates the concentration of the captured emissions for 
conducting the drift checks. Introduce the zero and calibration gases at 
the calibration valve assembly and verify that the appropriate gas flow 
rate and pressure are present at the FIA. Record the measurement system 
responses to the zero and calibration gases. The performance of the 
system is acceptable if the difference between the drift check 
measurement and the value obtained in section 7.1 is less than 3 percent 
of the span value. Alternatively, recalibrate the FIA as in section 7.1 
and report the results using both sets of calibration data (i.e., data 
determined prior to the test period and data determined following the 
test period). The data that results in the lowest CE value shall be 
reported as the results for the test run. Conduct a system drift check 
at the end of each run.
    7.3 System Check. Inject the high-range calibration gas at the inlet 
of the sampling probe and record the response. The performance of the 
system is acceptable if the measurement system response is within 5 
percent of the value obtained in section 7.1 for the high-range 
calibration gas. Conduct a system check before each test run.

                              8. Procedure

    8.1 Preliminary Determinations. The following points are considered 
exhaust points and should be measured for volumetric flow rates and VOC 
concentrations:
    8.1.1 Forced Draft Openings. Any opening in the facility with an 
exhaust fan. Determine the volumetric flow rate according to Method 2.
    8.1.2 Roof Openings. Any openings in the roof of a facility which 
does not contain fans are considered to be exhaust points. Determine 
volumetric flow rate from these openings. Use the appropriate velocity 
measurement devices (e.g., propeller anemometers).
    8.2 Determination of Flow Rates.
    8.2.1 Measure the volumetric flow rate at all locations identified 
as exhaust points in section 8.1. Divide each exhaust opening into nine 
equal areas for rectangular openings and into eight equal areas for 
circular openings.
    8.2.2 Measure the velocity at each site at least once every hour 
during each sampling run using Method 2 or 2A, if applicable, or using 
the low velocity instruments in section 4.2.2.
    8.3 Determination of VOC Content of Uncaptured Emissions.
    8.3.1 Analysis Duration. Measure the VOC responses at each 
uncaptured emissions point during the entire test run or, if applicable, 
while the process is operating. If there are multiple emissions 
locations, design a sampling system to allow a single FIA to be used to 
determine the VOC responses at all sampling locations.
    8.3.2 Gas VOC Concentration.
    8.3.2.1 Assemble the sample train as shown in Figure 204E-1. 
Calibrate the FIA and conduct a system check according to the procedures 
in sections 7.1 and 7.3, respectively.
    8.3.2.2 Install the sample probe so that the probe is centrally 
located in the stack, pipe, or duct, and is sealed tightly at the stack 
port connection.
    8.3.2.3 Inject zero gas at the calibration valve assembly. Allow the 
measurement system response to reach zero. Measure the system response 
time as the time required for the system to reach the effluent 
concentration after the calibration valve has been returned to the 
effluent sampling position.
    8.3.2.4 Conduct a system check before, and a system drift check 
after, each sampling run according to the procedures in sections 7.2 and 
7.3. If the drift check following a run indicates unacceptable 
performance (see section 7.3), the run is not valid. Alternatively, 
recalibrate the FIA as in section 7.1 and report the results using both 
sets of calibration data (i.e., data determined prior to the test period 
and data determined following the test period). The data that results in 
the lowest CE value shall be reported as the results for the test run. 
The tester may elect to perform drift checks during the run, not to 
exceed one drift check per hour.
    8.3.2.5 Verify that the sample lines, filter, and pump temperatures 
are 120 5 [deg]C.
    8.3.2.6 Begin sampling at the start of the test period and continue 
to sample during the entire run. Record the starting and ending times, 
and any required process information, as appropriate. If multiple 
emission locations are sampled using a single FIA, sample at each 
location for the same amount of time (e.g., 2 minutes) and continue to 
switch from one location to another for the entire test run. Be sure 
that total sampling time at each location is the same at the end of the 
test run. Collect at least four separate measurements from each sample 
point during each hour of testing. Disregard the response measurements 
at each sampling location until 2 times the response time of the 
measurement system has elapsed. Continue sampling for at least 1 minute, 
and record the concentration measurements.
    8.4 Alternative Procedure. The direct interface sampling and 
analysis procedure described in section 7.2 of Method 18 may be

[[Page 467]]

used to determine the gas VOC concentration. The system must be designed 
to collect and analyze at least one sample every 10 minutes. If the 
alternative procedure is used to determine the VOC concentration of the 
uncaptured emissions in a gas/gas protocol, it must also be used to 
determine the VOC concentration of the captured emissions. If a tester 
wishes to conduct a liquid/gas protocol using a gas chromatograph, the 
tester must use Method 204F for the liquid steam. A gas chromatograph is 
not an acceptable alternative to the FIA in Method 204A.

                    9. Data Analysis and Calculations

    9.1 Nomenclature.
CDH=average measured concentration for the drift check 
calibration gas, ppm propane.
CD0=average system drift check concentration for zero 
concentration gas, ppm propane.
CFj=corrected average VOC concentration of uncaptured 
emissions at point j, ppm propane.
CH=actual concentration of the drift check calibration gas, 
ppm propane.
Cj=uncorrected average VOC concentration measured at point j, 
ppm propane.
FB=total VOC content of uncaptured emissions from the 
building, kg.
K1=1.830 x 10-6 kg/(m\3\-ppm).
n=number of measurement points.
QFj=average effluent volumetric flow rate corrected to 
standard conditions at uncaptured emissions point j, m\3\/min.
[Theta]F=total duration of CE sampling run, min.

    9.2 Calculations
    9.2.1 Total VOC Uncaptured Emissions from the Building.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.019
    
    9.2.2 VOC Concentration of the Uncaptured Emissions at Point j.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.020
    
                         10. Method Performance

    The measurement uncertainties are estimated for each uncaptured 
emissions point as follows: QFj=10.0 
percent and CFj=5.0 percent. Based on 
these numbers, the probable uncertainty for FB is estimated 
at about 11.2 percent.

                              11. Diagrams

[[Page 468]]

[GRAPHIC] [TIFF OMITTED] TR16JN97.033

 Method 204F--Volatile Organic Compounds Content in Liquid Input Stream 
                         (Distillation Approach)

                             1. Introduction

    1.1 Applicability. This procedure is applicable for determining the 
input of volatile organic compounds (VOC). It is intended to be used as 
a segment in the development of liquid/gas protocols for determining VOC 
capture efficiency (CE) for surface coating and printing operations.
    1.2 Principle. The amount of VOC introduced to the process (L) is 
the sum of the products of the weight (W) of each VOC containing liquid 
(ink, paint, solvent, etc.) used,

[[Page 469]]

and its VOC content (V), corrected for a response factor (RF).
    1.3 Sampling Requirements. A CE test shall consist of at least three 
sampling runs. Each run shall cover at least one complete production 
cycle, but shall be at least 3 hours long. The sampling time for each 
run need not exceed 8 hours, even if the production cycle has not been 
completed. Alternative sampling times may be used with the approval of 
the Administrator.

                          2. Summary of Method

    A sample of each coating used is distilled to separate the VOC 
fraction. The distillate is used to prepare a known standard for 
analysis by a flame ionization analyzer (FIA), calibrated against 
propane, to determine its RF.

                                3. Safety

    Because this procedure is often applied in highly explosive areas, 
caution and care should be exercised in choosing, installing, and using 
the appropriate equipment.

                        4. Equipment and Supplies

    Mention of trade names or company products does not constitute 
endorsement. All gas concentrations (percent, ppm) are by volume, unless 
otherwise noted.
    4.1 Liquid Weight.
    4.1.1 Balances/Digital Scales. To weigh drums of VOC containing 
liquids to within 0.2 lb or 1.0 percent of the total weight of VOC 
liquid used.
    4.1.2 Volume Measurement Apparatus (Alternative). Volume meters, 
flow meters, density measurement equipment, etc., as needed to achieve 
the same accuracy as direct weight measurements.
    4.2 Response Factor Determination (FIA Technique). The VOC 
distillation system and Tedlar gas bag generation system apparatuses are 
shown in Figures 204F-1 and 204F-2, respectively. The following 
equipment is required:
    4.2.1 Sample Collection Can. An appropriately-sized metal can to be 
used to collect VOC containing materials. The can must be constructed in 
such a way that it can be grounded to the coating container.
    4.2.2 Needle Valves. To control gas flow.
    4.2.3 Regulators. For calibration, dilution, and sweep gas 
cylinders.
    4.2.4 Tubing and Fittings. Teflon and stainless steel tubing and 
fittings with diameters, lengths, and sizes determined by the connection 
requirements of the equipment.
    4.2.5 Thermometer. Capable of measuring the temperature of the hot 
water and oil baths to within 1 [deg]C.
    4.2.6 Analytical Balance. To measure 0.01 mg.
    4.2.7 Microliter Syringe. 10-[micro]l size.
    4.2.8 Vacuum Gauge or Manometer. 0- to 760-mm (0- to 30-in.) Hg U-
Tube manometer or vacuum gauge.
    4.2.9 Hot Oil Bath, With Stirring Hot Plate. Capable of heating and 
maintaining a distillation vessel at 110 3 [deg]C.
    4.2.10 Ice Water Bath. To cool the distillation flask.
    4.2.11 Vacuum/Water Aspirator. A device capable of drawing a vacuum 
to within 20 mm Hg from absolute.
    4.2.12 Rotary Evaporator System. Complete with folded inner coil, 
vertical style condenser, rotary speed control, and Teflon sweep gas 
delivery tube with valved inlet. Buchi Rotavapor or equivalent.
    4.2.13 Ethylene Glycol Cooling/Circulating Bath. Capable of 
maintaining the condenser coil fluid at -10 [deg]C.
    4.2.14 Dry Gas Meter (DGM). Capable of measuring the dilution gas 
volume within 2 percent, calibrated with a spirometer or bubble meter, 
and equipped with a temperature gauge capable of measuring temperature 
within 3 [deg]C.
    4.2.15 Activated Charcoal/Mole Sieve Trap. To remove any trace level 
of organics picked up from the DGM.
    4.2.16 Gas Coil Heater. Sufficient length of 0.125-inch stainless 
steel tubing to allow heating of the dilution gas to near the water bath 
temperature before entering the volatilization vessel.
    4.2.17 Water Bath, With Stirring Hot Plate. Capable of heating and 
maintaining a volatilization vessel and coil heater at a temperature of 
100 5 [deg]C.
    4.2.18 Volatilization Vessel. 50-ml midget impinger fitted with a 
septum top and loosely filled with glass wool to increase the 
volatilization surface.
    4.2.19 Tedlar Gas Bag. Capable of holding 30 liters of gas, flushed 
clean with zero air, leak tested, and evacuated.
    4.2.20 Organic Concentration Analyzer. An FIA with a span value of 
1.5 times the expected concentration as propane; however, other span 
values may be used if it can be demonstrated that they would provide 
equally accurate measurements. The FIA instrument should be the same 
instrument used in the gaseous analyses adjusted with the same fuel, 
combustion air, and sample back-pressure (flow rate) settings. The 
system shall be capable of meeting or exceeding the following 
specifications:
    4.2.20.1 Zero Drift. Less than 3.0 percent of 
the span value.
    4.2.20.2 Calibration Drift. Less than 3.0 
percent of the span value.
    4.2.20.3 Calibration Error. Less than 3.0 
percent of the calibration gas value.
    4.2.21 Integrator/Data Acquisition System. An analog or digital 
device or computerized data acquisition system used to integrate the FIA 
response or compute the average response and record measurement data.

[[Page 470]]

The minimum data sampling frequency for computing average or integrated 
value is one measurement value every 5 seconds. The device shall be 
capable of recording average values at least once per minute.
    4.2.22 Chart Recorder (Optional). A chart recorder or similar device 
is recommended to provide a continuous analog display of the measurement 
results during the liquid sample analysis.

                        5. Reagents and Standards

    5.1 Zero Air. High purity air with less than 1 ppm of organic 
material (as propane) or less than 0.1 percent of the span value, 
whichever is greater. Used to supply dilution air for making the Tedlar 
bag gas samples.
    5.2 THC Free N2. High purity N2 with less than 
1 ppm THC. Used as sweep gas in the rotary evaporator system.
    5.3 Calibration and Other Gases. Gases used for calibration, fuel, 
and combustion air (if required) are contained in compressed gas 
cylinders. All calibration gases shall be traceable to National 
Institute of Standards and Technology standards and shall be certified 
by the manufacturer to 1 percent of the tag value. 
Additionally, the manufacturer of the cylinder should provide a 
recommended shelf life for each calibration gas cylinder over which the 
concentration does not change more than 2 percent 
from the certified value. For calibration gas values not generally 
available, dilution systems calibrated using Method 205 may be used. 
Alternative methods for preparing calibration gas mixtures may be used 
with the approval of the Administrator.
    5.3.1 Fuel. The FIA manufacturer's recommended fuel should be used. 
A 40 percent H2/60 percent He, or 40 percent H2/60 
percent N2 mixture is recommended to avoid fuels with oxygen 
to avoid an oxygen synergism effect that reportedly occurs when oxygen 
concentration varies significantly from a mean value. Other mixtures may 
be used provided the tester can demonstrate to the Administrator that 
there is no oxygen synergism effect.
    5.3.2 Combustion Air. High purity air with less than 1 ppm of 
organic material (as propane) or less than 0.1 percent of the span 
value, whichever is greater.
    5.3.3 FIA Linearity Calibration Gases. Low-, mid-, and high-range 
gas mixture standards with nominal propane concentration of 20-30, 45-
55, and 70-80 percent of the span value in air, respectively. Other 
calibration values and other span values may be used if it can be shown 
that equally accurate measurements would be achieved.
    5.3.4 System Calibration Gas. Gas mixture standard containing 
propane in air, approximating the VOC concentration expected for the 
Tedlar gas bag samples.

                           6. Quality Control

    6.1 Required instrument quality control parameters are found in the 
following sections:
    6.1.1 The FIA system must be calibrated as specified in section 7.1.
    6.1.2 The system drift check must be performed as specified in 
section 7.2.
    6.2 Precision Control. A minimum of one sample in each batch must be 
distilled and analyzed in duplicate as a precision control. If the 
results of the two analyses differ by more than 10 
percent of the mean, then the system must be reevaluated and the entire 
batch must be redistilled and analyzed.
    6.3 Audits.
    6.3.1 Audit Procedure. Concurrently, analyze the audit sample and a 
set of compliance samples in the same manner to evaluate the technique 
of the analyst and the standards preparation. The same analyst, 
analytical reagents, and analytical system shall be used both for 
compliance samples and the EPA audit sample. If this condition is met, 
auditing of subsequent compliance analyses for the same enforcement 
agency within 30 days is not required. An audit sample set may not be 
used to validate different sets of compliance samples under the 
jurisdiction of different enforcement agencies, unless prior 
arrangements are made with both enforcement agencies.
    6.3.2 Audit Samples. Audit Sample Availability. Audit samples will 
be supplied only to enforcement agencies for compliance tests. The 
availability of audit samples may be obtained by writing: Source Test 
Audit Coordinator (STAC) (MD-77B), Quality Assurance Division, 
Atmospheric Research and Exposure Assessment Laboratory, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711 or by 
calling the STAC at (919) 541-7834. The request for the audit sample 
must be made at least 30 days prior to the scheduled compliance sample 
analysis.
    6.3.3 Audit Results. Calculate the audit sample concentration 
according to the calculation procedure described in the audit 
instructions included with the audit sample. Fill in the audit sample 
concentration and the analyst's name on the audit response form included 
with the audit instructions. Send one copy to the EPA Regional Office or 
the appropriate enforcement agency, and a second copy to the STAC. The 
EPA Regional Office or the appropriate enforcement agency will report 
the results of the audit to the laboratory being audited. Include this 
response with the results of the compliance samples in relevant reports 
to the EPA Regional Office or the appropriate enforcement agency.

[[Page 471]]

                   7. Calibration and Standardization

    7.1 FIA Calibration and Linearity Check. Make necessary adjustments 
to the air and fuel supplies for the FIA and ignite the burner. Allow 
the FIA to warm up for the period recommended by the manufacturer. 
Inject a calibration gas into the measurement system and adjust the 
back-pressure regulator to the value required to achieve the flow rates 
specified by the manufacturer. Inject the zero-and the high-range 
calibration gases and adjust the analyzer calibration to provide the 
proper responses. Inject the low-and mid-range gases and record the 
responses of the measurement system. The calibration and linearity of 
the system are acceptable if the responses for all four gases are within 
5 percent of the respective gas values. If the performance of the system 
is not acceptable, repair or adjust the system and repeat the linearity 
check. Conduct a calibration and linearity check after assembling the 
analysis system and after a major change is made to the system. A 
calibration curve consisting of zero gas and two calibration levels must 
be performed at the beginning and end of each batch of samples.
    7.2 Systems Drift Checks. After each sample, repeat the system 
calibration checks in section 7.1 before any adjustments to the FIA or 
measurement system are made. If the zero or calibration drift exceeds 
3 percent of the span value, discard the result 
and repeat the analysis. Alternatively, recalibrate the FIA as in 
section 7.1 and report the results using both sets of calibration data 
(i.e., data determined prior to the test period and data determined 
following the test period). The data that results in the lowest CE value 
shall be reported as the results for the test run.

                              8. Procedures

    8.1 Determination of Liquid Input Weight
    8.1.1 Weight Difference. Determine the amount of material introduced 
to the process as the weight difference of the feed material before and 
after each sampling run. In determining the total VOC containing liquid 
usage, account for: (a) The initial (beginning) VOC containing liquid 
mixture; (b) any solvent added during the test run; (c) any coating 
added during the test run; and (d) any residual VOC containing liquid 
mixture remaining at the end of the sample run.
    8.1.1.1 Identify all points where VOC containing liquids are 
introduced to the process. To obtain an accurate measurement of VOC 
containing liquids, start with an empty fountain (if applicable). After 
completing the run, drain the liquid in the fountain back into the 
liquid drum (if possible), and weigh the drum again. Weigh the VOC 
containing liquids to 0.5 percent of the total 
weight (full) or 1.0 percent of the total weight 
of VOC containing liquid used during the sample run, whichever is less. 
If the residual liquid cannot be returned to the drum, drain the 
fountain into a preweighed empty drum to determine the final weight of 
the liquid.
    8.1.1.2 If it is not possible to measure a single representative 
mixture, then weigh the various components separately (e.g., if solvent 
is added during the sampling run, weigh the solvent before it is added 
to the mixture). If a fresh drum of VOC containing liquid is needed 
during the run, then weigh both the empty drum and fresh drum.
    8.1.2 Volume Measurement (Alternative). If direct weight 
measurements are not feasible, the tester may use volume meters and flow 
rate meters (and density measurements) to determine the weight of 
liquids used if it can be demonstrated that the technique produces 
results equivalent to the direct weight measurements. If a single 
representative mixture cannot be measured, measure the components 
separately.
    8.2 Determination of VOC Content in Input Liquids
    8.2.1 Collection of Liquid Samples.
    8.2.1.1 Collect a 1-pint or larger sample of the VOC containing 
liquid mixture at each application location at the beginning and end of 
each test run. A separate sample should be taken of each VOC containing 
liquid added to the application mixture during the test run. If a fresh 
drum is needed during the sampling run, then obtain a sample from the 
fresh drum.
    8.2.1.2 When collecting the sample, ground the sample container to 
the coating drum. Fill the sample container as close to the rim as 
possible to minimize the amount of headspace.
    8.2.1.3 After the sample is collected, seal the container so the 
sample cannot leak out or evaporate.
    8.2.1.4 Label the container to identify clearly the contents.
    8.2.2 Distillation of VOC.
    8.2.2.1 Assemble the rotary evaporator as shown in Figure 204F-1.
    8.2.2.2 Leak check the rotary evaporation system by aspirating a 
vacuum of approximately 20 mm Hg from absolute. Close up the system and 
monitor the vacuum for approximately 1 minute. If the vacuum falls more 
than 25 mm Hg in 1 minute, repair leaks and repeat. Turn off the 
aspirator and vent vacuum.
    8.2.2.3 Deposit approximately 20 ml of sample (inks, paints, etc.) 
into the rotary evaporation distillation flask.
    8.2.2.4 Install the distillation flask on the rotary evaporator.
    8.2.2.5 Immerse the distillate collection flask into the ice water 
bath.
    8.2.2.6 Start rotating the distillation flask at a speed of 
approximately 30 rpm.
    8.2.2.7 Begin heating the vessel at a rate of 2 to 3 [deg]C per 
minute.

[[Page 472]]

    8.2.2.8 After the hot oil bath has reached a temperature of 50 
[deg]C or pressure is evident on the mercury manometer, turn on the 
aspirator and gradually apply a vacuum to the evaporator to within 20 mm 
Hg of absolute. Care should be taken to prevent material burping from 
the distillation flask.
    8.2.2.9 Continue heating until a temperature of 110 [deg]C is 
achieved and maintain this temperature for at least 2 minutes, or until 
the sample has dried in the distillation flask.
    8.2.2.10 Slowly introduce the N2 sweep gas through the 
purge tube and into the distillation flask, taking care to maintain a 
vacuum of approximately 400-mm Hg from absolute.
    8.2.2.11 Continue sweeping the remaining solvent VOC from the 
distillation flask and condenser assembly for 2 minutes, or until all 
traces of condensed solvent are gone from the vessel. Some distillate 
may remain in the still head. This will not affect solvent recovery 
ratios.
    8.2.2.12 Release the vacuum, disassemble the apparatus and transfer 
the distillate to a labeled, sealed vial.
    8.2.3 Preparation of VOC standard bag sample.
    8.2.3.1 Assemble the bag sample generation system as shown in Figure 
204F-2 and bring the water bath up to near boiling temperature.
    8.2.3.2 Inflate the Tedlar bag and perform a leak check on the bag.
    8.2.3.3 Evacuate the bag and close the bag inlet valve.
    8.2.3.4 Record the current barometric pressure.
    8.2.3.5 Record the starting reading on the dry gas meter, open the 
bag inlet valve, and start the dilution zero air flowing into the Tedlar 
bag at approximately 2 liters per minute.
    8.2.3.6 The bag sample VOC concentration should be similar to the 
gaseous VOC concentration measured in the gas streams. The amount of 
liquid VOC required can be approximated using equations in section 9.2. 
Using Equation 204F-4, calculate CVOC by assuming RF is 1.0 
and selecting the desired gas concentration in terms of propane, 
CC3. Assuming BV is 20 liters, ML, the 
approximate amount of liquid to be used to prepare the bag gas sample, 
can be calculated using Equation 204F-2.
    8.2.3.7 Quickly withdraw an aliquot of the approximate amount 
calculated in section 8.2.3.6 from the distillate vial with the 
microliter syringe and record its weight from the analytical balance to 
the nearest 0.01 mg.
    8.2.3.8 Inject the contents of the syringe through the septum of the 
volatilization vessel into the glass wool inside the vessel.
    8.2.3.9 Reweigh and record the tare weight of the now empty syringe.
    8.2.3.10 Record the pressure and temperature of the dilution gas as 
it is passed through the dry gas meter.
    8.2.3.11 After approximately 20 liters of dilution gas have passed 
into the Tedlar bag, close the valve to the dilution air source and 
record the exact final reading on the dry gas meter.
    8.2.3.12 The gas bag is then analyzed by FIA within 1 hour of bag 
preparation in accordance with the procedure in section 8.2.4.
    8.2.4 Determination of VOC response factor.
    8.2.4.1 Start up the FIA instrument using the same settings as used 
for the gaseous VOC measurements.
    8.2.4.2 Perform the FIA analyzer calibration and linearity checks 
according to the procedure in section 7.1. Record the responses to each 
of the calibration gases and the back-pressure setting of the FIA.
    8.2.4.3 Connect the Tedlar bag sample to the FIA sample inlet and 
record the bag concentration in terms of propane. Continue the analyses 
until a steady reading is obtained for at least 30 seconds. Record the 
final reading and calculate the RF.
    8.2.5 Determination of coating VOC content as VOC (VIJ).
    8.2.5.1 Determine the VOC content of the coatings used in the 
process using EPA Method 24 or 24A as applicable.

                    9. Data Analysis and Calculations

    9.1. Nomenclature.
BV=Volume of bag sample volume, liters.
CC3=Concentration of bag sample as propane, mg/liter.
CVOC=Concentration of bag sample as VOC, mg/liter.
K=0.00183 mg propane/(liter-ppm propane)
L=Total VOC content of liquid input, kg propane.
ML=Mass of VOC liquid injected into the bag, mg.
MV=Volume of gas measured by DGM, liters.
PM=Absolute DGM gas pressure, mm Hg.
PSTD=Standard absolute pressure, 760 mm Hg.
RC3=FIA reading for bag gas sample, ppm propane.
RF=Response factor for VOC in liquid, weight VOC/weight propane.
RFJ=Response factor for VOC in liquid J, weight VOC/weight 
propane.
TM=DGM temperature, [deg]K.
TSTD=Standard absolute temperature, 293 [deg]K.
VIJ=Initial VOC weight fraction of VOC liquid J.
VFJ=Final VOC weight fraction of VOC liquid J.
VAJ=VOC weight fraction of VOC liquid J added during the run.
WIJ=Weight of VOC containing liquid J at beginning of run, 
kg.
WFJ=Weight of VOC containing liquid J at end of run, kg.

[[Page 473]]

WAJ=Weight of VOC containing liquid J added during the run, 
kg.
    9.2 Calculations.
    9.2.1 Bag sample volume.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.021
    
    9.2.2 Bag sample VOC concentration.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.022
    
    9.2.3 Bag sample VOC concentration as propane.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.023
    
    9.2.4 Response Factor.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.024
    
    9.2.5 Total VOC Content of the Input VOC Containing Liquid.
    [GRAPHIC] [TIFF OMITTED] TR16JN97.025
    
                              10. Diagrams

[[Page 474]]

[GRAPHIC] [TIFF OMITTED] TR16JN97.034


[[Page 475]]


[GRAPHIC] [TIFF OMITTED] TR16JN97.035


[[Page 476]]



 Method 205--Verification of Gas Dilution Systems for Field Instrument 
                              Calibrations

                             1. Introduction

    1.1 Applicability. A gas dilution system can provide known values of 
calibration gases through controlled dilution of high-level calibration 
gases with an appropriate dilution gas. The instrumental test methods in 
40 CFR part 60--e.g., Methods 3A, 6C, 7E, 10, 15, 16, 20, 25A and 25B--
require on-site, multi-point calibration using gases of known 
concentrations. A gas dilution system that produces known low-level 
calibration gases from high-level calibration gases, with a degree of 
confidence similar to that for Protocol \1\ gases, may be used for 
compliance tests in lieu of multiple calibration gases when the gas 
dilution system is demonstrated to meet the requirements of this method. 
The Administrator may also use a gas dilution system in order to produce 
a wide range of Cylinder Gas Audit concentrations when conducting 
performance specifications according to appendix F, 40 CFR part 60. As 
long as the acceptance criteria of this method are met, this method is 
applicable to gas dilution systems using any type of dilution 
technology, not solely the ones mentioned in this method.
    1.2 Principle. The gas dilution system shall be evaluated on one 
analyzer once during each field test. A precalibrated analyzer is 
chosen, at the discretion of the source owner or operator, to 
demonstrate that the gas dilution system produces predictable gas 
concentrations spanning a range of concentrations. After meeting the 
requirements of this method, the remaining analyzers may be calibrated 
with the dilution system in accordance to the requirements of the 
applicable method for the duration of the field test. In Methods 15 and 
16, 40 CFR part 60, appendix A, reactive compounds may be lost in the 
gas dilution system. Also, in Methods 25A and 25B, 40 CFR part 60, 
appendix A, calibration with target compounds other than propane is 
allowed. In these cases, a laboratory evaluation is required once per 
year in order to assure the Administrator that the system will dilute 
these reactive gases without significant loss.
    Note: The laboratory evaluation is required only if the source owner 
or operator plans to utilize the dilution system to prepare gases 
mentioned above as being reactive.

                            2. Specifications

    2.1 Gas Dilution System. The gas dilution system shall produce 
calibration gases whose measured values are within 2 percent of the predicted values. The predicted values 
are calculated based on the certified concentration of the supply gas 
(Protocol gases, when available, are recommended for their accuracy) and 
the gas flow rates (or dilution ratios) through the gas dilution system.
    2.1.1 The gas dilution system shall be recalibrated once per 
calendar year using NIST-traceable primary flow standards with an 
uncertainty <=0.25 percent. A label shall be affixed at all times to the 
gas dilution system listing the date of the most recent calibration, the 
due date for the next calibration, and the person or manufacturer who 
carried out the calibration. Follow the manufacturer's instructions for 
the operation and use of the gas dilution system. A copy of the 
manufacturer's instructions for the operation of the instrument, as well 
as the most recent recalibration documentation shall be made available 
for the Administrator's inspection upon request.
    2.1.2 Some manufacturers of mass flow controllers recommend that 
flow rates below 10 percent of flow controller capacity be avoided; 
check for this recommendation and follow the manufacturer's 
instructions. One study has indicated that silicone oil from a positive 
displacement pump produces an interference in SO2 analyzers 
utilizing ultraviolet fluorescence; follow laboratory procedures similar 
to those outlined in Section 3.1 in order to demonstrate the 
significance of any resulting effect on instrument performance.
    2.2 High-Level Supply Gas. An EPA Protocol calibration gas is 
recommended, due to its accuracy, as the high-level supply gas.
    2.3 Mid-Level Supply Gas. An EPA Protocol gas shall be used as an 
independent check of the dilution system. The concentration of the mid-
level supply gas shall be within 10 percent of one of the dilution 
levels tested in Section 3.2.

                          3. Performance Tests

    3.1 Laboratory Evaluation (Optional). If the gas dilution system is 
to be used to formulate calibration gases with reactive compounds (Test 
Methods 15, 16, and 25A/25B (only if using a calibration gas other than 
propane during the field test) in 40 CFR part 60, appendix A), a 
laboratory certification must be conducted once per calendar year for 
each reactive compound to be diluted. In the laboratory, carry out the 
procedures in Section 3.2 on the analyzer required in each respective 
test method to be laboratory certified (15, 16, or 25A and 25B for 
compounds other than propane). For each compound in which the gas 
dilution system meets the requirements in Section 3.2, the source must 
provide the laboratory certification data for the field test and in the 
test report.
    3.2 Field Evaluation (Required). The gas dilution system shall be 
evaluated at the test site with an analyzer or monitor chosen by the 
source owner or operator. It is recommended that the source owner or 
operator choose a precalibrated instrument with a

[[Page 477]]

high level of precision and accuracy for the purposes of this test. This 
method is not meant to replace the calibration requirements of test 
methods. In addition to the requirements in this method, all the 
calibration requirements of the applicable test method must also be met.
    3.2.1 Prepare the gas dilution system according to the 
manufacturer's instructions. Using the high-level supply gas, prepare, 
at a minimum, two dilutions within the range of each dilution device 
utilized in the dilution system (unless, as in critical orifice systems, 
each dilution device is used to make only one dilution; in that case, 
prepare one dilution for each dilution device). Dilution device in this 
method refers to each mass flow controller, critical orifice, capillary 
tube, positive displacement pump, or any other device which is used to 
achieve gas dilution.
    3.2.2 Calculate the predicted concentration for each of the 
dilutions based on the flow rates through the gas dilution system (or 
the dilution ratios) and the certified concentration of the high-level 
supply gas.
    3.2.3 Introduce each of the dilutions from Section 3.2.1 into the 
analyzer or monitor one at a time and determine the instrument response 
for each of the dilutions.
    3.2.4 Repeat the procedure in Section 3.2.3 two times, i.e., until 
three injections are made at each dilution level. Calculate the average 
instrument response for each triplicate injection at each dilution 
level. No single injection shall differ by more than 2 percent from the average instrument response for that 
dilution.
    3.2.5 For each level of dilution, calculate the difference between 
the average concentration output recorded by the analyzer and the 
predicted concentration calculated in Section 3.2.2. The average 
concentration output from the analyzer shall be within 2 percent of the predicted value.
    3.2.6 Introduce the mid-level supply gas directly into the analyzer, 
bypassing the gas dilution system. Repeat the procedure twice more, for 
a total of three mid-level supply gas injections. Calculate the average 
analyzer output concentration for the mid-level supply gas. The 
difference between the certified concentration of the mid-level supply 
gas and the average instrument response shall be within 2 percent.
    3.3 If the gas dilution system meets the criteria listed in Section 
3.2, the gas dilution system may be used throughout that field test. If 
the gas dilution system fails any of the criteria listed in Section 3.2, 
and the tester corrects the problem with the gas dilution system, the 
procedure in Section 3.2 must be repeated in its entirety and all the 
criteria in Section 3.2 must be met in order for the gas dilution system 
to be utilized in the test.

                              4. References

    1. ``EPA Traceability Protocol for Assay and Certification of 
Gaseous Calibration Standards,'' EPA-600/R93/224, Revised September 
1993.

[55 FR 14249, Apr. 17, 1990; 55 FR 24687, June 18, 1990, as amended at 
55 FR 37606, Sept. 12, 1990; 56 FR 6278, Feb. 15, 1991; 56 FR 65435, 
Dec. 17, 1991; 60 FR 28054, May 30, 1995; 62 FR 32502, June 16, 1997]

                  Appendixes N-O to Part 51 [Reserved]

     Appendix P to Part 51--Minimum Emission Monitoring Requirements

    1.0 Purpose. This appendix P sets forth the minimum requirements for 
continuous emission monitoring and recording that each State 
Implementation Plan must include in order to be approved under the 
provisions of 40 CFR 51.165(b). These requirements include the source 
categories to be affected; emission monitoring, recording, and reporting 
requirements for those sources; performance specifications for accuracy, 
reliability, and durability of acceptable monitoring systems; and 
techniques to convert emission data to units of the applicable State 
emission standard. Such data must be reported to the State as an 
indication of whether proper maintenance and operating procedures are 
being utilized by source operators to maintain emission levels at or 
below emission standards. Such data may be used directly or indirectly 
for compliance determination or any other purpose deemed appropriate by 
the State. Though the monitoring requirements are specified in detail, 
States are given some flexibility to resolve difficulties that may arise 
during the implementation of these regulations.
    1.1 Applicability. The State plan shall require the owner or 
operator of an emission source in a category listed in this appendix to: 
(1) Install, calibrate, operate, and maintain all monitoring equipment 
necessary for continuously monitoring the pollutants specified in this 
appendix for the applicable source category; and (2) complete the 
installation and performance tests of such equipment and begin 
monitoring and recording within 18 months of plan approval or 
promulgation. The source categories and the respective monitoring 
requirements are listed below.
    1.1.1 Fossil fuel-fired steam generators, as specified in paragraph 
2.1 of this appendix, shall be monitored for opacity, nitrogen oxides 
emissions, sulfur dioxide emissions, and oxygen or carbon dioxide.
    1.1.2 Fluid bed catalytic cracking unit catalyst regenerators, as 
specified in paragraph 2.4 of this appendix, shall be monitored for 
opacity.

[[Page 478]]

    1.1.3 Sulfuric acid plants, as specified in paragraph 2.3 of this 
appendix, shall be monitored for sulfur dioxide emissions.
    1.1.4 Nitric acid plants, as specified in paragraph 2.2 of this 
appendix, shall be monitored for nitrogen oxides emissions.
    1.2 Exemptions. The States may include provisions within their 
regulations to grant exemptions from the monitoring requirements of 
paragraph 1.1 of this appendix for any source which is:
    1.2.1 Subject to a new source performance standard promulgated in 40 
CFR part 60 pursuant to section 111 of the Clean Air Act; or
    1.2.2 not subject to an applicable emission standard of an approved 
plan; or
    1.2.3 scheduled for retirement within 5 years after inclusion of 
monitoring requirements for the source in appendix P, provided that 
adequate evidence and guarantees are provided that clearly show that the 
source will cease operations prior to such date.
    1.3 Extensions. States may allow reasonable extensions of the time 
provided for installation of monitors for facilities unable to meet the 
prescribed timeframe (i.e., 18 months from plan approval or 
promulgation) provided the owner or operator of such facility 
demonstrates that good faith efforts have been made to obtain and 
install such devices within such prescribed timeframe.
    1.4 Monitoring System Malfunction. The State plan may provide a 
temporary exemption from the monitoring and reporting requirements of 
this appendix during any period of monitoring system malfunction, 
provided that the source owner or operator shows, to the satisfaction of 
the State, that the malfunction was unavoidable and is being repaired as 
expeditiously as practicable.
    2.0 Minimum Monitoring Requirement. States must, as a minimum, 
require the sources listed in paragraph 1.1 of this appendix to meet the 
following basic requirements.
    2.1 Fossil fuel-fired steam generators. Each fossil fuel-fired steam 
generator, except as provided in the following subparagraphs, with an 
annual average capacity factor of greater than 30 percent, as reported 
to the Federal Power Commission for calendar year 1974, or as otherwise 
demonstrated to the State by the owner or operator, shall conform with 
the following monitoring requirements when such facility is subject to 
an emission standard of an applicable plan for the pollutant in 
question.
    2.1.1 A continuous monitoring system for the measurement of opacity 
which meets the performance specifications of paragraph 3.1.1 of this 
appendix shall be installed, calibrated, maintained, and operated in 
accordance with the procedures of this appendix by the owner or operator 
of any such steam generator of greater than 250 million BTU per hour 
heat input except where:
    2.1.1.1 gaseous fuel is the only fuel burned, or
    2.1.1.2 oil or a mixture of gas and oil are the only fuels burned 
and the source is able to comply with the applicable particulate matter 
and opacity regulations without utilization of particulate matter 
collection equipment, and where the source has never been found, through 
any administrative or judicial proceedings, to be in violation of any 
visible emission standard of the applicable plan.
    2.1.2 A continuous monitoring system for the measurement of sulfur 
dioxide which meets the performance specifications of paragraph 3.1.3 of 
this appendix shall be installed, calibrated, maintained, and operated 
on any fossil fuel-fired steam generator of greater than 250 million BTU 
per hour heat input which has installed sulfur dioxide pollutant control 
equipment.
    2.1.3 A continuous monitoring system for the measurement of nitrogen 
oxides which meets the performance specification of paragraph 3.1.2 of 
this appendix shall be installed, calibrated, maintained, and operated 
on fossil fuel-fired steam generators of greater than 1000 million BTU 
per hour heat input when such facility is located in an Air Quality 
Control Region where the Administrator has specifically determined that 
a control strategy for nitrogen dioxide is necessary to attain the 
national standards, unless the source owner or operator demonstrates 
during source compliance tests as required by the State that such a 
source emits nitrogen oxides at levels 30 percent or more below the 
emission standard within the applicable plan.
    2.1.4 A continuous monitoring system for the measurement of the 
percent oxygen or carbon dioxide which meets the performance 
specifications of paragraphs 3.1.4 or 3.1.5 of this appendix shall be 
installed, calibrated, operated, and maintained on fossil fuel-fired 
steam generators where measurements of oxygen or carbon dioxide in the 
flue gas are required to convert either sulfur dioxide or nitrogen 
oxides continuous emission monitoring data, or both, to units of the 
emission standard within the applicable plan.
    2.2 Nitric acid plants. Each nitric acid plant of greater than 300 
tons per day production capacity, the production capacity being 
expressed as 100 percent acid, located in an Air Quality Control Region 
where the Administrator has specifically determined that a control 
strategy for nitrogen dioxide is necessary to attain the national 
standard shall install, calibrate, maintain, and operate a continuous 
monitoring system for the measurement of nitrogen oxides which meets the 
performance specifications of paragraph 3.1.2 for each nitric acid 
producing facility within such plant.

[[Page 479]]

    2.3 Sulfuric acid plants. Each Sulfuric acid plant of greater than 
300 tons per day production capacity, the production being expressed as 
100 percent acid, shall install, calibrate, maintain and operate a 
continuous monitoring system for the measurement of sulfur dioxide which 
meets the performance specifications of paragraph 3.1.3 for each 
sulfuric acid producing facility within such plant.
    2.4 Fluid bed catalytic cracking unit catalyst regenerators at 
petroleum refineries. Each catalyst regenerator for fluid bed catalytic 
cracking units of greater than 20,000 barrels per day fresh feed 
capacity shall install, calibrate, maintain, and operate a continuous 
monitoring system for the measurement of opacity which meets the 
performance specifications of paragraph 3.1.1.
    3.0 Minimum specifications. All State plans shall require owners or 
operators of monitoring equipment installed to comply with this 
appendix, except as provided in paragraph 3.2, to demonstrate compliance 
with the following performance specifications.
    3.1 Performance specifications. The performance specifications set 
forth in appendix B of part 60 are incorporated herein by reference, and 
shall be used by States to determine acceptability of monitoring 
equipment installed pursuant to this appendix except that (1) where 
reference is made to the ``Administrator'' in appendix B, part 60, the 
term State should be inserted for the purpose of this appendix (e.g., in 
Performance Specification 1, 1.2, `` * * * monitoring systems subject to 
approval by the Administrator,'' should be interpreted as, ``* * * 
monitoring systems subject to approval by the State''), and (2) where 
reference is made to the ``Reference Method'' in appendix B, part 60, 
the State may allow the use of either the State approved reference 
method or the Federally approved reference method as published in part 
60 of this chapter. The Performance Specifications to be used with each 
type of monitoring system are listed below.
    3.1.1 Continuous monitoring systems for measuring opacity shall 
comply with Performance Specification 1.
    3.1.2 Continuous monitoring systems for measuring nitrogen oxides 
shall comply with Performance Specification 2.
    3.1.3 Continuous monitoring systems for measuring sulfur dioxide 
shall comply with Performance Specification 2.
    3.1.4 Continuous monitoring systems for measuring oxygen shall 
comply with Performance Specification 3.
    3.1.5 Continuous monitoring systems for measuring carbon dioxide 
shall comply with Performance Specification 3.
    3.2 Exemptions. Any source which has purchased an emission 
monitoring system(s) prior to September 11, 1974, may be exempt from 
meeting such test procedures prescribed in appendix B of part 60 for a 
period not to exceed five years from plan approval or promulgation.
    3.3 Calibration Gases. For nitrogen oxides monitoring systems 
installed on fossil fuel-fired steam generators the pollutant gas used 
to prepare calibration gas mixtures (Section 2.1, Performance 
Specification 2, appendix B, part 60) shall be nitric oxide (NO). For 
nitrogen oxides monitoring systems, installed on nitric acid plants the 
pollutant gas used to prepare calibration gas mixtures (Section 2.1, 
Performance Specification 2, appendix B, part 60 of this chapter) shall 
be nitrogen dioxide (NO2). These gases shall also be used for 
daily checks under paragraph 3.7 of this appendix as applicable. For 
sulfur dioxide monitoring systems installed on fossil fuel-fired steam 
generators or sulfuric acid plants the pollutant gas used to prepare 
calibration gas mixtures (Section 2.1, Performance Specification 2, 
appendix B, part 60 of this chapter) shall be sulfur dioxide 
(SO2). Span and zero gases should be traceable to National 
Bureau of Standards reference gases whenever these reference gases are 
available. Every six months from date of manufacture, span and zero 
gases shall be reanalyzed by conducting triplicate analyses using the 
reference methods in appendix A, part 60 of this chapter as follows: for 
sulfur dioxide, use Reference Method 6; for nitrogen oxides, use 
Reference Method 7; and for carbon dioxide or oxygen, use Reference 
Method 3. The gases may be analyzed at less frequent intervals if longer 
shelf lives are guaranteed by the manufacturer.
    3.4 Cycling times. Cycling times include the total time a monitoring 
system requires to sample, analyze and record an emission measurement.
    3.4.1 Continuous monitoring systems for measuring opacity shall 
complete a minimum of one cycle of operation (sampling, analyzing, and 
data recording) for each successive 10-second period.
    3.4.2 Continuous monitoring systems for measuring oxides of 
nitrogen, carbon dioxide, oxygen, or sulfur dioxide shall complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period.
    3.5 Monitor location. State plans shall require all continuous 
monitoring systems or monitoring devices to be installed such that 
representative measurements of emissions or process parameters (i.e., 
oxygen, or carbon dioxide) from the affected facility are obtained. 
Additional guidance for location of continuous monitoring systems to 
obtain representative samples are contained in the applicable 
Performance Specifications of appendix B of part 60 of this chapter.
    3.6 Combined effluents. When the effluents from two or more affected 
facilities of similar design and operating characteristics are combined 
before being released to the atmosphere, the State plan may allow 
monitoring

[[Page 480]]

systems to be installed on the combined effluent. When the affected 
facilities are not of similar design and operating characteristics, or 
when the effluent from one affected facility is released to the 
atmosphere through more than one point, the State should establish 
alternate procedures to implement the intent of these requirements.
    3.7 Zero and drift. State plans shall require owners or operators of 
all continuous monitoring systems installed in accordance with the 
requirements of this appendix to record the zero and span drift in 
accordance with the method prescribed by the manufacturer of such 
instruments; to subject the instruments to the manufacturer's 
recommended zero and span check at least once daily unless the 
manufacturer has recommended adjustments at shorter intervals, in which 
case such recommendations shall be followed; to adjust the zero and span 
whenever the 24-hour zero drift or 24-hour calibration drift limits of 
the applicable performance specifications in appendix B of part 60 are 
exceeded; and to adjust continuous monitoring systems referenced by 
paragraph 3.2 of this appendix whenever the 24-hour zero drift or 24-
hour calibration drift exceed 10 percent of the emission standard.
    3.8 Span. Instrument span should be approximately 200 per cent of 
the expected instrument data display output corresponding to the 
emission standard for the source.
    3.9 Alternative procedures and requirements. In cases where States 
wish to utilize different, but equivalent, procedures and requirements 
for continuous monitoring systems, the State plan must provide a 
description of such alternative procedures for approval by the 
Administrator. Some examples of situations that may require alternatives 
follow:
    3.9.1 Alternative monitoring requirements to accommodate continuous 
monitoring systems that require corrections for stack moisture 
conditions (e.g., an instrument measuring steam generator SO2 
emissions on a wet basis could be used with an instrument measuring 
oxygen concentration on a dry basis if acceptable methods of measuring 
stack moisture conditions are used to allow accurate adjustments of the 
measured SO2 concentration to dry basis.)
    3.9.2 Alternative locations for installing continuous monitoring 
systems or monitoring devices when the owner or operator can demonstrate 
that installation at alternative locations will enable accurate and 
representative measurements.
    3.9.3 Alternative procedures for performing calibration checks 
(e.g., some instruments may demonstrate superior drift characteristics 
that require checking at less frequent intervals).
    3.9.4 Alternative monitoring requirements when the effluent from one 
affected facility or the combined effluent from two or more identical 
affected facilities is released to the atmosphere through more than one 
point (e.g., an extractive, gaseous monitoring system used at several 
points may be approved if the procedures recommended are suitable for 
generating accurate emission averages).
    3.9.5 Alternative continuous monitoring systems that do not meet the 
spectral response requirements in Performance Specification 1, appendix 
B of part 60, but adequately demonstrate a definite and consistent 
relationship between their measurements and the opacity measurements of 
a system complying with the requirements in Performance Specification 1. 
The State may require that such demonstration be performed for each 
affected facility.
    4.0 Minimum data requirements. The following paragraphs set forth 
the minimum data reporting requirements necessary to comply with Sec. 
51.214(d) and (e).
    4.1 The State plan shall require owners or operators of facilities 
required to install continuous monitoring systems to submit a written 
report of excess emissions for each calendar quarter and the nature and 
cause of the excess emissions, if known. The averaging period used for 
data reporting should be established by the State to correspond to the 
averaging period specified in the emission test method used to determine 
compliance with an emission standard for the pollutant/source category 
in question. The required report shall include, as a minimum, the data 
stipulated in this appendix.
    4.2 For opacity measurements, the summary shall consist of the 
magnitude in actual percent opacity of all one-minute (or such other 
time period deemed appropriate by the State) averages of opacity greater 
than the opacity standard in the applicable plan for each hour of 
operation of the facility. Average values may be obtained by integration 
over the averaging period or by arithmetically averaging a minimum of 
four equally spaced, instantaneous opacity measurements per minute. Any 
time period exempted shall be considered before determining the excess 
averages of opacity (e.g., whenever a regulation allows two minutes of 
opacity measurements in excess of the standard, the State shall require 
the source to report all opacity averages, in any one hour, in excess of 
the standard, minus the two-minute exemption). If more than one opacity 
standard applies, excess emissions data must be submitted in relation to 
all such standards.
    4.3 For gaseous measurements the summary shall consist of emission 
averages, in the units of the applicable standard, for each averaging 
period during which the applicable standard was exceeded.
    4.4 The date and time identifying each period during which the 
continuous monitoring system was inoperative, except for zero and

[[Page 481]]

span checks, and the nature of system repairs or adjustments shall be 
reported. The State may require proof of continuous monitoring system 
performance whenever system repairs or adjustments have been made.
    4.5 When no excess emissions have occurred and the continuous 
monitoring system(s) have not been inoperative, repaired, or adjusted, 
such information shall be included in the report.
    4.6 The State plan shall require owners or operators of affected 
facilities to maintain a file of all information reported in the 
quarterly summaries, and all other data collected either by the 
continuous monitoring system or as necessary to convert monitoring data 
to the units of the applicable standard for a minimum of two years from 
the date of collection of such data or submission of such summaries.
    5.0 Data Reduction. The State plan shall require owners or operators 
of affected facilities to use the following procedures for converting 
monitoring data to units of the standard where necessary.
    5.1 For fossil fuel-fired steam generators the following procedures 
shall be used to convert gaseous emission monitoring data in parts per 
million to g/million cal (lb/million BTU) where necessary:
    5.1.1 When the owner or operator of a fossil fuel-fired steam 
generator elects under paragraph 2.1.4 of this appendix to measure 
oxygen in the flue gases, the measurements of the pollutant 
concentration and oxygen concentration shall each be on a dry basis and 
the following conversion procedure used:

E = CF [20.9/20.9 - %O2]

    5.1.2 When the owner or operator elects under paragraph 2.1.4 of 
this appendix to measure carbon dioxide in the flue gases, the 
measurement of the pollutant concentration and the carbon dioxide 
concentration shall each be on a consistent basis (wet or dry) and the 
following conversion procedure used:

E = CFc (100 / %CO2)

    5.1.3 The values used in the equations under paragraph 5.1 are 
derived as follows:

E = pollutant emission, g/million cal (lb/million BTU),
C = pollutant concentration, g/dscm (lb/dscf), determined by multiplying 
the average concentration (ppm) for each hourly period by 
4.16x10-5 M g/dscm per ppm (2.64x10-9 M lb/dscf 
per ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-mole). M 
= 64 for sulfur dioxide and 46 for oxides of nitrogen.
%O2, %CO2 = Oxygen or carbon dioxide volume 
(expressed as percent) determined with equipment specified under 
paragraph 4.1.4 of this appendix,
F, Fc = a factor representing a ratio of the volume of dry 
flue gases generated to the calorific value of the fuel combusted (F), 
and a factor representing a ratio of the volume of carbon dioxide 
generated to the calorific value of the fuel combusted (Fc) 
respectively. Values of F and Fc are given in Sec. 60.45(f) 
of part 60, as applicable.

    5.2 For sulfuric acid plants the owner or operator shall:
    5.2.1 establish a conversion factor three times daily according to 
the procedures to Sec. 60.84(b) of this chapter;
    5.2.2 multiply the conversion factor by the average sulfur dioxide 
concentration in the flue gases to obtain average sulfur dioxide 
emissions in Kg/metric ton (lb/short ton); and
    5.2.3 report the average sulfur dioxide emission for each averaging 
period in excess of the applicable emission standard in the quarterly 
summary.
    5.3 For nitric acid plants the owner or operator shall:
    5.3.1 establish a conversion factor according to the procedures of 
Sec. 60.73(b) of this chapter;
    5.3.2 multiply the conversion factor by the average nitrogen oxides 
concentration in the flue gases to obtain the nitrogen oxides emissions 
in the units of the applicable standard;
    5.3.3 report the average nitrogen oxides emission for each averaging 
period in excess of the applicable emission standard, in the quarterly 
summary.
    5.4 Any State may allow data reporting or reduction procedures 
varying from those set forth in this appendix if the owner or operator 
of a source shows to the satisfaction of the State that his procedures 
are at least as accurate as those in this appendix. Such procedures may 
include but are not limited to, the following:
    5.4.1 Alternative procedures for computing emission averages that do 
not require integration of data (e.g., some facilities may demonstrate 
that the variability of their emissions is sufficiently small to allow 
accurate reduction of data based upon computing averages from equally 
spaced data points over the averaging period).
    5.4.2 Alternative methods of converting pollutant concentration 
measurements to the units of the emission standards.
    6.0 Special Consideration. The State plan may provide for approval, 
on a case-by-case basis, of alternative monitoring requirements 
different from the provisions of parts 1 through 5 of this appendix if 
the provisions of this appendix (i.e., the installation of a continuous 
emission monitoring system) cannot be implemented by a source due to 
physical plant limitations or extreme economic reasons. To make use of 
this provision, States must include in their plan specific criteria for 
determining those physical limitations or extreme economic situations

[[Page 482]]

to be considered by the State. In such cases, when the State exempts any 
source subject to this appendix by use of this provision from installing 
continuous emission monitoring systems, the State shall set forth 
alternative emission monitoring and reporting requirements (e.g., 
periodic manual stack tests) to satisfy the intent of these regulations. 
Examples of such special cases include, but are not limited to, the 
following:
    6.1 Alternative monitoring requirements may be prescribed when 
installation of a continuous monitoring system or monitoring device 
specified by this appendix would not provide accurate determinations of 
emissions (e.g., condensed, uncombined water vapor may prevent an 
accurate determination of opacity using commercially available 
continuous monitoring systems).
    6.2 Alternative monitoring requirements may be prescribed when the 
affected facility is infrequently operated (e.g., some affected 
facilities may operate less than one month per year).
    6.3 Alternative monitoring requirements may be prescribed when the 
State determines that the requirements of this appendix would impose an 
extreme economic burden on the source owner or operator.
    6.4 Alternative monitoring requirements may be prescribed when the 
State determines that monitoring systems prescribed by this appendix 
cannot be installed due to physical limitations at the facility.

[40 FR 46247, Oct. 6, 1975, as amended at 51 FR 40675, Nov. 7, 1986]

                  Appendixes Q-R to Part 51 [Reserved]

      Appendix S to Part 51--Emission Offset Interpretative Ruling

                             I. Introduction

    This appendix sets forth EPA's Interpretative Ruling on the 
preconstruction review requirements for stationary sources of air 
pollution (not including indirect sources) under 40 CFR subpart I and 
section 129 of the Clean Air Act Amendments of 1977, Public Law 95-95, 
(note under 42 U.S.C. 7502). A major new source or major modification 
which would locate in any area designated under section 107(d) of the 
Act as attainment or unclassifiable for ozone that is located in an 
ozone transport region or which would locate in an area designated in 40 
CFR part 81, subpart C, as nonattainment for a pollutant for which the 
source or modification would be major may be allowed to construct only 
if the stringent conditions set forth below are met. These conditions 
are designed to insure that the new source's emissions will be 
controlled to the greatest degree possible; that more than equivalent 
offsetting emission reductions (emission offsets) will be obtained from 
existing sources; and that there will be progress toward achievement of 
the NAAQS.
    For each area designated as exceeding a NAAQS (nonattainment area) 
under 40 CFR part 81, subpart C, or for any area designated under 
section 107(d) of the Act as attainment or unclassifiable for ozone that 
is located in an ozone transport region, this Interpretative Ruling will 
be superseded after June 30, 1979 (a) by preconstruction review 
provisions of the revised SIP, if the SIP meets the requirements of Part 
D, Title 1, of the Act; or (b) by a prohibition on construction under 
the applicable SIP and section 110(a)(2)(I) of the Act, if the SIP does 
not meet the requirements of Part D. The Ruling will remain in effect to 
the extent not superseded under the Act. This prohibition on major new 
source construction does not apply to a source whose permit to construct 
was applied for during a period when the SIP was in compliance with Part 
D, or before the deadline for having a revised SIP in effect that 
satisfies Part D.
    The requirement of this Ruling shall not apply to any major 
stationary source or major modification that was not subject to the 
Ruling as in effect on January 16, 1979, if the owner or operator:
    A. Obtained all final Federal, State, and local preconstruction 
approvals or permits necessary under the applicable State Implementation 
Plan before August 7, 1980;
    B. Commenced construction within 18 months from August 7, 1980, or 
any earlier time required under the applicable State Implementation 
Plan; and
    C. Did not discontinue construction for a period of 18 months or 
more and completed construction within a reasonable time.

     II. Initial Screening Analyses and Determination of Applicable 
                              Requirements

    A. Definitions--For the purposes of this Ruling:
    1. Stationary source means any building, structure, facility, or 
installation which emits or may emit any air pollutant subject to 
regulation under the Act.
    2. Building, structure, facility or installation means all of the 
pollutant-emitting activities which belong to the same industrial 
grouping, are located on one or more contiguous or adjacent properties, 
and are under the control of the same person (or persons under common 
control) except the activities of any vessel. Pollutant-emitting 
activities shall be considered as part of the same industrial grouping 
if they belong to the same ``Major Group'' (i.e., which have the same 
two digit code) as described in the Standard Industrial Classification 
Manual, 1972, as amended by the 1977 Supplement (U.S. Government 
Printing Office stock numbers 4101-0066 and 003-005-00176-0, 
respectively).

[[Page 483]]

    3. Potential to emit means the maximum capacity of a stationary 
source to emit a pollutant under its physical and operational design. 
Any physical or operational limitation on the capacity of the source to 
emit a pollutant, including air pollution control equipment and 
restrictions on hours of operation or on the type or amount of material 
combusted, stored, or processed, shall be treated as part of its design 
only if the limitation or the effect it would have on emissions is 
federally enforceable. Secondary emissions do not count in determining 
the potential to emit of a stationary source.
    4. (i) Major stationary source means:
    (a) Any stationary source of air pollutants which emits, or has the 
potential to emit, 100 tons per year or more of any pollutant subject to 
regulation under the Act, except that lower emissions thresholds shall 
apply in areas subject to subpart 2, subpart 3, or subpart 4 of part D, 
title I of the Act, according to paragraphs II.A.4(i)(a)(1) through (6) 
of this Ruling.
    (1) 50 tons per year of volatile organic compounds in any serious 
ozone nonattainment area.
    (2) 50 tons per year of volatile organic compounds in an area within 
an ozone transport region, except for any severe or extreme ozone 
nonattainment area.
    (3) 25 tons per year of volatile organic compounds in any severe 
ozone nonattainment area.
    (4) 10 tons per year of volatile organic compounds in any extreme 
ozone nonattainment area.
    (5) 50 tons per year of carbon monoxide in any serious nonattainment 
area for carbon monoxide, where stationary sources contribute 
significantly to carbon monoxide levels in the area (as determined under 
rules issued by the Administrator)
    (6) 70 tons per year of PM-10 in any serious nonattainment area for 
PM-10;
    (b) For the purposes of applying the requirements of paragraph IV.H 
of this Ruling to stationary sources of nitrogen oxides located in an 
ozone nonattainment area or in an ozone transport region, any stationary 
source which emits, or has the potential to emit, 100 tons per year or 
more of nitrogen oxides emissions, except that the emission thresholds 
in paragraphs II.A.4(i)(b)(1) through (6) of this Ruling apply in areas 
subject to subpart 2 of part D, title I of the Act.
    (1) 100 tons per year or more of nitrogen oxides in any ozone 
nonattainment area classified as marginal or moderate.
    (2) 100 tons per year or more of nitrogen oxides in any ozone 
nonattainment area classified as a transitional, submarginal, or 
incomplete or no data area, when such area is located in an ozone 
transport region.
    (3) 100 tons per year or more of nitrogen oxides in any area 
designated under section 107(d) of the Act as attainment or 
unclassifiable for ozone that is located in an ozone transport region.
    (4) 50 tons per year or more of nitrogen oxides in any serious 
nonattainment area for ozone.
    (5) 25 tons per year or more of nitrogen oxides in any severe 
nonattainment area for ozone.
    (6) 10 tons per year or more of nitrogen oxides in any extreme 
nonattainment area for ozone; or
    (c) Any physical change that would occur at a stationary source not 
qualifying under paragraph II.A.4(i)(a) or (b) of this Ruling as a major 
stationary source, if the change would constitute a major stationary 
source by itself.
    (ii) A major stationary source that is major for volatile organic 
compounds or nitrogen oxides is major for ozone.
    5. (i) Major modification means any physical change in or change in 
the method of operation of a major stationary source that would result 
in a significant net emissions increase of any pollutant subject to 
regulation under the Act.
    (ii) Any net emission increase that is considered significant for 
volatile organic compounds shall be considered significant for ozone.
    (iii) A physical change or change in the method of operation shall 
not include:
    (a) Routine maintenance, repair, and replacement;
    (b) Use of an alternative fuel or raw material by reason of an order 
under section 2 (a) and (b) of the Energy Supply and Environmental 
Coordination Act of 1974 (or any superseding legislation) or by reason 
of a natural gas curtailment plan pursuant to the Federal Power Act;
    (c) Use of an alternative fuel by reason of an order or rule under 
section 125 of the Act;
    (d) Use of an alternative fuel at a steam generating unit to the 
extent that the fuel is generated from municipal solid waste;
    (e) Use of an alternative fuel or raw material by a stationary 
source which:
    (1) The source was capable of accommodating before December 21, 
1976, unless such change would be prohibited under any federally 
enforceable permit condition which was established after December 21, 
1976, pursuant to 40 CFR 52.21 or under regulations approved pursuant to 
40 CFR subpart I or Sec. 51.166; or
    (2) The source is approved to use under any permit issued under this 
ruling;
    (f) An increase in the hours of operation or in the production rate, 
unless such change is prohibited under any federally enforceable permit 
condition which was established after December 21, 1976 pursuant to 40 
CFR 52.21 or under regulations approved pursuant to 40 CFR subpart I or 
Sec. 51.166;
    (g) Any change in ownership at a stationary source.

[[Page 484]]

    (iv) For the purpose of applying the requirements of paragraph IV.H 
of this Ruling to modifications at major stationary sources of nitrogen 
oxides located in ozone nonattainment areas or in ozone transport 
regions, whether or not subject with respect to ozone to subpart 2, part 
D, title I of the Act, any significant net emissions increase of 
nitrogen oxides is considered significant for ozone.
    (v) Any physical change in, or change in the method of operation of, 
a major stationary source of volatile organic compounds that results in 
any increase in emissions of volatile organic compounds from any 
discrete operation, emissions unit, or other pollutant emitting activity 
at the source shall be considered a significant net emissions increase 
and a major modification for ozone, if the major stationary source is 
located in an extreme ozone nonattainment area that is subject to 
subpart 2, part D, title I of the Act.
    6. (i) Net emissions increase means the amount by which the sum of 
the following exceeds zero:
    (a) Any increase in actual emissions from a particular physical 
change or change in the method of operation at a stationary source; and
    (b) Any other increases and decreases in actual emissions at the 
source that are contemporaneous with the particular change and are 
otherwise creditable.
    (ii) An increase or decrease in actual emissions is contemporaneous 
with the increase from the particular change only if it occurs between:
    (a) The date five years before construction on the particular change 
commences and
    (b) The date that the increase from the particular change occurs.
    (iii) An increase or decrease in actual emissions is creditable only 
if the Administrator has not relied on it in issuing a permit for the 
source under this Ruling which permit is in effect when the increase in 
actual emissions from the particular change occurs.
    (iv) An increase in actual emissions is creditable only to the 
extent that the new level of actual emissions exceeds the old level.
    (v) A decrease in actual emissions is creditable only to the extent 
that:
    (a) The old level of actual emissions or the old level of allowable 
emissions, whichever is lower, exceeds the new level of actual 
emissions;
    (b) It is federally enforceable at and after the time that actual 
construction on the particular change begins;
    (c) The reviewing authority has not relied on it in issuing any 
permit under regulations approved pursuant to 40 CFR 51.165;
    (d) It has approximately the same qualitative significance for 
public health and welfare as that attributed to the increase from the 
particular change.
    (vi) An increase that results from a physical change at a source 
occurs when the emissions unit on which construction occurred becomes 
operational and begins to emit a particular pollutant. Any replacement 
unit that requires shakedown becomes operational only after a reasonable 
shakedown period, not to exceed 180 days.
    7. Emissions unit means any part of a stationary source which emits 
or would have the potential to emit any pollutant subject to regulation 
under the Act.
    8. Secondary emissions means emissions which would occur as a result 
of the construction or operation of a major stationary source or major 
modification, but do not come from the major stationary source or major 
modification itself. For the purpose of this Ruling, secondary emissions 
must be specific, well defined, quantifiable, and impact the same 
general area as the stationary source or modification which causes the 
secondary emissions. Secondary emissions include emissions from any 
offsite support facility which would not be constructed or increase its 
emissions except as a result of the construction or operation of the 
major stationary source or major modification. Secondary emissions do 
not include any emissions which come directly from a mobile source, such 
as emissions from the tailpipe of a motor vehicle, from a train, or from 
a vessel.
    9. Fugitive emissions means those emissions which could not 
reasonably pass through a stack, chimney, vent, or other functionally 
equivalent opening.
    10. (i) Significant means, in reference to a net emissions increase 
or the potential of a source to emit any of the following pollutants, a 
rate of emissions that would equal or exceed any of the following rates:

                      Pollutant and Emissions Rate

Carbon monoxide: 100 tons per year (tpy)
Nitrogen oxides: 40 tpy
Sulfur dioxide: 40 tpy
Ozone: 40 tpy of volatile organic compounds or NOX
Lead: 0.6 tpy
Particulate matter: 25 tpy of particulate matter emissions
PM-10: 15 tpy PM-10

    (ii) Notwithstanding the significant emissions rate for ozone in 
paragraph II.A.10(i) of this Ruling, significant means, in reference to 
an emissions increase or a net emissions increase, any increase in 
actual emissions of volatile organic compounds that would result from 
any physical change in, or change in the method of operation of, a major 
stationary source locating in a serious or severe ozone nonattainment 
area that is subject to subpart 2, part D, title I of the Act, if such

[[Page 485]]

emissions increase of volatile organic compounds exceeds 25 tons per 
year.
    (iii) For the purposes of applying the requirements of paragraph 
IV.H of this Ruling to modifications at major stationary sources of 
nitrogen oxides located in an ozone nonattainment area or in an ozone 
transport region, the significant emission rates and other requirements 
for volatile organic compounds in paragraphs II.A.10(i), (ii), and (v) 
of this Ruling shall apply to nitrogen oxides emissions.
    (iv) Notwithstanding the significant emissions rate for carbon 
monoxide under paragraph II.A.10(i) of this Ruling, significant means, 
in reference to an emissions increase or a net emissions increase, any 
increase in actual emissions of carbon monoxide that would result from 
any physical change in, or change in the method of operation of, a major 
stationary source in a serious nonattainment area for carbon monoxide if 
such increase equals or exceeds 50 tons per year, provided the 
Administrator has determined that stationary sources contribute 
significantly to carbon monoxide levels in that area.
    (v) Notwithstanding the significant emissions rates for ozone under 
paragraphs II.A.10(i) and (ii) of this Ruling, any increase in actual 
emissions of volatile organic compounds from any emissions unit at a 
major stationary source of volatile organic compounds located in an 
extreme ozone nonattainment area that is subject to subpart 2, part D, 
title I of the Act shall be considered a significant net emissions 
increase.
    11. Allowable emissions means the emissions rate calculated using 
the maximum rated capacity of the source (unless the source is subject 
to federally enforceable limits which restrict the operating rate, or 
hours of operation, or both) and the most stringent of the following:
    (i) Applicable standards as set forth in 40 CFR parts 60 and 61;
    (ii) Any applicable State Implementation Plan emissions limitation, 
including those with a future compliance date; or
    (iii) The emissions rate specified as a federally enforceable permit 
condition, including those with a future compliance date.
    12. Federally enforceable means all limitations and conditions which 
are enforceable by the Administrator, including those requirements 
developed pursuant to 40 CFR parts 60 and 61, requirements within any 
applicable State implementation plan, any permit requirements 
established pursuant to 40 CFR 52.21 or under regulations approved 
pursuant to 40 CFR part 51, subpart I, including operating permits 
issued under an EPA-approved program that is incorporated into the State 
implementation plan and expressly requires adherence to any permit 
issued under such program.
    13. (i) Actual emissions means the actual rate of emissions of a 
pollutant from an emissions unit as determined in accordance with 
paragraphs 16. (ii) through (iv) of Section II.A. of this appendix.
    (ii) In general, actual emissions as of a particular date shall 
equal the average rate, in tons per year, at which the unit actually 
emitted the pollutant during a two-year period which precedes the 
particular date and which is representative of normal source operation. 
The reviewing authority shall allow the use of a different time period 
upon a determination that it is more representative of normal source 
operation. Actual emissions shall be calculated using the unit's actual 
operating hours, production rates, and types of materials processed, 
stored or combusted during the selected time period.
    (iii) The reviewing authority may presume that source-specific 
allowable emissions for the unit are equivalent to the actual emissions 
of the unit.
    (iv) For any emissions unit which has not begun normal operations on 
the particular date, actual emissions shall equal the potential to emit 
of the unit on that date.
    14. Construction means any physical change or change in the method 
of operation (including fabrication, erection, installation, demolition, 
or modification of an emissions unit) which would result in a change in 
actual emissions.
    15. Commence as applied to construction of a major stationary source 
or major modification means that the owner or operator has all necessary 
preconstruction approvals or permits and either has:
    (i) Begun, or caused to begin, a continuous program of actual on-
site construction of the source, to be completed within a reasonable 
time; or
    (ii) Entered into binding agreements or contractual obligations, 
which cannot be cancelled or modified without substantial loss to the 
owner or operator, to undertake a program of actual construction of the 
source to be completed within a reasonable time.
    16. Necessary preconstruction approvals or permits means those 
permits or approvals required under Federal air quality control laws and 
regulations and those air quality control laws and regulations which are 
part of the applicable State Implementation Plan.
    17. Begin actual construction means, in general, initiation of 
physical on-site construction activities on an emissions unit which are 
of a permanent nature. Such activities include, but are not limited to, 
installation of building supports and foundations, laying of underground 
pipework, and construction of permanent storage structures. With respect 
to a change in method of operating this term refers to those on-site 
activities other than preparatory activities which mark the initiation 
of the change.

[[Page 486]]

    18. Lowest achievable emission rate means, for any source, the more 
stringent rate of emissions based on the following:
    (i) The most stringent emissions limitation which is contained in 
the implementation plan of any State for such class or category of 
stationary source, unless the owner or operator of the proposed 
stationary source demonstrates that such limitations are not achievable; 
or
    (ii) The most stringent emissions limitation which is achieved in 
practice by such class or category of stationary source. This 
limitation, when applied to a modification, means the lowest achievable 
emissions rate for the new or modified emissions units within the 
stationary source. In no event shall the application of this term permit 
a proposed new or modified stationary source to emit any pollutant in 
excess of the amount allowable under applicable new source standards of 
performance.
    19. Resource recovery facility means any facility at which solid 
waste is processed for the purpose of extracting, converting to energy, 
or otherwise separating and preparing solid waste for reuse. Energy 
conversion facilities must utilize solid waste to provide more than 50 
percent of the heat input to be considered a resource recovery facility 
under this Ruling.
    20. Volatile organic compounds (VOC) is as defined in Sec. 
51.100(s) of this part.
    B. Review of all sources for emission limitation compliance. The 
reviewing authority must examine each proposed major new source and 
proposed major modification \1\ to determine if such a source will meet 
all applicable emission requirements in the SIP, any applicable new 
source performance standard in 40 CFR part 60, or any national emission 
standard for hazardous air pollutants in 40 CFR part 61. If the 
reviewing authority determines that the proposed major new source cannot 
meet the applicable emission requirements, the permit to construct must 
be denied.
---------------------------------------------------------------------------

    \1\ Hereafter the term source will be used to denote both any source 
and any modification.
---------------------------------------------------------------------------

    C. Review of specified sources for air quality impact. In addition, 
the reviewing authority must determine whether the major stationary 
source or major modification would be constructed in an area designated 
in 40 CFR 81.300 et seq. as nonattainment for a pollutant for which the 
stationary source or modification is major.
    D.-E. [Reserved]
    F. Fugitive emissions sources. Section IV. A. of this Ruling shall 
not apply to a source or modification that would be a major stationary 
source or major modification only if fugitive emissions, to the extent 
quantifiable, are considered in calculating the potential to emit of the 
stationary source or modification and the source does not belong to any 
of the following categories:
    (1) Coal cleaning plants (with thermal dryers);
    (2) Kraft pulp mills;
    (3) Portland cement plants;
    (4) Primary zinc smelters;
    (5) Iron and steel mills;
    (6) Primary aluminum ore reduction plants;
    (7) Primary copper smelters;
    (8) Municipal incinerators capable of charging more than 250 tons of 
refuse per day;
    (9) Hydrofluoric, sulfuric, or nitric acid plants;
    (10) Petroleum refineries;
    (11) Lime plants;
    (12) Phosphate rock processing plants;
    (13) Coke oven batteries;
    (14) Sulfur recovery plants;
    (15) Carbon black plants (furnace process);
    (16) Primary lead smelters;
    (17) Fuel conversion plants;
    (18) Sintering plants;
    (19) Secondary metal production plants;
    (20) Chemical process plants;
    (21) Fossil-fuel boilers (or combination thereof) totaling more than 
250 million British thermal units per hour heat input;
    (22) Petroleum storage and transfer units with a total storage 
capacity exceeding 300,000 barrels;
    (23) Taconite ore processing plants;
    (24) Glass fiber processing plants;
    (25) Charcoal production plants;
    (26) Fossil fuel-fired steam electric plants of more than 250 
million British thermal units per hour heat input;
    (27) Any other stationary source category which, as of August 7, 
1980, is being regulated under section 111 or 112 of the Act.
    G. Secondary emissions. Secondary emissions need not be considered 
in determining whether the emission rates in Section II.C. above would 
be exceeded. However, if a source is subject to this Ruling on the basis 
of the direct emissions from the source, the applicable conditions of 
this Ruling must also be met for secondary emissions. However, secondary 
emissions may be exempt from Conditions 1 and 2 of Section IV. Also, 
since EPA's authority to perform or require indirect source review 
relating to mobile sources regulated under Title II of the Act (motor 
vehicles and aircraft) has been restricted by statute, consideration of 
the indirect impacts of motor vehicles and aircraft traffic is not 
required under this Ruling.

[[Page 487]]

III. Sources Locating in Designated Clean or Unclassifiable Areas Which 
   Would Cause or Contribute to a Violation of a National Ambient Air 
                            Quality Standard

    A. This section applies only to major sources or major modifications 
which would locate in an area designated in 40 CFR 81.300 et seq. as 
attainment or unclassifiable in a State where EPA has not yet approved 
the State preconstruction review program required by 40 CFR 51.165(b), 
if the source or modification would exceed the following significance 
levels at any locality that does not meet the NAAQS:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                Averaging time (hours)
             Pollutant                       Annual         --------------------------------------------------------------------------------------------
                                                                       24                      8                      3                      1
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2................................  1.0 [micro]g/m\3\.....  5 [micro]g/m\3\.......  .....................  25 [micro]g/m\3\.....  .....................
TSP................................  1.0 [micro]g/m\3\.....  5 [micro]g/m\3\.......  .....................  .....................  .....................
NO2................................  1.0 [micro]g/m\3\.....  ......................  .....................  .....................  .....................
CO.................................  ......................  ......................  0.5 mg/m\3\..........  .....................  2 mg/m\3\.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    B. Sources to which this section applies must meet Conditions 1, 2, 
and 4 of Section IV.A. of this ruling.\2\ However, such sources may be 
exempt from Condition 3 of Section IV.A. of this ruling.
---------------------------------------------------------------------------

    \2\ The discussion in this paragraph is a proposal, but represents 
EPA's interim policy until final rulemaking is completed.
---------------------------------------------------------------------------

    C. Review of specified sources for air quality impact. For stable 
air pollutants (i.e. SO2, particulate matter and CO), the 
determination of whether a source will cause or contribute to a 
violation of an NAAQS generally should be made on a case-by-case basis 
as of the proposed new source's start-up date using the source's 
allowable emissions in an atmospheric simulation model (unless a source 
will clearly impact on a receptor which exceeds an NAAQS).
    For sources of nitrogen oxides, the initial determination of whether 
a source would cause or contribute to a violation of the NAAQS for 
NO2 should be made using an atmospheric simulation model 
assuming all the nitric oxide emitted is oxidized to NO2 by 
the time the plume reaches ground level. The initial concentration 
estimates may be adjusted if adequate data are available to account for 
the expected oxidation rate.
    For ozone, sources of volatile organic compounds, locating outside a 
designated ozone nonattainment area, will be presumed to have no 
significant impact on the designated nonattainment area. If ambient 
monitoring indicates that the area of source location is in fact 
nonattainment, then the source may be permitted under the provisions of 
any State plan adopted pursuant to section 110(a)(2)(D) of the Act until 
the area is designated nonattainment and a State Implementation Plan 
revision is approved. If no State plan pursuant to section 110(a)(2)(D) 
has been adopted and approved, then this Ruling shall apply.
    As noted above, the determination as to whether a source would cause 
or contribute to a violation of an NAAQS should be made as of the new 
source's start-up date. Therefore, if a designated nonattainment area is 
projected to be an attainment area as part of an approved SIP control 
strategy by the new source start-up date, offsets would not be required 
if the new source would not cause a new violation.
    D. Sources locating in clean areas, but would cause a new violating 
of an NAAQS. If the reviewing authority finds that the emissions from a 
proposed source would cause a new violation of an NAAQS, but would not 
contribute to an existing violation, approval may be granted only if 
both of the following conditions are met:
    Condition 1. The new source is required to meet a more stringent 
emission limitation \3\ and/or the control of existing sources below 
allowable levels is required so that the source will not cause a 
violation of any NAAQS.
---------------------------------------------------------------------------

    \3\ If the reviewing authority determines that technological or 
economic limitations on the application of measurement methodology to a 
particular class of sources would make the imposition of an enforceable 
numerical emission standard infeasible, the authority may instead 
prescribe a design, operational or equipment standard. In such cases, 
the reviewing authority shall make its best estimate as to the emission 
rate that will be achieved and must specify that rate in the required 
submission to EPA (see Part V). Any permits issued without an 
enforceable numerical emission standard must contain enforceable 
conditions which assure that the design characteristics or equipment 
will be properly maintained (or that the operational conditions will be 
properly performed) so as to continuously achieve the assumed degree of 
control. Such conditions shall be enforceable as emission limitations by 
private parties under section 304. Hereafter, the term emission 
limitation shall also include such design, operational, or equipment 
standards.

---------------------------------------------------------------------------

[[Page 488]]

    Condition 2. The new emission limitations for the new source as well 
as any existing sources affected must be enforceable in accordance with 
the mechanisms set forth in Section V of this appendix.

    IV. Sources That Would Locate in a Designated Nonattainment Area

    A. Conditions for approval. If the reviewing authority finds that 
the major stationary source or major modification would be constructed 
in an area designated in 40 CFR 81.300 et seq as nonattainment for a 
pollutant for which the stationary source or modification is major, 
approval may be granted only if the following conditions are met:
    Condition 1. The new source is required to meet an emission 
Limitation \4\ which specifies the lowest achievable emission rate for 
such source.
---------------------------------------------------------------------------

    \4\ If the reviewing authority determines that technological or 
economic limitations on the application of measurement methodology to a 
particular class of sources would make the imposition of an enforceable 
numerical emission standard infeasible, the authority may instead 
prescribe a design, operational or equipment standard. In such cases, 
the reviewing authority shall make its best estimate as to the emission 
rate that will be achieved and must specify that rate in the required 
submission to EPA (see Part V). Any permits issued without an 
enforceable numerical emission standard must contain enforceable 
conditions which assure that the design characteristics or equipment 
will be properly maintained (or that the operational conditions will be 
properly performed) so as to continuously achieve the assumed degree of 
control. Such conditions shall be enforceable as emission limitations by 
private parties under section 304. Hereafter, the term emission 
limitation shall also include such design, operational, or equipment 
standards.
---------------------------------------------------------------------------

    Condition 2. The applicant must certify that all existing major 
sources owned or operated by the applicant (or any entity controlling, 
controlled by, or under common control with the appplicant) in the same 
State as the proposed source are in compliance with all applicable 
emission limitations and standards under the Act (or are in compliance 
with an expeditious schedule which is Federally enforceable or contained 
in a court decree).
    Condition 3. Emission reductions (offsets) from existing sources \5\ 
in the area of the proposed source (whether or not under the same 
ownership) are required such that there will be reasonable progress 
toward attainment of the applicable NAAQs.\6\
---------------------------------------------------------------------------

    \5\ Subject to the provisions of section IV.C. below.
    \6\ The discussion in this paragraph is a proposal, but represents 
EPA's interim policy until final rulemaking is completed.
---------------------------------------------------------------------------

    Only intrapollutant emission offsets will be acceptable (e.g., 
hydrocarbon increases may not be offset against SO2 
reductions).
    Condition 4. The emission offsets will provide a positive net air 
quality benefit in the affected area (see Section IV.D. below). 
Atmospheric simulation modeling is not necessary for volatile organic 
compounds and NOX. Fulfillment of Condition 3 and Section 
IV.D. will be considered adequate to meet this condition.
    B. Exemptions from certain conditions. The reviewing authority may 
exempt the following sources from Condition 1 under Section III or 
Conditions 3 and 4. Section IV.A.:
    (i) Resource recovery facilities burning municipal solid waste, and 
(ii) sources which must switch fuels due to lack of adequate fuel 
supplies or where a source is required to be modified as a result of EPA 
regulations (e.g., lead-in-fuel requirements) and no exemption from such 
regulation is available to the source. Such an exemption may be granted 
only if:
    1. The applicant demonstrates that it made its best efforts to 
obtain sufficient emission offsets to comply with Condition 1 under 
Section III or Conditions 3 and 4 under Section IV.A. and that such 
efforts were unsuccessful;
    2. The applicant has secured all available emission offsets; and
    3. The applicant will continue to seek the necessary emission 
offsets and apply them when they become available.
    Such an exemption may result in the need to revise the SIP to 
provide additional control of existing sources.
    Temporary emission sources, such as pilot plants, portable 
facilities which will be relocated outside of the nonattainment area 
after a short period of time, and emissions resulting from the 
construction phase of a new source, are exempt from Conditions 3 and 4 
of this section.
    C. Baseline for determining credit for emission and air quality 
offsets. The baseline for determining credit for emission and air 
quality offsets will be the SIP emission limitations in effect at the 
time the application to construct or modify a source is filed. Thus, 
credit for emission offset purposes may be allowable for existing 
control that goes beyond that required by the SIP. Emission offsets 
generally should be made on a pounds per hour basis when all facilities 
involved in the emission offset calculations are operating at their 
maximum expected or allowed production rate. The reviewing agency should 
specify other averaging periods (e.g., tons per

[[Page 489]]

year) in addition to the pounds per hour basis if necessary to carry out 
the intent of this Ruling. When offsets are calculated on a tons per 
year basis, the baseline emissions for existing sources providing the 
offsets should be calculated using the actual annual operating hours for 
the previous one or two year period (or other appropriate period if 
warranted by cyclical business conditions). Where the SIP requires 
certain hardware controls in lieu of an emission limitation (e.g., 
floating roof tanks for petroleum storage), baseline allowable emissions 
should be based on actual operating conditions for the previous one or 
two year period (i.e., actual throughput and vapor pressures) in 
conjunction with the required hardware controls.
    1. No meaningful or applicable SIP requirement. Where the applicable 
SIP does not contain an emission limitation for a source or source 
category, the emission offset baseline involving such sources shall be 
the actual emissions determined in accordance with the discussion above 
regarding operating conditions.
    Where the SIP emission limit allows greater emissions than the 
uncontrolled emission rate of the source (as when a State has a single 
particulate emission limit for all fuels), emission offset credit will 
be allowed only for control below the uncontrolled emission rate.
    2. Combustion of fuels. Generally, the emissions for determining 
emission offset credit involving an existing fuel combustion source will 
be the allowable emissions under the SIP for the type of fuel being 
burned at the time the new source application is filed (i.e., if the 
existing source has switched to a different type of fuel at some earlier 
date, any resulting emission reduction [either actual or allowable] 
shall not be used for emission offset credit). If the existing source 
commits to switch to a cleaner fuel at some future date, emission offset 
credit based on the allowable emissions for the fuels involved is not 
acceptable unless the permit is conditioned to require the use of a 
specified alternative control measure which would achieve the same 
degree of emission reduction should the source switch back to a dirtier 
fuel at some later date. The reviewing authority should ensure that 
adequate long-term supplies of the new fuel are available before 
granting emission offset credit for fuel switches.
    3. Emission Reduction Credits from Shutdowns and Curtailments.
    (i) Emissions reductions achieved by shutting down an existing 
source or curtailing production or operating hours may be generally 
credited for offsets if they meet the requirements in paragraphs 
IV.C.3.i.1. through 2 of this section.
    (1) Such reductions are surplus, permanent, quantifiable, and 
federally enforceable.
    (2) The shutdown or curtailment occurred after the last day of the 
base year for the SIP planning process. For purposes of this paragraph, 
a reviewing authority may choose to consider a prior shutdown or 
curtailment to have occurred after the last day of the base year if the 
projected emissions inventory used to develop the attainment 
demonstration explicitly includes the emissions from such previously 
shutdown or curtailed emission units. However, in no event may credit be 
given for shutdowns that occurred before August 7, 1977.
    (ii) Emissions reductions achieved by shutting down an existing 
source or curtailing production or operating hours and that do not meet 
the requirements in paragraphs IV.C.3.i.1. through 2 of this section may 
be generally credited only if:
    (1) The shutdown or curtailment occurred on or after the date the 
new source permit application is filed; or
    (2) The applicant can establish that the proposed new source is a 
replacement for the shutdown or curtailed source, and the emissions 
reductions achieved by the shutdown or curtailment met the requirements 
of paragraphs IV.C.3.i.1. through 2 of this section.
    4. Credit for VOC substitution. As set forth in the Agency's 
``Recommended Policy on Control of Volatile Organic Compounds'' (42 FR 
35314, July 8, 1977), EPA has found that almost all non-methane VOCs are 
photochemically reactive and that low reactivity VOCs eventually form as 
much ozone as the highly reactive VOCs. Therefore, no emission offset 
credit may be allowed for replacing one VOC compound with another of 
lesser reactivity, except for those compounds listed in Table 1 of the 
above policy statement.
    5. ``Banking'' of emission offset credit. For new sources obtaining 
permits by applying offsets after January 16, 1979, the reviewing 
authority may allow offsets that exceed the requirements of reasonable 
progress toward attainment (Condition 3) to be ``banked'' (i.e., saved 
to provide offsets for a source seeking a permit in the future) for use 
under this Ruling. Likewise, the reviewing authority may allow the owner 
of an existing source that reduces its own emissions to bank any 
resulting reductions beyond those required by the SIP for use under this 
Ruling, even if none of the offsets are applied immediately to a new 
source permit. A reviewing authority may allow these banked offsets to 
be used under the preconstruction review program required by Part D, as 
long as these banked emissions are identified and accounted for in the 
SIP control strategy. A reviewing authority may not approve the 
construction of a source using banked offsets if the new source would 
interfere with the SIP control strategy or if such use would violate any 
other condition set forth for use

[[Page 490]]

of offsets. To preserve banked offsets, the reviewing authority should 
identify them in either a SIP revision or a permit, and establish rules 
as to how and when they may be used.
    6. Offset credit for meeting NSPS or NESHAPS. Where a source is 
subject to an emission limitation established in a New Source 
Performance Standard (NSPS) or a National Emission Standard for 
Hazardous Air Pollutants (NESHAPS), (i.e., requirements under sections 
111 and 112, respectively, of the Act), and a different SIP limitation, 
the more stringent limitation shall be used as the baseline for 
determining credit for emission and air quality offsets. The difference 
in emissions between the SIP and the NSPS or NESHAPS, for such source 
may not be used as offset credit. However, if a source were not subject 
to an NSPS or NESHAPS, for example if its construction had commenced 
prior to the proposal of an NSPS or NESHAPS for that source category, 
offset credit can be permitted for tightening the SIP to the NSPS or 
NESHAPS level for such source.
    D. Location of offsetting emissions. The owner or operator of a new 
or modified major stationary source may comply with any offset 
requirement in effect under this Ruling for increased emissions of any 
air pollutant only by obtaining emissions reductions of such air 
pollutant from the same source or other sources in the same 
nonattainment area, except that the reviewing authority may allow the 
owner or operator of a source to obtain such emissions reductions in 
another nonattainment area if the conditions in IV.D.1 and 2 are met.
    1. The other area has an equal or higher nonattainment 
classification than the area in which the source is located.
    2. Emissions from such other area contribute to a violation of the 
national ambient air quality standard in the nonattainment area in which 
the source is located.
    E. Reasonable further progress. Permits to construct and operate may 
be issued if the reviewing authority determines that, by the time the 
source is to commence operation, sufficient offsetting emissions 
reductions have been obtained, such that total allowable emissions from 
existing sources in the region, from new or modified sources which are 
not major emitting facilities, and from the proposed source will be 
sufficiently less than total emissions from existing sources prior to 
the application for such permit to construct or modify so as to 
represent (when considered together with the plan provisions required 
under CAA section 172) reasonable further progress (as defined in CAA 
section 171).
    F. Source obligation. At such time that a particular source or 
modification becomes a major stationary source or major modification 
solely by virtue of a relaxation in any enforceable limitation which was 
established after August 7, 1980, on the capacity of the source or 
modification otherwise to emit a pollutant, such as a restriction on 
hours of operation, then the requirements of this Ruling shall apply to 
the source or modification as though construction had not yet commenced 
on the source or modification.
    G. Offset Ratios. 1. In meeting the emissions offset requirements of 
paragraph IV.A, Condition 3 of this Ruling for ozone nonattainment areas 
that are subject to subpart 2, part D, title I of the Act, the ratio of 
total actual emissions reductions of VOC to the emissions increase of 
VOC shall be as follows:
    (i) In any marginal nonattainment area for ozone--at least 1.1:1;
    (ii) In any moderate nonattainment area for ozone--at least 1.15:1;
    (iii) In any serious nonattainment area for ozone--at least 1.2:1;
    (iv) In any severe nonattainment area for ozone--at least 1.3:1 
(except that the ratio may be at least 1.2:1 if the State also requires 
all existing major sources in such nonattainment area to use BACT for 
the control of VOC); and
    (v) In any extreme nonattainment area for ozone--at least 1.5:1 
(except that the ratio may be at least 1.2:1 if the State also requires 
all existing major sources in such nonattainment area to use BACT for 
the control of VOC); and
    2. Notwithstanding the requirements of paragraph IV.G.1 of this 
Ruling for meeting the requirements of paragraph IV.A, Condition 3 of 
this Ruling, the ratio of total actual emissions reductions of VOC to 
the emissions increase of VOC shall be at least 1.15:1 for all areas 
within an ozone transport region that is subject to subpart 2, part D, 
title I of the Act, except for serious, severe, and extreme ozone 
nonattainment areas that are subject to subpart 2, part D, title I of 
the Act.
    3. In meeting the emissions offset requirements of paragraph IV.A, 
Condition 3 of this Ruling for ozone nonattainment areas that are 
subject to subpart 1, part D, title I of the Act (but are not subject to 
subpart 2, part D, title I of the Act, including 8-hour ozone 
nonattainment areas subject to 40 CFR 51.902(b)), the ratio of total 
actual emissions reductions of VOC to the emissions increase of VOC 
shall be at least 1:1.
    H. Additional provisions for emissions of nitrogen oxides in ozone 
transport regions and nonattainment areas. The requirements of this 
Ruling applicable to major stationary sources and major modifications of 
volatile organic compounds shall apply to nitrogen oxides emissions from 
major stationary sources and major modifications of nitrogen oxides in 
an ozone transport region or in any ozone nonattainment area, except in 
ozone nonattainment areas where the Administrator has granted a 
NOX waiver applying

[[Page 491]]

the standards set forth under 182(f) and the waiver continues to apply.

                      V. Administrative Procedures

    The necessary emission offsets may be proposed either by the owner 
of the proposed source or by the local community or the State. The 
emission reduction committed to must be enforceable by authorized State 
and/or local agencies and under the Clean Air Act, and must be 
accomplished by the new source's start-up date. If emission reductions 
are to be obtained in a State that neighbors the State in which the new 
source is to be located, the emission reductions committed to must be 
enforceable by the neighboring State and/or local agencies and under the 
Clean Air Act. Where the new facility is a replacement for a facility 
that is being shut down in order to provide the necessary offsets, the 
reviewing authority may allow up to 180 days for shakedown of the new 
facility before the existing facility is required to cease operation.
    A. Source initiated emission offsets. A source may propose emission 
offsets which involve:
    (1) Reductions from sources controlled by the source owner (internal 
emission offsets); and/or (2) reductions from neighboring sources 
(external emission offsets). The source does not have to investigate all 
possible emission offsets. As long as the emission offsets obtained 
represent reasonable progress toward attainment, they will be 
acceptable. It is the reviewing authority's responsibility to assure 
that the emission offsets will be as effective as proposed by the 
source. An internal emission offset will be considered enforceable if it 
is made a SIP requirement by inclusion as a condition of the new source 
permit and the permit is forwarded to the appropriate EPA Regional 
Office. \7\ An external emission offset will not be enforceable unless 
the affected source(s) providing the emission reductions is subject to a 
new SIP requirement to ensure that its emissions will be reduced by a 
specified amount in a specified time. Thus, if the source(s) providing 
the emission reductions does not obtain the necessary reduction, it will 
be in violation of a SIP requirement and subject to enforcement action 
by EPA, the State and/or private parties.
---------------------------------------------------------------------------

    \7\ The emission offset will, therefore, be enforceable by EPA under 
section 113 as an applicable SIP requirement and will be enforceable by 
private parties under section 304 as an emission limitation.
---------------------------------------------------------------------------

    The form of the SIP revision may be a State or local regulation, 
operating permit condition, consent or enforcement order, or any other 
mechanism available to the State that is enforceable under the Clean Air 
Act. If a SIP revision is required, the public hearing on the revision 
may be substituted for the normal public comment procedure required for 
all major sources under 40 CFR 51.18. The formal publication of the SIP 
revision approval in the Federal Register need not appear before the 
source may proceed with construction. To minimize uncertainty that may 
be caused by these procedures, EPA will, if requested by the State, 
propose a SIP revision for public comment in the Federal Register 
concurrently with the State public hearing process. Of course, any major 
change in the final permit/SIP revision submitted by the State may 
require a reproposal by EPA.
    B. State or community initiated emission offsets. A State or 
community which desires that a source locate in its area may commit to 
reducing emissions from existing sources (including mobile sources) to 
sufficiently outweigh the impact of the new source and thus open the way 
for the new source. As with source-initiated emission offsets, the 
commitment must be something more than one-for-one. This commitment must 
be submitted as a SIP revision by the State.

            VI. Policy Where Attainment Dates have not Passed

    In some cases, the dates for attainment of primary standards 
specified in the SIP under section 110 have not yet passed due to a 
delay in the promulgation of a plan under this section of the Act. In 
addition the Act provides more flexibility with respect to the dates for 
attainment of secondary NAAQS than for primary standards. Rather than 
setting specific deadlines, section 110 requires secondary NAAQS to be 
achieved within a ``reasonable time''. Therefore, in some cases, the 
date for attainment of secondary standards specified in the SIP under 
section 110 may also not yet have passed. In such cases, a new source 
locating in an area designated in 40 CFR 81.300 et seq. as nonattainment 
(or, where section III of this Ruling is applicable, a new source that 
would cause or contribute to a NAAQS violation) may be exempt from the 
Conditions of section IV.A if the conditions in paragraphs VI.A through 
C are met.
    A. The new source meets the applicable SIP emission limitations.
    B. The new source will not interfere with the attainment date 
specified in the SIP under section 110 of the Act.

[[Page 492]]

    C. The Administrator has determined that conditions A and B of this 
section are satisfied and such determination is published in the Federal 
Register.

(Secs. 101(b)(1), 110, 160-169, 171-178, and 301(a), Clean Air Act, as 
amended (42 U.S.C. 7401(b)(1), 7410, 7470-7479, 7501-7508, and 7601(a)); 
sec. 129(a), Clean Air Act Amendments of 1977 (Pub. L. 95-95, 91 Stat. 
685 (Aug., 7, 1977)))

[44 FR 3282, Jan. 16, 1979, as amended at 45 FR 31311, May 13, 1980; 45 
FR 52741, Aug. 7, 1980; 45 FR 59879, Sept. 11, 1980; 46 FR 50771, Oct. 
14, 1981; 47 FR 27561, June 25, 1982; 49 FR 43210, Oct. 26, 1984; 51 FR 
40661, 40675, Nov. 7, 1986; 52 FR 24714, July 1, 1987; 52 FR 29386, Aug 
7, 1987; 54 FR 27285, 27299, June 28, 1989; 57 FR 3946, Feb. 3, 1992; 70 
FR 71702, Nov. 29, 2005]

                  Appendixes T-U to Part 51 [Reserved]

Appendix V to Part 51--Criteria for Determining the Completeness of Plan 
                               Submissions

                              1.0. Purpose

    This appendix V sets forth the minimum criteria for determining 
whether a State implementation plan submitted for consideration by EPA 
is an official submission for purposes of review under Sec. 51.103.
    1.1 The EPA shall return to the submitting official any plan or 
revision thereof which fails to meet the criteria set forth in this 
appendix V, and request corrective action, identifying the component(s) 
absent or insufficient to perform a review of the submitted plan.
    1.2 The EPA shall inform the submitting official whether or not a 
plan submission meets the requirements of this appendix V within 60 days 
of EPA's receipt of the submittal, but no later than 6 months after the 
date by which the State was required to submit the plan or revision. If 
a completeness determination is not made by 6 months from receipt of a 
submittal, the submittal shall be deemed complete by operation of law on 
the date 6 months from receipt. A determination of completeness under 
this paragraph means that the submission is an official submission for 
purposes of Sec. 51.103.

                              2.0. Criteria

    The following shall be included in plan submissions for review by 
EPA:
    2.1. Administrative Materials
    (a) A formal letter of submittal from the Governor or his designee, 
requesting EPA approval of the plan or revision thereof (hereafter ``the 
plan'').
    (b) Evidence that the State has adopted the plan in the State code 
or body of regulations; or issued the permit, order, consent agreement 
(hereafter ``document'') in final form. That evidence shall include the 
date of adoption or final issuance as well as the effective date of the 
plan, if different from the adoption/issuance date.
    (c) Evidence that the State has the necessary legal authority under 
State law to adopt and implement the plan.
    (d) A copy of the actual regulation, or document submitted for 
approval and incorporation by reference into the plan, including 
indication of the changes made to the existing approved plan, where 
applicable. The submittal shall be a copy of the official State 
regulation /document signed, stamped, dated by the appropriate State 
official indicating that it is fully enforceable by the State. The 
effective date of the regulation/document shall, whenever possible, be 
indicated in the document itself.
    (e) Evidence that the State followed all of the procedural 
requirements of the State's laws and constitution in conducting and 
completing the adoption/issuance of the plan.
    (f) Evidence that public notice was given of the proposed change 
consistent with procedures approved by EPA, including the date of 
publication of such notice.
    (g) Certification that public hearings(s) were held in accordance 
with the information provided in the public notice and the State's laws 
and constitution, if applicable.
    (h) Compilation of public comments and the State's response thereto.
    2.2. Technical Support
    (a) Identification of all regulated pollutants affected by the plan.
    (b) Identification of the locations of affected sources including 
the EPA attainment/nonattainment designation of the locations and the 
status of the attainment plan for the affected areas(s).
    (c) Quantification of the changes in plan allowable emissions from 
the affected sources; estimates of changes in current actual emissions 
from affected sources or, where appropriate, quantification of changes 
in actual emissions from affected sources through calculations of the 
differences between certain baseline levels and allowable emissions 
anticipated as a result of the revision.
    (d) The State's demonstration that the national ambient air quality 
standards, prevention of significant deterioration increments, 
reasonable further progress demonstration, and visibility, as 
applicable, are protected if the plan is approved and implemented. For 
all requests to redesignate an area to attainment for a national primary 
ambient air quality standard, under section 107 of the Act, a revision 
must be submitted to provide for the maintenance of the national primary 
ambient air quality standards for at least 10 years as required by 
section 175A of the Act.

[[Page 493]]

    (e) Modeling information required to support the proposed revision, 
including input data, output data, models used, justification of model 
selections, ambient monitoring data used, meteorological data used, 
justification for use of offsite data (where used), modes of models 
used, assumptions, and other information relevant to the determination 
of adequacy of the modeling analysis.
    (f) Evidence, where necessary, that emission limitations are based 
on continuous emission reduction technology.
    (g) Evidence that the plan contains emission limitations, work 
practice standards and recordkeeping/reporting requirements, where 
necessary, to ensure emission levels.
    (h) Compliance/enforcement strategies, including how compliance will 
be determined in practice.
    (i) Special economic and technological justifications required by 
any applicable EPA policies, or an explanation of why such 
justifications are not necessary.
    2.3. Exceptions
    2.3.1. The EPA, for the purposes of expediting the review of the 
plan, has adopted a procedure referred to as ``parallel processing.'' 
Parallel processing allows a State to submit the plan prior to actual 
adoption by the State and provides an opportunity for the State to 
consider EPA comments prior to submission of a final plan for final 
review and action. Under these circumstances, the plan submitted will 
not be able to meet all of the requirements of paragraph 2.1 (all 
requirements of paragraph 2.2 will apply). As a result, the following 
exceptions apply to plans submitted explicitly for parallel processing:
    (a) The letter required by paragraph 2.1(a) shall request that EPA 
propose approval of the proposed plan by parallel processing.
    (b) In lieu of paragraph 2.1(b) the State shall submit a schedule 
for final adoption or issuance of the plan.
    (c) In lieu of paragraph 2.1(d) the plan shall include a copy of the 
proposed/draft regulation or document, including indication of the 
proposed changes to be made to the existing approved plan, where 
applicable.
    (d) The requirements of paragraphs 2.1(e)-2.1(h) shall not apply to 
plans submitted for parallel processing.
    2.3.2. The exceptions granted in paragraph 2.3.1 shall apply only to 
EPA's determination of proposed action and all requirements of paragraph 
2.1 shall be met prior to publication of EPA's final determination of 
plan approvability.

[55 FR 5830, Feb. 16, 1990, as amended at 56 FR 42219, Aug. 26, 1991; 56 
FR 57288, Nov. 8, 1991]

         Appendix W to Part 51--Guideline on Air Quality Models

                                 Preface

    a. Industry and control agencies have long expressed a need for 
consistency in the application of air quality models for regulatory 
purposes. In the 1977 Clean Air Act, Congress mandated such consistency 
and encouraged the standardization of model applications. The Guideline 
on Air Quality Models (hereafter, Guideline) was first published in 
April 1978 to satisfy these requirements by specifying models and 
providing guidance for their use. The Guideline provides a common basis 
for estimating the air quality concentrations of criteria pollutants 
used in assessing control strategies and developing emission limits.
    b. The continuing development of new air quality models in response 
to regulatory requirements and the expanded requirements for models to 
cover even more complex problems have emphasized the need for periodic 
review and update of guidance on these techniques. Historically, three 
primary activities have provided direct input to revisions of the 
Guideline. The first is a series of annual EPA workshops conducted for 
the purpose of ensuring consistency and providing clarification in the 
application of models. The second activity was the solicitation and 
review of new models from the technical and user community. In the March 
27, 1980 Federal Register, a procedure was outlined for the submittal to 
EPA of privately developed models. After extensive evaluation and 
scientific review, these models, as well as those made available by EPA, 
have been considered for recognition in the Guideline. The third 
activity is the extensive on-going research efforts by EPA and others in 
air quality and meteorological modeling.
    c. Based primarily on these three activities, new sections and 
topics have been included as needed. EPA does not make changes to the 
guidance on a predetermined schedule, but rather on an as-needed basis. 
EPA believes that revisions of the Guideline should be timely and 
responsive to user needs and should involve public participation to the 
greatest possible extent. All future changes to the guidance will be 
proposed and finalized in the Federal Register. Information on the 
current status of modeling guidance can always be obtained from EPA's 
Regional Offices.

                            Table of Contents

                             List of Tables

1.0 Introduction
2.0 Overview of Model Use
    2.1 Suitability of Models
    2.2 Levels of Sophistication of Models
    2.3 Availability of Models

[[Page 494]]

3.0 Recommended Air Quality Models
    3.1 Preferred Modeling Techniques
    3.1.1 Discussion
    3.1.2 Recommendations
    3.2 Use of Alternative Models
    3.2.1 Discussion
    3.2.2 Recommendations
    3.3 Availability of Supplementary Modeling Guidance
4.0 Stationary-Source Models
    4.1 Discussion
    4.2 Recommendations
    4.2.1 Screening Techniques
    4.2.1.1 Simple Terrain
    4.2.1.2 Complex Terrain
    4.2.2 Refined Analytical Techniques
5.0 Models for Ozone, Particulate Matter, Carbon Monoxide, Nitrogen 
          Dioxide, and Lead
    5.1 Discussion
    5.2 Recommendations
    5.2.1 Models for Ozone
    5.2.2 Models for Particulate Matter
    5.2.2.1 PM-2.5
    5.2.2.2 PM-10
    5.2.3 Models for Carbon Monoxide
    5.2.4 Models for Nitrogen Dioxide (Annual Average)
    5.2.5 Models for Lead
6.0 Other Model Requirements
    6.1 Discussion
    6.2 Recommendations
    6.2.1 Visibility
    6.2.2 Good Engineering Practice Stack Height
    6.2.3 Long Range Transport (LRT) (i.e., beyond 50 km)
    6.2.4 Modeling Guidance for Other Governmental Programs
7.0 General Modeling Considerations
    7.1 Discussion
    7.2 Recommendations
    7.2.1 Design Concentrations
    7.2.2 Critical Receptor Sites
    7.2.3 Dispersion Coefficients
    7.2.4 Stability Categories
    7.2.5 Plume Rise
    7.2.6 Chemical Transformation
    7.2.7 Gravitational Settling and Deposition
    7.2.8 Complex Winds
    7.2.9 Calibration of Models
8.0 Model Input Data
    8.1 Source Data
    8.1.1 Discussion
    8.1.2 Recommendations
    8.2 Background Concentrations
    8.2.1 Discussion
    8.2.2 Recommendations (Isolated Single Source)
    8.2.3 Recommendations (Multi-Source Areas)
    8.3 Meteorological Input Data
    8.3.1 Length of Record of Meteorological Data
    8.3.2 National Weather Service Data
    8.3.3 Site Specific Data
    8.3.4 Treatment of Near-calms and Calms
9.0 Accuracy and Uncertainty of Models
    9.1 Discussion
    9.1.1 Overview of Model Uncertainty
    9.1.2 Studies of Model Accuracy
    9.1.3 Use of Uncertainty in Decision-Making
    9.1.4 Evaluation of Models
    9.2 Recommendations
10.0 Regulatory Application of Models
    10.1 Discussion
    10.2 Recommendations
    10.2.1 Analysis Requirements
    10.2.2 Use of Measured Data in Lieu of Model Estimates
    10.2.3 Emission Limits
11.0 Bibliography
12.0 References
Appendix A to Appendix W of 40 CFR Part 51--Summaries of Preferred Air 
          Quality Models

                             List of Tables
------------------------------------------------------------------------
              Table No.                              Title
------------------------------------------------------------------------
4-1a................................  Neutral/Stable Meteorological
                                       Matrix for CTSCREEN.
4-1b................................  Unstable/Convective Meteorological
                                       Matrix for CTSCREEN.
8-1.................................  Model Emission Input Data for
                                       Point Sources.
8-2.................................  Point Source Model Emission Input
                                       Data for NAAQS Compliance in PSD
                                       Demonstrations.
8-3.................................  Averaging Times for Site Specific
                                       Wind and Turbulence Measurements.
------------------------------------------------------------------------

                            1.0 Introduction

    a. The Guideline recommends air quality modeling techniques that 
should be applied to State Implementation Plan (SIP) revisions for 
existing sources and to new source reviews (NSR), including prevention 
of significant deterioration (PSD). \1,2,3\ Applicable only to criteria 
air pollutants, it is intended for use by EPA Regional Offices in 
judging the adequacy of modeling analyses performed by EPA, State and 
local agencies and by industry. The guidance is appropriate for use by 
other Federal agencies and by State agencies with air quality and land 
management responsibilities. The Guideline serves to identify, for all 
interested parties, those techniques and data bases EPA considers 
acceptable. The Guideline is not intended to be a compendium of modeling 
techniques. Rather, it should serve as a common measure of acceptable 
technical analysis when supported by sound scientific judgment.
    b. Due to limitations in the spatial and temporal coverage of air 
quality measurements, monitoring data normally are not sufficient as the 
sole basis for demonstrating the adequacy of emission limits for 
existing sources. Also, the impacts of new sources that do not yet exist 
can only be determined through modeling. Thus, models, while

[[Page 495]]

uniquely filling one program need, have become a primary analytical tool 
in most air quality assessments. Air quality measurements can be used in 
a complementary manner to dispersion models, with due regard for the 
strengths and weaknesses of both analysis techniques. Measurements are 
particularly useful in assessing the accuracy of model estimates. The 
use of air quality measurements alone however could be preferable, as 
detailed in a later section of this document, when models are found to 
be unacceptable and monitoring data with sufficient spatial and temporal 
coverage are available.
    c. It would be advantageous to categorize the various regulatory 
programs and to apply a designated model to each proposed source needing 
analysis under a given program. However, the diversity of the nation's 
topography and climate, and variations in source configurations and 
operating characteristics dictate against a strict modeling 
``cookbook''. There is no one model capable of properly addressing all 
conceivable situations even within a broad category such as point 
sources. Meteorological phenomena associated with threats to air quality 
standards are rarely amenable to a single mathematical treatment; thus, 
case-by-case analysis and judgment are frequently required. As modeling 
efforts become more complex, it is increasingly important that they be 
directed by highly competent individuals with a broad range of 
experience and knowledge in air quality meteorology. Further, they 
should be coordinated closely with specialists in emissions 
characteristics, air monitoring and data processing. The judgment of 
experienced meteorologists and analysts is essential.
    d. The model that most accurately estimates concentrations in the 
area of interest is always sought. However, it is clear from the needs 
expressed by the States and EPA Regional Offices, by many industries and 
trade associations, and also by the deliberations of Congress, that 
consistency in the selection and application of models and data bases 
should also be sought, even in case-by-case analyses. Consistency 
ensures that air quality control agencies and the general public have a 
common basis for estimating pollutant concentrations, assessing control 
strategies and specifying emission limits. Such consistency is not, 
however, promoted at the expense of model and data base accuracy. The 
Guideline provides a consistent basis for selection of the most accurate 
models and data bases for use in air quality assessments.
    e. Recommendations are made in the Guideline concerning air quality 
models, data bases, requirements for concentration estimates, the use of 
measured data in lieu of model estimates, and model evaluation 
procedures. Models are identified for some specific applications. The 
guidance provided here should be followed in air quality analyses 
relative to State Implementation Plans and in supporting analyses 
required by EPA, State and local agency air programs. EPA may approve 
the use of another technique that can be demonstrated to be more 
appropriate than those recommended in this guide. This is discussed at 
greater length in Section 3. In all cases, the model applied to a given 
situation should be the one that provides the most accurate 
representation of atmospheric transport, dispersion, and chemical 
transformations in the area of interest. However, to ensure consistency, 
deviations from this guide should be carefully documented and fully 
supported.
    f. From time to time situations arise requiring clarification of the 
intent of the guidance on a specific topic. Periodic workshops are held 
with the headquarters, Regional Office, State, and local agency modeling 
representatives to ensure consistency in modeling guidance and to 
promote the use of more accurate air quality models and data bases. The 
workshops serve to provide further explanations of Guideline 
requirements to the Regional Offices and workshop reports are issued 
with this clarifying information. In addition, findings from ongoing 
research programs, new model development, or results from model 
evaluations and applications are continuously evaluated. Based on this 
information changes in the guidance may be indicated.
    g. All changes to the Guideline must follow rulemaking requirements 
since the Guideline is codified in Appendix W of Part 51. EPA will 
promulgate proposed and final rules in the Federal Register to amend 
this Appendix. Ample opportunity for public comment will be provided for 
each proposed change and public hearings scheduled if requested.
    h. A wide range of topics on modeling and data bases are discussed 
in the Guideline. Section 2 gives an overview of models and their 
appropriate use. Section 3 provides specific guidance on the use of 
``preferred'' air quality models and on the selection of alternative 
techniques. Sections 4 through 7 provide recommendations on modeling 
techniques for application to simple-terrain stationary source problems, 
complex terrain problems, and mobile source problems. Specific modeling 
requirements for selected regulatory issues are also addressed. Section 
8 discusses issues common to many modeling analyses, including 
acceptable model components. Section 9 makes recommendations for data 
inputs to models including source, meteorological and background air 
quality data. Section 10 covers the uncertainty in model estimates and 
how that information can be useful to the regulatory decision-maker. The 
last chapter summarizes how estimates and measurements of air quality 
are

[[Page 496]]

used in assessing source impact and in evaluating control strategies.
    i. Appendix W to 40 CFR Part 51 itself contains an appendix: 
Appendix A. Thus, when reference is made to ``Appendix A'' in this 
document, it refers to Appendix A to Appendix W to 40 CFR Part 51. 
Appendix A contains summaries of refined air quality models that are 
``preferred'' for specific applications; both EPA models and models 
developed by others are included.

                        2.0 Overview of Model Use

    a. Before attempting to implement the guidance contained in this 
document, the reader should be aware of certain general information 
concerning air quality models and their use. Such information is 
provided in this section.

                        2.1 Suitability of Models

    a. The extent to which a specific air quality model is suitable for 
the evaluation of source impact depends upon several factors. These 
include: (1) The meteorological and topographic complexities of the 
area; (2) the level of detail and accuracy needed for the analysis; (3) 
the technical competence of those undertaking such simulation modeling; 
(4) the resources available; and (5) the detail and accuracy of the data 
base, i.e., emissions inventory, meteorological data, and air quality 
data. Appropriate data should be available before any attempt is made to 
apply a model. A model that requires detailed, precise, input data 
should not be used when such data are unavailable. However, assuming the 
data are adequate, the greater the detail with which a model considers 
the spatial and temporal variations in emissions and meteorological 
conditions, the greater the ability to evaluate the source impact and to 
distinguish the effects of various control strategies.
    b. Air quality models have been applied with the most accuracy, or 
the least degree of uncertainty, to simulations of long term averages in 
areas with relatively simple topography. Areas subject to major 
topographic influences experience meteorological complexities that are 
extremely difficult to simulate. Although models are available for such 
circumstances, they are frequently site specific and resource intensive. 
In the absence of a model capable of simulating such complexities, only 
a preliminary approximation may be feasible until such time as better 
models and data bases become available.
    c. Models are highly specialized tools. Competent and experienced 
personnel are an essential prerequisite to the successful application of 
simulation models. The need for specialists is critical when the more 
sophisticated models are used or the area being investigated has 
complicated meteorological or topographic features. A model applied 
improperly, or with inappropriate data, can lead to serious 
misjudgements regarding the source impact or the effectiveness of a 
control strategy.
    d. The resource demands generated by use of air quality models vary 
widely depending on the specific application. The resources required 
depend on the nature of the model and its complexity, the detail of the 
data base, the difficulty of the application, and the amount and level 
of expertise required. The costs of manpower and computational 
facilities may also be important factors in the selection and use of a 
model for a specific analysis. However, it should be recognized that 
under some sets of physical circumstances and accuracy requirements, no 
present model may be appropriate. Thus, consideration of these factors 
should lead to selection of an appropriate model.

                 2.2 Levels of Sophistication of Models

    a. There are two levels of sophistication of models. The first level 
consists of relatively simple estimation techniques that generally use 
preset, worst-case meteorological conditions to provide conservative 
estimates of the air quality impact of a specific source, or source 
category. These are called screening techniques or screening models. The 
purpose of such techniques is to eliminate the need of more detailed 
modeling for those sources that clearly will not cause or contribute to 
ambient concentrations in excess of either the National Ambient Air 
Quality Standards (NAAQS) \4\ or the allowable prevention of significant 
deterioration (PSD) concentration increments. \2,3\ If a screening 
technique indicates that the concentration contributed by the source 
exceeds the PSD increment or the increment remaining to just meet the 
NAAQS, then the second level of more sophisticated models should be 
applied.
    b. The second level consists of those analytical techniques that 
provide more detailed treatment of physical and chemical atmospheric 
processes, require more detailed and precise input data, and provide 
more specialized concentration estimates. As a result they provide a 
more refined and, at least theoretically, a more accurate estimate of 
source impact and the effectiveness of control strategies. These are 
referred to as refined models.
    c. The use of screening techniques followed, as appropriate, by a 
more refined analysis is always desirable. However there are situations 
where the screening techniques are practically and technically the only 
viable option for estimating source impact. In such cases, an attempt 
should be made to acquire or improve the necessary data bases and to 
develop appropriate analytical techniques.

[[Page 497]]

                       2.3 Availability of Models

    a. For most of the screening and refined models discussed in the 
Guideline, codes, associated documentation and other useful information 
are available for download from EPA's Support Center for Regulatory Air 
Modeling (SCRAM) Internet Web site at http://www.epa.gov/scram001. A 
list of alternate models that can be used with case-by-case 
justification (subsection 3.2) and an example air quality analysis 
checklist are also posted on this Web site. This is a site with which 
modelers should become familiar.

                   3.0 Recommended Air Quality Models

    a. This section recommends the approach to be taken in determining 
refined modeling techniques for use in regulatory air quality programs. 
The status of models developed by EPA, as well as those submitted to EPA 
for review and possible inclusion in this guidance, is discussed. The 
section also addresses the selection of models for individual cases and 
provides recommendations for situations where the preferred models are 
not applicable. Two additional sources of modeling guidance are the 
Model Clearinghouse \5\ and periodic Regional/State/Local Modelers 
workshops.
    b. In this guidance, when approval is required for a particular 
modeling technique or analytical procedure, we often refer to the 
``appropriate reviewing authority''. In some EPA regions, authority for 
NSR and PSD permitting and related activities has been delegated to 
State and even local agencies. In these cases, such agencies are 
``representatives'' of the respective regions. Even in these 
circumstances, the Regional Office retains the ultimate authority in 
decisions and approvals. Therefore, as discussed above and depending on 
the circumstances, the appropriate reviewing authority may be the 
Regional Office, Federal Land Manager(s), State agency(ies), or perhaps 
local agency(ies). In cases where review and approval comes solely from 
the Regional Office (sometimes stated as ``Regional Administrator''), 
this will be stipulated. If there is any question as to the appropriate 
reviewing authority, you should contact the Regional modeling contact 
(http://www.epa.gov/scram001/tt28.htm#regionalmodelingcontacts) in the 
appropriate EPA Regional Office, whose jurisdiction generally includes 
the physical location of the source in question and its expected 
impacts.
    c. In all regulatory analyses, especially if other-than-preferred 
models are selected for use, early discussions among Regional Office 
staff, State and local control agencies, industry representatives, and 
where appropriate, the Federal Land Manager, are invaluable and are 
encouraged. Agreement on the data base(s) to be used, modeling 
techniques to be applied and the overall technical approach, prior to 
the actual analyses, helps avoid misunderstandings concerning the final 
results and may reduce the later need for additional analyses. The use 
of an air quality analysis checklist, such as is posted on EPA's 
Internet SCRAM Web site (subsection 2.3), and the preparation of a 
written protocol help to keep misunderstandings at a minimum.
    d. It should not be construed that the preferred models identified 
here are to be permanently used to the exclusion of all others or that 
they are the only models available for relating emissions to air 
quality. The model that most accurately estimates concentrations in the 
area of interest is always sought. However, designation of specific 
models is needed to promote consistency in model selection and 
application.
    e. The 1980 solicitation of new or different models from the 
technical community \6\ and the program whereby these models were 
evaluated, established a means by which new models are identified, 
reviewed and made available in the Guideline. There is a pressing need 
for the development of models for a wide range of regulatory 
applications. Refined models that more realistically simulate the 
physical and chemical process in the atmosphere and that more reliably 
estimate pollutant concentrations are needed.

                    3.1 Preferred Modeling Techniques

                            3.1.1 Discussion

    a. EPA has developed models suitable for regulatory application. 
Other models have been submitted by private developers for possible 
inclusion in the Guideline. Refined models which are preferred and 
recommended by EPA have undergone evaluation exercises \7,8,9,10\ that 
include statistical measures of model performance in comparison with 
measured air quality data as suggested by the American Meteorological 
Society \11\ and, where possible, peer scientific reviews. \12,13,14\
    b. When a single model is found to perform better than others, it is 
recommended for application as a preferred model and listed in Appendix 
A. If no one model is found to clearly perform better through the 
evaluation exercise, then the preferred model listed in Appendix A may 
be selected on the basis of other factors such as past use, public 
familiarity, cost or resource requirements, and availability. 
Accordingly, dispersion models listed in Appendix A meet these 
conditions:
    i. The model must be written in a common programming language, and 
the executable(s) must run on a common computer platform.
    ii. The model must be documented in a user's guide which identifies 
the mathematics of the model, data requirements and program operating 
characteristics at a level

[[Page 498]]

of detail comparable to that available for other recommended models in 
Appendix A.
    iii. The model must be accompanied by a complete test data set 
including input parameters and output results. The test data must be 
packaged with the model in computer-readable form.
    iv. The model must be useful to typical users, e.g., State air 
pollution control agencies, for specific air quality control problems. 
Such users should be able to operate the computer program(s) from 
available documentation.
    v. The model documentation must include a comparison with air 
quality data (and/or tracer measurements) or with other well-established 
analytical techniques.
    vi. The developer must be willing to make the model and source code 
available to users at reasonable cost or make them available for public 
access through the Internet or National Technical Information Service: 
The model and its code cannot be proprietary.
    c. The evaluation process includes a determination of technical 
merit, in accordance with the above six items including the practicality 
of the model for use in ongoing regulatory programs. Each model will 
also be subjected to a performance evaluation for an appropriate data 
base and to a peer scientific review. Models for wide use (not just an 
isolated case) that are found to perform better will be proposed for 
inclusion as preferred models in future Guideline revisions.
    d. No further evaluation of a preferred model is required for a 
particular application if the EPA recommendations for regulatory use 
specified for the model in the Guideline are followed. Alternative 
models to those listed in Appendix A should generally be compared with 
measured air quality data when they are used for regulatory applications 
consistent with recommendations in subsection 3.2.

                          3.1.2 Recommendations

    a. Appendix A identifies refined models that are preferred for use 
in regulatory applications. If a model is required for a particular 
application, the user should select a model from that appendix. These 
models may be used without a formal demonstration of applicability as 
long as they are used as indicated in each model summary of Appendix A. 
Further recommendations for the application of these models to specific 
source problems are found in subsequent sections of the Guideline.
    b. If changes are made to a preferred model without affecting the 
concentration estimates, the preferred status of the model is unchanged. 
Examples of modifications that do not affect concentrations are those 
made to enable use of a different computer platform or those that affect 
only the format or averaging time of the model results. However, when 
any changes are made, the Regional Administrator should require a test 
case example to demonstrate that the concentration estimates are not 
affected.
    c. A preferred model should be operated with the options listed in 
Appendix A as ``Recommendations for Regulatory Use.'' If other options 
are exercised, the model is no longer ``preferred.'' Any other 
modification to a preferred model that would result in a change in the 
concentration estimates likewise alters its status as a preferred model. 
Use of the model must then be justified on a case-by-case basis.

                      3.2 Use of Alternative Models

                            3.2.1 Discussion

    a. Selection of the best techniques for each individual air quality 
analysis is always encouraged, but the selection should be done in a 
consistent manner. A simple listing of models in this Guideline cannot 
alone achieve that consistency nor can it necessarily provide the best 
model for all possible situations. An EPA reference \15\ provides a 
statistical technique for evaluating model performance for predicting 
peak concentration values, as might be observed at individual monitoring 
locations. This protocol is available to assist in developing a 
consistent approach when justifying the use of other-than-preferred 
modeling techniques recommended in the Guideline. The procedures in this 
protocol provide a general framework for objective decision-making on 
the acceptability of an alternative model for a given regulatory 
application. These objective procedures may be used for conducting both 
the technical evaluation of the model and the field test or performance 
evaluation. An ASTM reference \16\ provides a general philosophy for 
developing and implementing advanced statistical evaluations of 
atmospheric dispersion models, and provides an example statistical 
technique to illustrate the application of this philosophy.
    b. This section discusses the use of alternate modeling techniques 
and defines three situations when alternative models may be used.

                          3.2.2 Recommendations

    a. Determination of acceptability of a model is a Regional Office 
responsibility. Where the Regional Administrator finds that an 
alternative model is more appropriate than a preferred model, that model 
may be used subject to the recommendations of this subsection. This 
finding will normally result from a determination that (1) a preferred 
air quality model is not appropriate for the particular application; or 
(2) a more appropriate model or analytical procedure is available and 
applicable.
    b. An alternative model should be evaluated from both a theoretical 
and a performance perspective before it is selected for use.

[[Page 499]]

There are three separate conditions under which such a model may 
normally be approved for use: (1) If a demonstration can be made that 
the model produces concentration estimates equivalent to the estimates 
obtained using a preferred model; (2) if a statistical performance 
evaluation has been conducted using measured air quality data and the 
results of that evaluation indicate the alternative model performs 
better for the given application than a comparable model in Appendix A; 
or (3) if the preferred model is less appropriate for the specific 
application, or there is no preferred model. Any one of these three 
separate conditions may make use of an alternative model acceptable. 
Some known alternative models that are applicable for selected 
situations are listed on EPA's SCRAM Internet Web site (subsection 2.3). 
However, inclusion there does not confer any unique status relative to 
other alternative models that are being or will be developed in the 
future.
    c. Equivalency, condition (1) in paragraph (b) of this subsection, 
is established by demonstrating that the maximum or highest, second 
highest concentrations are within 2 percent of the estimates obtained 
from the preferred model. The option to show equivalency is intended as 
a simple demonstration of acceptability for an alternative model that is 
so nearly identical (or contains options that can make it identical) to 
a preferred model that it can be treated for practical purposes as the 
preferred model. Two percent was selected as the basis for equivalency 
since it is a rough approximation of the fraction that PSD Class I 
increments are of the NAAQS for SO2, i.e., the difference in 
concentrations that is judged to be significant. However, 
notwithstanding this demonstration, models that are not equivalent may 
be used when one of the two other conditions described in paragraphs (d) 
and (e) of this subsection are satisfied.
    d. For condition (2) in paragraph (b) of this subsection, 
established procedures and techniques \15,16\ for determining the 
acceptability of a model for an individual case based on superior 
performance should be followed, as appropriate. Preparation and 
implementation of an evaluation protocol which is acceptable to both 
control agencies and regulated industry is an important element in such 
an evaluation.
    e. Finally, for condition (3) in paragraph (b) of this subsection, 
an alternative refined model may be used provided that:
    i. The model has received a scientific peer review;
    ii. The model can be demonstrated to be applicable to the problem on 
a theoretical basis;
    iii. The data bases which are necessary to perform the analysis are 
available and adequate;
    iv. Appropriate performance evaluations of the model have shown that 
the model is not biased toward underestimates; and
    v. A protocol on methods and procedures to be followed has been 
established.

           3.3 Availability of Supplementary Modeling Guidance

    a. The Regional Administrator has the authority to select models 
that are appropriate for use in a given situation. However, there is a 
need for assistance and guidance in the selection process so that 
fairness and consistency in modeling decisions is fostered among the 
various Regional Offices and the States. To satisfy that need, EPA 
established the Model Clearinghouse \5\ and also holds periodic 
workshops with headquarters, Regional Office, State, and local agency 
modeling representatives.
    b. The Regional Office should always be consulted for information 
and guidance concerning modeling methods and interpretations of modeling 
guidance, and to ensure that the air quality model user has available 
the latest most up-to-date policy and procedures. As appropriate, the 
Regional Office may request assistance from the Model Clearinghouse 
after an initial evaluation and decision has been reached concerning the 
application of a model, analytical technique or data base in a 
particular regulatory action.

                4.0 Traditional Stationary Source Models

                             4.1 Discussion

    a. Guidance in this section applies to modeling analyses for which 
the predominant meteorological conditions that control the design 
concentration are steady state and for which the transport distances are 
nominally 50km or less. The models recommended in this section are 
generally used in the air quality impact analysis of stationary sources 
for most criteria pollutants. The averaging time of the concentration 
estimates produced by these models ranges from 1 hour to an annual 
average.
    b. Simple terrain, as used here, is considered to be an area where 
terrain features are all lower in elevation than the top of the stack of 
the source(s) in question. Complex terrain is defined as terrain 
exceeding the height of the stack being modeled.
    c. In the early 1980s, model evaluation exercises were conducted to 
determine the ``best, most appropriate point source model'' for use in 
simple terrain.\12\ No one model was found to be clearly superior and, 
based on past use, public familiarity, and availability, ISC 
(predecessor to ISC3 \17\) became the recommended model for a wide range 
of regulatory applications. Other refined models which also employed the 
same basic Gaussian kernel as in ISC, i.e., BLP,

[[Page 500]]

CALINE3 and OCD, were developed for specialized applications (Appendix 
A). Performance evaluations were also made for these models, which are 
identified below.
    d. Encouraged by the development of pragmatic methods for better 
characterization of plume dispersion \18,19,20,21\ the AMS/EPA 
Regulatory Model Improvement Committee (AERMIC) developed AERMOD. \22\ 
AERMOD employs best state-of-practice parameterizations for 
characterizing the meteorological influences and dispersion. The model 
utilizes a probability density function (pdf) and the superposition of 
several Gaussian plumes to characterize the distinctly non-Gaussian 
nature of the vertical pollutant distribution for elevated plumes during 
convective conditions; otherwise the distribution is Gaussian. Also, 
nighttime urban boundary layers (and plumes within them) have the 
turbulence enhanced by AERMOD to simulate the influence of the urban 
heat island. AERMOD has been evaluated using a variety of data sets and 
has been found to perform better than ISC3 for many applications, and as 
well or better than CTDMPLUS for several complex terrain data sets 
(Section A.1; subsection n). The current version of AERMOD has been 
modified to include an algorithm for dry and wet deposition for both 
gases and particles. Note that when deposition is invoked, mass in the 
plume is depleted. Availability of this version is described in Section 
A.1, and is subject to applicable guidance published in the Guideline.
    e. A new building downwash algorithm \23\ was developed and tested 
within AERMOD. The PRIME algorithm has been evaluated using a variety of 
data sets and has been found to perform better than the downwash 
algorithm that is in ISC3, and has been shown to perform acceptably in 
tests within AERMOD (Section A.1; subsection n).

                           4.2 Recommendations

                       4.2.1 Screening Techniques

                         4.2.1.1 Simple Terrain

    a. Where a preliminary or conservative estimate is desired, point 
source screening techniques are an acceptable approach to air quality 
analyses. EPA has published guidance for screening procedures. \24,25\
    b. All screening procedures should be adjusted to the site and 
problem at hand. Close attention should be paid to whether the area 
should be classified urban or rural in accordance with Section 7.2.3. 
The climatology of the area should be studied to help define the worst-
case meteorological conditions. Agreement should be reached between the 
model user and the appropriate reviewing authority on the choice of the 
screening model for each analysis, and on the input data as well as the 
ultimate use of the results.

                         4.2.1.2 Complex Terrain

    a. CTSCREEN \26\ can be used to obtain conservative, yet realistic, 
worst-case estimates for receptors located on terrain above stack 
height. CTSCREEN accounts for the three-dimensional nature of plume and 
terrain interaction and requires detailed terrain data representative of 
the modeling domain. The model description and user's instructions are 
contained in the user's guide. \26\ The terrain data must be digitized 
in the same manner as for CTDMPLUS and a terrain processor is available. 
\27\ A discussion of the model's performance characteristics is provided 
in a technical paper. \28\ CTSCREEN is designed to execute a fixed 
matrix of meteorological values for wind speed (u), standard deviation 
of horizontal and vertical wind speeds ([sigma]v, 
[sigma]w), vertical potential temperature gradient 
(d[thetas]/dz), friction velocity (u*), Monin-Obukhov length 
(L), mixing height (zi) as a function of terrain height, and 
wind directions for both neutral/stable conditions and unstable 
convective conditions. Table 4-1 contains the matrix of meteorological 
variables that is used for each CTSCREEN analysis. There are 96 
combinations, including exceptions, for each wind direction for the 
neutral/stable case, and 108 combinations for the unstable case. The 
specification of wind direction, however, is handled internally, based 
on the source and terrain geometry. Although CTSCREEN is designed to 
address a single source scenario, there are a number of options that can 
be selected on a case-by-case basis to address multi-source situations. 
However, the appropriate reviewing authority should be consulted, and 
concurrence obtained, on the protocol for modeling multiple sources with 
CTSCREEN to ensure that the worst case is identified and assessed. The 
maximum concentration output from CTSCREEN represents a worst-case 1-
hour concentration. Time-scaling factors of 0.7 for 3-hour, 0.15 for 24-
hour and 0.03 for annual concentration averages are applied internally 
by CTSCREEN to the highest 1-hour concentration calculated by the model.
    b. Placement of receptors requires very careful attention when 
modeling in complex terrain. Often the highest concentrations are 
predicted to occur under very stable conditions, when the plume is near, 
or impinges on, the terrain. The plume under such conditions may be 
quite narrow in the vertical, so that even relatively small changes in a 
receptor's location may substantially affect the predicted 
concentration. Receptors within about a kilometer of the source may be 
even more sensitive to location. Thus, a dense array of receptors may be 
required in some cases. In order to avoid excessively large computer 
runs due to such a large array of receptors, it is often desirable to 
model the area twice. The first model run would use a moderate number of 
receptors

[[Page 501]]

carefully located over the area of interest. The second model run would 
use a more dense array of receptors in areas showing potential for high 
concentrations, as indicated by the results of the first model run.
    c. As mentioned above, digitized contour data must be preprocessed 
\27\ to provide hill shape parameters in suitable input format. The user 
then supplies receptors either through an interactive program that is 
part of the model or directly, by using a text editor; using both 
methods to select receptors will generally be necessary to assure that 
the maximum concentrations are estimated by either model. In cases where 
a terrain feature may ``appear to the plume'' as smaller, multiple 
hills, it may be necessary to model the terrain both as a single feature 
and as multiple hills to determine design concentrations.
    d. Other screening techniques \17,25,29\ may be acceptable for 
complex terrain cases where established procedures are used. The user is 
encouraged to confer with the appropriate reviewing authority if any 
unresolvable problems are encountered, e.g., applicability, 
meteorological data, receptor siting, or terrain contour processing 
issues.

                   4.2.2 Refined Analytical Techniques

    a. A brief description of each preferred model for refined 
applications is found in Appendix A. Also listed in that appendix are 
availability, the model input requirements, the standard options that 
should be selected when running the program, and output options.
    b. For a wide range of regulatory applications in all types of 
terrain, the recommended model is AERMOD. This recommendation is based 
on extensive developmental and performance evaluation (Section A.1; 
subsection n). Differentiation of simple versus complex terrain is 
unnecessary with AERMOD. In complex terrain, AERMOD employs the well-
known dividing-streamline concept in a simplified simulation of the 
effects of plume-terrain interactions.
    c. If aerodynamic building downwash is important for the modeling 
analysis, e.g., paragraph 6.2.2(b), then the recommended model is 
AERMOD. The state-of-the-science for modeling atmospheric deposition is 
evolving and the best techniques are currently being assessed and their 
results are being compared with observations. Consequently, while 
deposition treatment is available in AERMOD, the approach taken for any 
purpose should be coordinated with the appropriate reviewing authority. 
Line sources can be simulated with AERMOD if point or volume sources are 
appropriately combined. If buoyant plume rise from line sources is 
important for the modeling analysis, the recommended model is BLP. For 
other special modeling applications, CALINE3 (or CAL3QHCR on a case-by-
case basis), OCD, and EDMS are available as described in Sections 5 and 
6.
    d. If the modeling application involves a well defined hill or ridge 
and a detailed dispersion analysis of the spatial pattern of plume 
impacts is of interest, CTDMPLUS, listed in Appendix A, is available. 
CDTMPLUS provides greater resolution of concentrations about the contour 
of the hill feature than does AERMOD through a different plume-terrain 
interaction algorithm.

                          Table 4-1a--Neutral/Stable Meteorological Matrix for CTSCREEN
 
 
----------------------------------------------------------------------------------------------------------------
                  Variable                                             Specific values
----------------------------------------------------------------------------------------------------------------
U (m/s)....................................          1.0           2.0          3.0            4.0           5.0
[sigma]v (m/s).............................          0.3           0.75
[sigma]w (m/s).............................          0.08          0.15         0.30           0.75
[Delta][thetas]/[Delta]z (K/m).............          0.01          0.02         0.035
WD.........................................     (Wind direction is optimized internally for each meteorological
                                                                        combination.)
----------------------------------------------------------------------------------------------------------------

Exceptions:

(1) If U <= 2 m/s and [sigma]v <= 0.3 m/s, then include 
          [sigma]w = 0.04 m/s.
(2) If [sigma]w = 0.75 m/s and U = 3.0 m/s, then 
          [Delta][thetas]/[Delta]z is limited to <= 0.01 K/m.
(3) If U = 4 m/s, then [sigma]w = 0.15 
          m/s.
(4) [sigma]w <= [sigma]v

                       Table 4-1b--Unstable/Convective Meteorological Matrix for CTSCREEN
 
 
----------------------------------------------------------------------------------------------------------------
                  Variable                                              Specific values
----------------------------------------------------------------------------------------------------------------
U (m/s).....................................         1.0           2.0           3.0            4.0          5.0
U* (m/s)....................................         0.1           0.3           0.5
L (m).......................................       -10           -50           -90

[[Page 502]]

 
[Delta][thetas]/[Delta]z (K/m)..............         0.030        (potential temperature gradient above Zi)
Zi (m)......................................         0.5h          1.0h          1.5h     (h = terrain height)
----------------------------------------------------------------------------------------------------------------

  5.0 Models for Ozone, Particulate Matter, Carbon Monoxide, Nitrogen 
                            Dioxide, and Lead

                             5.1 Discussion

    a. This section identifies modeling approaches or models appropriate 
for addressing ozone (O3) \a\, carbon monoxide (CO), nitrogen 
dioxide (NO2), particulates (PM-2.5 \a\ and PM-10), and lead. 
These pollutants are often associated with emissions from numerous 
sources. Generally, mobile sources contribute significantly to emissions 
of these pollutants or their precursors. For cases where it is of 
interest to estimate concentrations of CO or NO2 near a 
single or small group of stationary sources, refer to Section 4. 
(Modeling approaches for SO2 are discussed in Section 4.)
---------------------------------------------------------------------------

    \a\ Modeling for attainment demonstrations for O3 and PM-
2.5 should be conducted in time to meet required SIP submission dates as 
provided for in the respective implementation rules. Information on 
implementation of the 8-hr O3 and PM-2.5 standards is 
available at: http://www.epa.gov/ttn/naags/.
---------------------------------------------------------------------------

    b. Several of the pollutants mentioned in the preceding paragraph 
are closely related to each other in that they share common sources of 
emissions and/or are subject to chemical transformations of similar 
precursors. \30,31\ For example, strategies designed to reduce ozone 
could have an effect on the secondary component of PM-2.5 and vice 
versa. Thus, it makes sense to use models which take into account the 
chemical coupling between O3 and PM-2.5, when feasible. This 
should promote consistency among methods used to evaluate strategies for 
reducing different pollutants as well as consistency among the 
strategies themselves. Regulatory requirements for the different 
pollutants are likely to be due at different times. Thus, the following 
paragraphs identify appropriate modeling approaches for pollutants 
individually.
    c. The NAAQS for ozone was revised on July 18, 1997 and is now based 
on an 8-hour averaging period. Models for ozone are needed primarily to 
guide choice of strategies to correct an observed ozone problem in an 
area not attaining the NAAQS for ozone. Use of photochemical grid models 
is the recommended means for identifying strategies needed to correct 
high ozone concentrations in such areas. Such models need to consider 
emissions of volatile organic compounds (VOC), nitrogen oxides 
(NOX) and carbon monoxide (CO), as well as means for 
generating meteorological data governing transport and dispersion of 
ozone and its precursors. Other approaches, such as Lagrangian or 
observational models may be used to guide choice of appropriate 
strategies to consider with a photochemical grid model. These other 
approaches may be sufficient to address ozone in an area where observed 
concentrations are near the NAAQS or only slightly above it. Such a 
decision needs to be made on a case-by-case basis in concert with the 
Regional Office.
    d. A control agency with jurisdiction over one or more areas with 
significant ozone problems should review available ambient air quality 
data to assess whether the problem is likely to be significantly 
impacted by regional transport. \32\ Choice of a modeling approach 
depends on the outcome of this review. In cases where transport is 
considered significant, use of a nested regional model may be the 
preferred approach. If the observed problem is believed to be primarily 
of local origin, use of a model with a single horizontal grid resolution 
and geographical coverage that is less than that of a regional model may 
suffice.
    e. The fine particulate matter NAAQS, promulgated on July 18, 1997, 
includes particles with an aerodynamic diameter nominally less than or 
equal to 2.5 micrometers (PM-2.5). Models for PM-2.5 are needed to 
assess adequacy of a proposed strategy for meeting annual and/or 24-hour 
NAAQS for PM-2.5. PM-2.5 is a mixture consisting of several diverse 
components. Because chemical/physical properties and origins of each 
component differ, it may be appropriate to use either a single model 
capable of addressing several of the important components or to model 
primary and secondary components using different models. Effects of a 
control strategy on PM-2.5 is estimated from the sum of the effects on 
the components composing PM-2.5. Model users may refer to guidance \33\ 
for further details concerning appropriate modeling approaches.
    f. A control agency with jurisdiction over one or more areas with 
PM-2.5 problems should review available ambient air quality data to 
assess which components of PM-2.5 are likely to be major contributors to 
the problem. If it is determined that regional transport of secondary 
particulates, such as sulfates or nitrates, is likely to contribute 
significantly to the problem, use of a regional model may be the 
preferred approach. Otherwise, coverage may be limited to a domain that 
is urban scale or less. Special care

[[Page 503]]

should be taken to select appropriate geographical coverage for a 
modeling application.\33\
    g. The NAAQS for PM-10 was promulgated in July 1987 (40 CFR 50.6). A 
SIP development guide \34\ is available to assist in PM-10 analyses and 
control strategy development. EPA promulgated regulations for PSD 
increments measured as PM-10 in a notice published on June 3, 1993 (40 
CFR 51.166(c)). As an aid to assessing the impact on ambient air quality 
of particulate matter generated from prescribed burning activities, a 
reference \35\ is available.
    h. Models for assessing the impacts of particulate matter may 
involve dispersion models or receptor models, or a combination 
(depending on the circumstances). Receptor models focus on the behavior 
of the ambient environment at the point of impact as opposed to source-
oriented dispersion models, which focus on the transport, diffusion, and 
transformation that begin at the source and continue to the receptor 
site. Receptor models attempt to identify and apportion sources by 
relating known sample compositions at receptors to measured or inferred 
compositions of source emissions. When complete and accurate emission 
inventories or meteorological characterization are unavailable, or 
unknown pollutant sources exist, receptor modeling may be necessary.
    i. Models for assessing the impact of CO emissions are needed for a 
number of different purposes. Examples include evaluating effects of 
point sources, congested intersections and highways, as well as the 
cumulative effect of numerous sources of CO in an urban area.
    j. Models for assessing the impact of sources on ambient 
NO2 concentrations are primarily needed to meet new source 
review requirements, such as addressing the effect of a proposed source 
on PSD increments for annual concentrations of NO2. Impact of 
an individual source on ambient NO2 depends, in part, on the 
chemical environment into which the source's plume is to be emitted. 
There are several approaches for estimating effects of an individual 
source on ambient NO2. One approach is through use of a 
plume-in-grid algorithm imbedded within a photochemical grid model. 
However, because of the rigor and complexity involved, and because this 
approach may not be capable of defining sub-grid concentration 
gradients, the plume-in-grid approach may be impractical for estimating 
effects on an annual PSD increment. A second approach which does not 
have this limitation and accommodates distance-dependent conversion 
ratios--the Plume Volume Molar Ratio Method (PVMRM) \36\--is currently 
being tested to determine suitability as a refined method. A third 
(screening) approach is to develop site specific (domain-wide) 
conversion factors based on measurements. If it is not possible to 
develop site specific conversion factors and use of the plume-in-grid 
algorithm is also not feasible, other screening procedures may be 
considered.
    k. In January 1999 (40 CFR Part 58, Appendix D), EPA gave notice 
that concern about ambient lead impacts was being shifted away from 
roadways and toward a focus on stationary point sources. EPA has also 
issued guidance on siting ambient monitors in the vicinity of such 
sources. \37\ For lead, the SIP should contain an air quality analysis 
to determine the maximum quarterly lead concentration resulting from 
major lead point sources, such as smelters, gasoline additive plants, 
etc. General guidance for lead SIP development is also available. \38\

                           5.2 Recommendations

                         5.2.1 Models for Ozone

    a. Choice of Models for Multi-source Applications. Simulation of 
ozone formation and transport is a highly complex and resource intensive 
exercise. Control agencies with jurisdiction over areas with ozone 
problems are encouraged to use photochemical grid models, such as the 
Models-3/Community Multi-scale Air Quality (CMAQ) modeling system, \39\ 
to evaluate the relationship between precursor species and ozone. 
Judgement on the suitability of a model for a given application should 
consider factors that include use of the model in an attainment test, 
development of emissions and meteorological inputs to the model and 
choice of episodes to model. \32\ Similar models for the 8-hour NAAQS 
and for the 1-hour NAAQS are appropriate.
    b. Choice of Models to Complement Photochemical Grid Models. As 
previously noted, observational models, Lagrangian models, or the 
refined version of the Ozone Isopleth Plotting Program (OZIPR) \40\ may 
be used to help guide choice of strategies to simulate with a 
photochemical grid model and to corroborate results obtained with a grid 
model. Receptor models have also been used to apportion sources of ozone 
precursors (e.g., VOC) in urban domains. EPA has issued guidance \32\ in 
selecting appropriate techniques.
    c. Estimating the Impact of Individual Sources. Choice of methods 
used to assess the impact of an individual source depends on the nature 
of the source and its emissions. Thus, model users should consult with 
the Regional Office to determine the most suitable approach on a case-
by-case basis (subsection 3.2.2).

                   5.2.2 Models for Particulate Matter

                             5.2.2.1 PM-2.5

    a. Choice of Models for Multi-source Applications. Simulation of 
phenomena resulting in high ambient PM-2.5 can be a multi-faceted

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and complex problem resulting from PM-2.5's existence as an aerosol 
mixture. Treating secondary components of PM-2.5, such as sulfates and 
nitrates, can be a highly complex and resource-intensive exercise. 
Control agencies with jurisdiction over areas with secondary PM-2.5 
problems are encouraged to use models which integrate chemical and 
physical processes important in the formation, decay and transport of 
these species (e.g., Models-3/CMAQ \38\ or REMSAD \41\). Primary 
components can be simulated using less resource-intensive techniques. 
Suitability of a modeling approach or mix of modeling approaches for a 
given application requires technical judgement,\33\ as well as 
professional experience in choice of models, use of the model(s) in an 
attainment test, development of emissions and meteorological inputs to 
the model and selection of days to model.
    b. Choice of Analysis Techniques to Complement Air Quality 
Simulation Models. Receptor models may be used to corroborate 
predictions obtained with one or more air quality simulation models. 
They may also be potentially useful in helping to define specific source 
categories contributing to major components of PM-2.5. \33\
    c. Estimating the Impact of Individual Sources. Choice of methods 
used to assess the impact of an individual source depends on the nature 
of the source and its emissions. Thus, model users should consult with 
the Regional Office to determine the most suitable approach on a case-
by-case basis (subsection 3.2.2).

                              5.2.2.2 PM-10

    a. Screening techniques like those identified in subsection 4.2.1 
are applicable to PM-10. Conservative assumptions which do not allow 
removal or transformation are suggested for screening. Thus, it is 
recommended that subjectively determined values for ``half-life'' or 
pollutant decay not be used as a surrogate for particle removal. 
Proportional models (rollback/forward) may not be applied for screening 
analysis, unless such techniques are used in conjunction with receptor 
modeling. \34\
    b. Refined models such as those discussed in subsection 4.2.2 are 
recommended for PM-10. However, where possible, particle size, gas-to-
particle formation, and their effect on ambient concentrations may be 
considered. For point sources of small particles and for source-specific 
analyses of complicated sources, use the appropriate recommended steady-
state plume dispersion model (subsection 4.2.2).
    c. Receptor models have proven useful for helping validate emission 
inventories and for corroborating source-specific impacts estimated by 
dispersion models. The Chemical Mass Balance (CMB) model is useful for 
apportioning impacts from localized sources. \42,43,44\ Other receptor 
models, e.g., the Positive Matrix Factorization (PMF) model \45\ and 
Unmix, \46\ which don't share some of CMB's constraints, have also been 
applied. In regulatory applications, dispersion models have been used in 
conjunction with receptor models to attribute source (or source 
category) contributions. Guidance is available for PM-10 sampling and 
analysis applicable to receptor modeling. \47\
    d. Under certain conditions, recommended dispersion models may not 
be reliable. In such circumstances, the modeling approach should be 
approved by the Regional Office on a case-by-case basis. Analyses 
involving model calculations for stagnation conditions should also be 
justified on a case-by-case basis (subsection 7.2.8).
    e. Fugitive dust usually refers to dust put into the atmosphere by 
the wind blowing over plowed fields, dirt roads or desert or sandy areas 
with little or no vegetation. Reentrained dust is that which is put into 
the air by reason of vehicles driving over dirt roads (or dirty roads) 
and dusty areas. Such sources can be characterized as line, area or 
volume sources. Emission rates may be based on site specific data or 
values from the general literature. Fugitive emissions include the 
emissions resulting from the industrial process that are not captured 
and vented through a stack but may be released from various locations 
within the complex. In some unique cases a model developed specifically 
for the situation may be needed. Due to the difficult nature of 
characterizing and modeling fugitive dust and fugitive emissions, it is 
recommended that the proposed procedure be cleared by the Regional 
Office for each specific situation before the modeling exercise is 
begun.

                    5.2.3 Models for Carbon Monoxide

    a. Guidance is available for analyzing CO impacts at roadway 
intersections. \48\ The recommended screening model for such analyses is 
CAL3QHC. \49,50\ This model combines CALINE3 (listed in Appendix A) with 
a traffic model to calculate delays and queues that occur at signalized 
intersections. The screening approach is described in reference 48; a 
refined approach may be considered on a case-by-case basis with 
CAL3QHCR. \51\ The latest version of the MOBILE (mobile source emission 
factor) model should be used for emissions input to intersection models.
    b. For analyses of highways characterized by uninterrupted traffic 
flows, CALINE3 is recommended, with emissions input from the latest 
version of the MOBILE model. A scientific review article for line source 
models is available. \52\
    c. For urban area wide analyses of CO, an Eulerian grid model should 
be used. Information on SIP development and requirements for using such 
models can be found in several references. \48,53,54,55\

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    d. Where point sources of CO are of concern, they should be treated 
using the screening and refined techniques described in Section 4.

           5.2.4 Models for Nitrogen Dioxide (Annual Average)

    a. A tiered screening approach is recommended to obtain annual 
average estimates of NO2 from point sources for New Source 
Review analysis, including PSD, and for SIP planning purposes. This 
multi-tiered approach is conceptually shown in Figure 5-1 and described 
in paragraphs b through d of this subsection:

                               Figure 5-1

    Multi-tiered screening approach for Estimating Annual NO2 
Concentrations from Point Sources
[GRAPHIC] [TIFF OMITTED] TR09NO05.001

    b. For Tier 1 (the initial screen), use an appropriate model in 
subsection 4.2.2 to estimate the maximum annual average concentration 
and assume a total conversion of NO to NO2. If the 
concentration exceeds the NAAQS and/or PSD increments for 
NO2, proceed to the 2nd level screen.
    c. For Tier 2 (2nd level) screening analysis, multiply the Tier 1 
estimate(s) by an empirically derived NO2/NOX 
value of 0.75 (annual national default). \56\ The reviewing agency may 
establish an alternative default NO2/NOX ratio 
based on ambient annual average NO2 and annual average 
NOX data representative of area wide quasi-equilibrium 
conditions. Alternative default NO2/NOX ratios 
should be based on data satisfying quality assurance procedures that 
ensure data accuracy for both NO2 and NOX within 
the typical range of measured values. In areas with relatively low 
NOX concentrations, the quality assurance procedures used to 
determine compliance with the NO2 national ambient air 
quality standard may not be adequate. In addition, default 
NO2/NOX ratios, including the 0.75 national 
default value, can underestimate long range NO2 impacts and 
should be used with caution in long range transport scenarios.
    d. For Tier 3 (3rd level) analysis, a detailed screening method may 
be selected on a case-by-case basis. For point source modeling, detailed 
screening techniques such as the Ozone Limiting Method \57\ may also be 
considered. Also, a site specific NO2/NOX ratio 
may be used as a detailed screening method if it meets the same 
restrictions as described for alternative default NO2/
NOX ratios. Ambient NOX monitors used to develop a 
site specific ratio should be sited to obtain the NO2 and 
NOX concentrations under quasi-equilibrium conditions. Data 
obtained from monitors sited at the maximum NOX impact site, 
as may be required in a PSD pre-construction monitoring program, likely 
reflect transitional NOX conditions. Therefore, 
NOX data from maximum impact sites may not be suitable for 
determining a site specific NO2/NOX ratio that is 
applicable for the entire modeling analysis. A site specific ratio 
derived from maximum impact data can only be used to estimate 
NO2 impacts at receptors located within the same distance of 
the source as the source-to-monitor distance.
    e. In urban areas (subsection 7.2.3), a proportional model may be 
used as a preliminary assessment to evaluate control strategies to meet 
the NAAQS for multiple minor sources, i.e., minor point, area and mobile 
sources of NOX; concentrations resulting from major point 
sources should be estimated separately as discussed above, then added to 
the impact of the minor sources. An acceptable screening technique for 
urban complexes is to assume that all NOX is emitted in the 
form of NO2 and to use a model from Appendix A for 
nonreactive pollutants to estimate NO2 concentrations. A more 
accurate estimate can be obtained by: (1) Calculating the annual average 
concentrations of NOX with an urban model, and (2) converting 
these estimates to NO2 concentrations using an empirically 
derived annual NO2/NOX ratio. A value of 0.75 is 
recommended for this ratio. However, a spatially averaged alternative 
default annual NO2/NOX ratio may be determined 
from an existing air quality monitoring network and used in lieu of the 
0.75 value if it is determined to be representative of prevailing ratios 
in the urban area by the reviewing agency. To ensure use of appropriate 
locally derived annual average NO2/NOX ratios, 
monitoring data under consideration should be limited to those collected 
at monitors meeting siting criteria defined in 40 CFR Part 58,

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Appendix D as representative of ``neighborhood'', ``urban'', or 
``regional'' scales. Furthermore, the highest annual spatially averaged 
NO2/NOX ratio from the most recent 3 years of 
complete data should be used to foster conservatism in estimated 
impacts.
    f. To demonstrate compliance with NO2 PSD increments in 
urban areas, emissions from major and minor sources should be included 
in the modeling analysis. Point and area source emissions should be 
modeled as discussed above. If mobile source emissions do not contribute 
to localized areas of high ambient NO2 concentrations, they 
should be modeled as area sources. When modeled as area sources, mobile 
source emissions should be assumed uniform over the entire highway link 
and allocated to each area source grid square based on the portion of 
highway link within each grid square. If localized areas of high 
concentrations are likely, then mobile sources should be modeled as line 
sources using an appropriate steady-state plume dispersion model (e.g., 
CAL3QHCR; subsection 5.2.3).
    g. More refined techniques to handle special circumstances may be 
considered on a case-by-case basis and agreement with the appropriate 
reviewing authority (paragraph 3.0(b)) should be obtained. Such 
techniques should consider individual quantities of NO and 
NO2 emissions, atmospheric transport and dispersion, and 
atmospheric transformation of NO to NO2. Where they are 
available, site specific data on the conversion of NO to NO2 
may be used. Photochemical dispersion models, if used for other 
pollutants in the area, may also be applied to the NOX 
problem.

                          5.2.5 Models for Lead

    a. For major lead point sources, such as smelters, which contribute 
fugitive emissions and for which deposition is important, professional 
judgement should be used, and there should be coordination with the 
appropriate reviewing authority (paragraph 3.0(b)). To model an entire 
major urban area or to model areas without significant sources of lead 
emissions, as a minimum a proportional (rollback) model may be used for 
air quality analysis. The rollback philosophy assumes that measured 
pollutant concentrations are proportional to emissions. However, urban 
or other dispersion models are encouraged in these circumstances where 
the use of such models is feasible.
    b. In modeling the effect of traditional line sources (such as a 
specific roadway or highway) on lead air quality, dispersion models 
applied for other pollutants can be used. Dispersion models such as 
CALINE3 and CAL3QHCR have been used for modeling carbon monoxide 
emissions from highways and intersections (subsection 5.2.3). Where 
there is a point source in the middle of a substantial road network, the 
lead concentrations that result from the road network should be treated 
as background (subsection 8.2); the point source and any nearby major 
roadways should be modeled separately using the appropriate recommended 
steady-state plume dispersion model (subsection 4.2.2).

                      6.0 Other Model Requirements

                             6.1 Discussion

    a. This section covers those cases where specific techniques have 
been developed for special regulatory programs. Most of the programs 
have, or will have when fully developed, separate guidance documents 
that cover the program and a discussion of the tools that are needed. 
The following paragraphs reference those guidance documents, when they 
are available. No attempt has been made to provide a comprehensive 
discussion of each topic since the reference documents were designed to 
do that. This section will undergo periodic revision as new programs are 
added and new techniques are developed.
    b. Other Federal agencies have also developed specific modeling 
approaches for their own regulatory or other requirements. \58\ Although 
such regulatory requirements and manuals may have come about because of 
EPA rules or standards, the implementation of such regulations and the 
use of the modeling techniques is under the jurisdiction of the agency 
issuing the manual or directive.
    c. The need to estimate impacts at distances greater than 50km (the 
nominal distance to which EPA considers most steady-state Gaussian plume 
models are applicable) is an important one especially when considering 
the effects from secondary pollutants. Unfortunately, models originally 
available to EPA had not undergone sufficient field evaluation to be 
recommended for general use. Data bases from field studies at mesoscale 
and long range transport distances were limited in detail. This 
limitation was a result of the expense to perform the field studies 
required to verify and improve mesoscale and long range transport 
models. Meteorological data adequate for generating three-dimensional 
wind fields were particularly sparse. Application of models to 
complicated terrain compounds the difficulty of making good assessments 
of long range transport impacts. EPA completed limited evaluation of 
several long range transport (LRT) models against two sets of field data 
and evaluated results. \59\ Based on the results, EPA concluded that 
long range and mesoscale transport models were limited for regulatory 
use to a case-by-case basis. However a more recent series of comparisons 
has been completed for a new model, CALPUFF (Section A.3). Several of 
these field studies involved three-to-four hour releases of tracer gas 
sampled along arcs of receptors at distances greater than

[[Page 507]]

50km downwind. In some cases, short-term concentration sampling was 
available, such that the transport of the tracer puff as it passed the 
arc could be monitored. Differences on the order of 10 to 20 degrees 
were found between the location of the simulated and observed center of 
mass of the tracer puff. Most of the simulated centerline concentration 
maxima along each arc were within a factor of two of those observed. It 
was concluded from these case studies that the CALPUFF dispersion model 
had performed in a reasonable manner, and had no apparent bias toward 
over or under prediction, so long as the transport distance was limited 
to less than 300km. \60\

                           6.2 Recommendations

                            6.2.1 Visibility

    a. Visibility in important natural areas (e.g., Federal Class I 
areas) is protected under a number of provisions of the Clean Air Act, 
including Sections 169A and 169B (addressing impacts primarily from 
existing sources) and Section 165 (new source review). Visibility 
impairment is caused by light scattering and light absorption associated 
with particles and gases in the atmosphere. In most areas of the 
country, light scattering by PM-2.5 is the most significant component of 
visibility impairment. The key components of PM-2.5 contributing to 
visibility impairment include sulfates, nitrates, organic carbon, 
elemental carbon, and crustal material.
    b. The visibility regulations as promulgated in December 1980 (40 
CFR 51.300-307) require States to mitigate visibility impairment, in any 
of the 156 mandatory Federal Class I areas, that is found to be 
``reasonably attributable'' to a single source or a small group of 
sources. In 1985, EPA promulgated Federal Implementation Plans (FIPs) 
for several States without approved visibility provisions in their SIPs. 
The IMPROVE (Interagency Monitoring for Protected Visual Environments) 
monitoring network, a cooperative effort between EPA, the States, and 
Federal land management agencies, was established to implement the 
monitoring requirements in these FIPs. Data has been collected by the 
IMPROVE network since 1988.
    c. In 1999, EPA issued revisions to the 1980 regulations to address 
visibility impairment in the form of regional haze, which is caused by 
numerous, diverse sources (e.g., stationary, mobile, and area sources) 
located across a broad region (40 CFR 51.308-309). The state of relevant 
scientific knowledge has expanded significantly since the Clean Air Act 
Amendments of 1977. A number of studies and reports \61,62\ have 
concluded that long range transport (e.g., up to hundreds of kilometers) 
of fine particulate matter plays a significant role in visibility 
impairment across the country. Section 169A of the Act requires states 
to develop SIPs containing long-term strategies for remedying existing 
and preventing future visibility impairment in 156 mandatory Class I 
federal areas. In order to develop long-term strategies to address 
regional haze, many States will need to conduct regional-scale modeling 
of fine particulate concentrations and associated visibility impairment 
(e.g., light extinction and deciview metrics).
    d. To calculate the potential impact of a plume of specified 
emissions for specific transport and dispersion conditions (``plume 
blight''), a screening model, VISCREEN, and guidance are available. \63\ 
If a more comprehensive analysis is required, a refined model should be 
selected . The model selection (VISCREEN vs. PLUVUE II or some other 
refined model), procedures, and analyses should be determined in 
consultation with the appropriate reviewing authority (paragraph 3.0(b)) 
and the affected Federal Land Manager (FLM). FLMs are responsible for 
determining whether there is an adverse effect by a plume on a Class I 
area.
    e. CALPUFF (Section A.3) may be applied when assessment is needed of 
reasonably attributable haze impairment or atmospheric deposition due to 
one or a small group of sources. This situation may involve more sources 
and larger modeling domains than that to which VISCREEN ideally may be 
applied. The procedures and analyses should be determined in 
consultation with the appropriate reviewing authority (paragraph 3.0(b)) 
and the affected FLM(s).
    f. Regional scale models are used by EPA to develop and evaluate 
national policy and assist State and local control agencies. Two such 
models which can be used to assess visibility impacts from source 
emissions are Models-3/CMAQ \38\ and REMSAD. \41\ Model users should 
consult with the appropriate reviewing authority (paragraph 3.0(b)), 
which in this instance would include FLMs.

              6.2.2 Good Engineering Practice Stack Height

    a. The use of stack height credit in excess of Good Engineering 
Practice (GEP) stack height or credit resulting from any other 
dispersion technique is prohibited in the development of emission 
limitations by 40 CFR 51.118 and 40 CFR 51.164. The definitions of GEP 
stack height and dispersion technique are contained in 40 CFR 51.100. 
Methods and procedures for making the appropriate stack height 
calculations, determining stack height credits and an example of 
applying those techniques are found in several references \64,65,66,67\, 
which provide a great deal of additional information for evaluating and 
describing building cavity and wake effects.
    b. If stacks for new or existing major sources are found to be less 
than the height defined by EPA's refined formula for determining GEP 
height, then air quality impacts

[[Page 508]]

associated with cavity or wake effects due to the nearby building 
structures should be determined. The EPA refined formula height is 
defined as H + 1.5L (see reference 66). Detailed downwash screening 
procedures \24\ for both the cavity and wake regions should be followed. 
If more refined concentration estimates are required, the recommended 
steady-state plume dispersion model in subsection 4.2.2 contains 
algorithms for building wake calculations and should be used.

          6.2.3 Long Range Transport (LRT) (i.e., Beyond 50km)

    a. Section 165(d) of the Clean Air Act requires that suspected 
adverse impacts on PSD Class I areas be determined. However, 50km is the 
useful distance to which most steady-state Gaussian plume models are 
considered accurate for setting emission limits. Since in many cases PSD 
analyses show that Class I areas may be threatened at distances greater 
than 50km from new sources, some procedure is needed to (1) determine if 
an adverse impact will occur, and (2) identify the model to be used in 
setting an emission limit if the Class I increments are threatened. In 
addition to the situations just described, there are certain 
applications containing a mixture of both long range and short range 
source-receptor relationships in a large modeled domain (e.g., several 
industrialized areas located along a river or valley). Historically, 
these applications have presented considerable difficulty to an analyst 
if impacts from sources having transport distances greater than 50km 
significantly contributed to the design concentrations. To properly 
analyze applications of this type, a modeling approach is needed which 
has the capability of combining, in a consistent manner, impacts 
involving both short and long range transport. The CALPUFF modeling 
system, listed in Appendix A, has been designed to accommodate both the 
Class I area LRT situation and the large modeling domain situation. 
Given the judgement and refinement involved, conducting a LRT modeling 
assessment will require significant consultation with the appropriate 
reviewing authority (paragraph 3.0(b)) and the affected FLM(s). The FLM 
has an affirmative responsibility to protect air quality related values 
(AQRVs) that may be affected, and to provide the appropriate procedures 
and analysis techniques. Where there is no increment violation, the 
ultimate decision on whether a Class I area is adversely affected is the 
responsibility of the appropriate reviewing authority (Section 
165(d)(2)(C)(ii) of the Clean Air Act), taking into consideration any 
information on the impacts on AQRVs provided by the FLM. According to 
Section 165(d)(2)(C)(iii) of the Clean Air Act, if there is a Class I 
increment violation, the source must demonstrate to the satisfaction of 
the FLM that the emissions from the source will have no adverse impact 
on the AQRVs.
    b. If LRT is determined to be important, then refined estimates 
utilizing the CALPUFF modeling system should be obtained. A screening 
approach \60,68\ is also available for use on a case-by-case basis that 
generally provides concentrations that are higher than those obtained 
using refined characterizations of the meteorological conditions. The 
meteorological input data requirements for developing the time and space 
varying three-dimensional winds and dispersion meteorology for refined 
analyses are discussed in paragraph 8.3.1.2(d). Additional information 
on applying this model is contained in Appendix A. To facilitate use of 
complex air quality and meteorological modeling systems, a written 
protocol approved by the appropriate reviewing authority (paragraph 
3.0(b)) and the affected FLM(s) may be considered for developing 
consensus in the methods and procedures to be followed.

         6.2.4 Modeling Guidance for Other Governmental Programs

    a. When using the models recommended or discussed in the Guideline 
in support of programmatic requirements not specifically covered by EPA 
regulations, the model user should consult the appropriate Federal or 
State agency to ensure the proper application and use of the models. For 
modeling associated with PSD permit applications that involve a Class I 
area, the appropriate Federal Land Manager should be consulted on all 
modeling questions.
    b. The Offshore and Coastal Dispersion (OCD) model, described in 
Appendix A, was developed by the Minerals Management Service and is 
recommended for estimating air quality impact from offshore sources on 
onshore, flat terrain areas. The OCD model is not recommended for use in 
air quality impact assessments for onshore sources. Sources located on 
or just inland of a shoreline where fumigation is expected should be 
treated in accordance with subsection 7.2.8.
    c. The latest version of the Emissions and Dispersion Modeling 
System (EDMS), was developed and is supported by the Federal Aviation 
Administration (FAA), and is appropriate for air quality assessment of 
primary pollutant impacts at airports or air bases. EDMS has adopted 
AERMOD for treating dispersion. Application of EDMS is intended for 
estimating the collective impact of changes in aircraft operations, 
point source, and mobile source emissions on pollutant concentrations. 
It is not intended for PSD, SIP, or other regulatory air quality 
analyses of point or mobile sources at or peripheral to airport property 
that are unrelated to airport operations. If changes in other than 
aircraft operations are associated with analyses, a model recommended in

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Chapter 4 or 5 should be used. The latest version of EDMS may be 
obtained from FAA at its Web site: http://www.aee.faa.gov/emissions/
edms/edmshome.htm.

                   7.0 General Modeling Considerations

                              7.1 Discussion

    a. This section contains recommendations concerning a number of 
different issues not explicitly covered in other sections of this guide. 
The topics covered here are not specific to any one program or modeling 
area but are common to nearly all modeling analyses for criteria 
pollutants.

                           7.2 Recommendations

       7.2.1 Design Concentrations (See Also Subsection 10.2.3.1)

  7.2.1.1 Design Concentrations for SO2, PM-10, CO, Pb, and 
                             NO2

    a. An air quality analysis for SO2, PM-10, CO, Pb, and 
NO2 is required to determine if the source will (1) cause a 
violation of the NAAQS, or (2) cause or contribute to air quality 
deterioration greater than the specified allowable PSD increment. For 
the former, background concentration (subsection 8.2) should be added to 
the estimated impact of the source to determine the design 
concentration. For the latter, the design concentration includes impact 
from all increment consuming sources.
    b. If the air quality analyses are conducted using the period of 
meteorological input data recommended in subsection 8.3.1.2 (e.g., 5 
years of National Weather Service (NWS) data or at least 1 year of site 
specific data; subsection 8.3.3), then the design concentration based on 
the highest, second-highest short term concentration over the entire 
receptor network for each year modeled or the highest long term average 
(whichever is controlling) should be used to determine emission 
limitations to assess compliance with the NAAQS and PSD increments. For 
the 24-hour PM-10 NAAQS (which is a probabilistic standard)--when 
multiple years are modeled, they collectively represent a single period. 
Thus, if 5 years of NWS data are modeled, then the highest sixth highest 
concentration for the whole period becomes the design value. And in 
general, when n years are modeled, the (n+1)th highest concentration 
over the n-year period is the design value, since this represents an 
average or expected exceedance rate of one per year.
    c. When sufficient and representative data exist for less than a 5-
year period from a nearby NWS site, or when site specific data have been 
collected for less than a full continuous year, or when it has been 
determined that the site specific data may not be temporally 
representative (subsection 8.3.3), then the highest concentration 
estimate should be considered the design value. This is because the 
length of the data record may be too short to assure that the conditions 
producing worst-case estimates have been adequately sampled. The highest 
value is then a surrogate for the concentration that is not to be 
exceeded more than once per year (the wording of the deterministic 
standards). Also, the highest concentration should be used whenever 
selected worst-case conditions are input to a screening technique, as 
described in EPA guidance. \24\
    d. If the controlling concentration is an annual average value and 
multiple years of data (site specific or NWS) are used, then the design 
value is the highest of the annual averages calculated for the 
individual years. If the controlling concentration is a quarterly 
average and multiple years are used, then the highest individual 
quarterly average should be considered the design value.
    e. As long a period of record as possible should be used in making 
estimates to determine design values and PSD increments. If more than 1 
year of site specific data is available, it should be used.

       7.2.1.2 Design Concentrations for O3 and PM-2.5

    a. Guidance and specific instructions for the determination of the 
1-hr and 8-hr design concentrations for ozone are provided in Appendix H 
and I (respectively) of reference 4. Appendix H explains how to 
determine when the expected number of days per calendar year with 
maximum hourly concentrations above the NAAQS is equal to or less than 
1. Appendix I explains the data handling conventions and computations 
necessary for determining whether the 8-hour primary and secondary NAAQS 
are met at an ambient monitoring site. For PM-2.5, Appendix N of 
reference 4, and supplementary guidance,\69\ explain the data handling 
conventions and computations necessary for determining when the annual 
and 24-hour primary and secondary NAAQS are met. For all SIP revisions 
the user should check with the Regional Office to obtain the most recent 
guidance documents and policy memoranda concerning the pollutant in 
question. There are currently no PSD increments for O3 and 
PM-2.5.

                      7.2.2 Critical Receptor Sites

    a. Receptor sites for refined modeling should be utilized in 
sufficient detail to estimate the highest concentrations and possible 
violations of a NAAQS or a PSD increment. In designing a receptor 
network, the emphasis should be placed on receptor resolution and 
location, not total number of receptors. The selection of receptor sites 
should be a case-by-case determination taking into consideration the 
topography, the climatology,

[[Page 510]]

monitor sites, and the results of the initial screening procedure.

                      7.2.3 Dispersion Coefficients

    a. Steady-state Gaussian plume models used in most applications 
should employ dispersion coefficients consistent with those contained in 
the preferred models in Appendix A. Factors such as averaging time, 
urban/rural surroundings (see paragraphs (b)--(f) of this subsection), 
and type of source (point vs. line) may dictate the selection of 
specific coefficients. Coefficients used in some Appendix A models are 
identical to, or at least based on, Pasquill-Gifford coefficients \70\ 
in rural areas and McElroy-Pooler \71\ coefficients in urban areas. A 
key feature of AERMOD's formulation is the use of directly observed 
variables of the boundary layer to parameterize dispersion. \22\
    b. The selection of either rural or urban dispersion coefficients in 
a specific application should follow one of the procedures suggested by 
Irwin \72\ and briefly described in paragraphs (c)--(f) of this 
subsection. These include a land use classification procedure or a 
population based procedure to determine whether the character of an area 
is primarily urban or rural.
    c. Land Use Procedure: (1) Classify the land use within the total 
area, Ao, circumscribed by a 3km radius circle about the 
source using the meteorological land use typing scheme proposed by Auer 
\73\; (2) if land use types I1, I2, C1, R2, and R3 account for 50 
percent or more of Ao, use urban dispersion coefficients; 
otherwise, use appropriate rural dispersion coefficients.
    d. Population Density Procedure: (1) Compute the average population 
density, p per square kilometer with Ao as defined above; (2) 
If p is greater than 750 people/km2, use urban dispersion 
coefficients; otherwise use appropriate rural dispersion coefficients.
    e. Of the two methods, the land use procedure is considered more 
definitive. Population density should be used with caution and should 
not be applied to highly industrialized areas where the population 
density may be low and thus a rural classification would be indicated, 
but the area is sufficiently built-up so that the urban land use 
criteria would be satisfied. In this case, the classification should 
already be ``urban'' and urban dispersion parameters should be used.
    f. Sources located in an area defined as urban should be modeled 
using urban dispersion parameters. Sources located in areas defined as 
rural should be modeled using the rural dispersion parameters. For 
analyses of whole urban complexes, the entire area should be modeled as 
an urban region if most of the sources are located in areas classified 
as urban.
    g. Buoyancy-induced dispersion (BID), as identified by Pasquill 
\74\, is included in the preferred models and should be used where 
buoyant sources, e.g., those involving fuel combustion, are involved.

                       7.2.4 Stability Categories

    a. The Pasquill approach to classifying stability is commonly used 
in preferred models (Appendix A). The Pasquill method, as modified by 
Turner \75\, was developed for use with commonly observed meteorological 
data from the National Weather Service and is based on cloud cover, 
insolation and wind speed.
    b. Procedures to determine Pasquill stability categories from other 
than NWS data are found in subsection 8.3. Any other method to determine 
Pasquill stability categories must be justified on a case-by-case basis.
    c. For a given model application where stability categories are the 
basis for selecting dispersion coefficients, both [sigma]y 
and [sigma]z should be determined from the same stability 
category. ``Split sigmas'' in that instance are not recommended. Sector 
averaging, which eliminates the [sigma]y term, is commonly 
acceptable in complex terrain screening methods.
    d. AERMOD, also a preferred model in Appendix A, uses a planetary 
boundary layer scaling parameter to characterize stability. \22\ This 
approach represents a departure from the discrete, hourly stability 
categories estimated under the Pasquill-Gifford-Turner scheme.

                            7.2.5 Plume Rise

    a. The plume rise methods of Briggs \76,77\ are incorporated in many 
of the preferred models and are recommended for use in many modeling 
applications. In AERMOD, \22\ for the stable boundary layer, plume rise 
is estimated using an iterative approach, similar to that in the 
CTDMPLUS model. In the convective boundary layer, plume rise is 
superposed on the displacements by random convective velocities. \78\ In 
AERMOD, plume rise is computed using the methods of Briggs excepting 
cases involving building downwash, in which a numerical solution of the 
mass, energy, and momentum conservation laws is performed. \23\ No 
explicit provisions in these models are made for multistack plume rise 
enhancement or the handling of such special plumes as flares; these 
problems should be considered on a case-by-case basis.
    b. Gradual plume rise is generally recommended where its use is 
appropriate: (1) In AERMOD; (2) in complex terrain screening procedures 
to determine close-in impacts and (3) when calculating the effects of 
building wakes. The building wake algorithm in AERMOD incorporates and 
exercises the thermodynamically based gradual plume rise calculations as 
described in (a) above. If the building wake is calculated to affect the 
plume for any hour, gradual plume rise is

[[Page 511]]

also used in downwind dispersion calculations to the distance of final 
plume rise, after which final plume rise is used. Plumes captured by the 
near wake are re-emitted to the far wake as a ground-level volume 
source.
    c. Stack tip downwash generally occurs with poorly constructed 
stacks and when the ratio of the stack exit velocity to wind speed is 
small. An algorithm developed by Briggs \77\ is the recommended 
technique for this situation and is used in preferred models for point 
sources.

                      7.2.6 Chemical Transformation

    a. The chemical transformation of SO2 emitted from point 
sources or single industrial plants in rural areas is generally assumed 
to be relatively unimportant to the estimation of maximum concentrations 
when travel time is limited to a few hours. However, in urban areas, 
where synergistic effects among pollutants are of considerable 
consequence, chemical transformation rates may be of concern. In urban 
area applications, a half-life of 4 hours \75\ may be applied to the 
analysis of SO2 emissions. Calculations of transformation 
coefficients from site specific studies can be used to define a ``half-
life'' to be used in a steady-state Gaussian plume model with any travel 
time, or in any application, if appropriate documentation is provided. 
Such conversion factors for pollutant half-life should not be used with 
screening analyses.
    b. Use of models incorporating complex chemical mechanisms should be 
considered only on a case-by-case basis with proper demonstration of 
applicability. These are generally regional models not designed for the 
evaluation of individual sources but used primarily for region-wide 
evaluations. Visibility models also incorporate chemical transformation 
mechanisms which are an integral part of the visibility model itself and 
should be used in visibility assessments.

               7.2.7 Gravitational Settling and Deposition

    a. An ``infinite half-life'' should be used for estimates of 
particle concentrations when steady-state Gaussian plume models 
containing only exponential decay terms for treating settling and 
deposition are used.
    b. Gravitational settling and deposition may be directly included in 
a model if either is a significant factor. When particulate matter 
sources can be quantified and settling and dry deposition are problems, 
professional judgement should be used, and there should be coordination 
with the appropriate reviewing authority (paragraph 3.0(b)).

                           7.2.8 Complex Winds

    a. Inhomogeneous Local Winds. In many parts of the United States, 
the ground is neither flat nor is the ground cover (or land use) 
uniform. These geographical variations can generate local winds and 
circulations, and modify the prevailing ambient winds and circulations. 
Geographic effects are most apparent when the ambient winds are light or 
calm. \79\ In general these geographically induced wind circulation 
effects are named after the source location of the winds, e.g., lake and 
sea breezes, and mountain and valley winds. In very rugged hilly or 
mountainous terrain, along coastlines, or near large land use 
variations, the characterization of the winds is a balance of various 
forces, such that the assumptions of steady-state straight-line 
transport both in time and space are inappropriate. In the special cases 
described, the CALPUFF modeling system (described in Appendix A) may be 
applied on a case-by-case basis for air quality estimates in such 
complex non-steady-state meteorological conditions. The purpose of 
choosing a modeling system like CALPUFF is to fully treat the time and 
space variations of meteorology effects on transport and dispersion. The 
setup and application of the model should be determined in consultation 
with the appropriate reviewing authority (paragraph 3.0(b)) consistent 
with limitations of paragraph 3.2.2(e). The meteorological input data 
requirements for developing the time and space varying three-dimensional 
winds and dispersion meteorology for these situations are discussed in 
paragraphs 8.3.1.2(d) and 8.3.1.2(f). Examples of inhomogeneous winds 
include, but aren't limited to, situations described in the following 
paragraphs (i)--(iii):
    i. Inversion Breakup Fumigation. Inversion breakup fumigation occurs 
when a plume (or multiple plumes) is emitted into a stable layer of air 
and that layer is subsequently mixed to the ground through convective 
transfer of heat from the surface or because of advection to less stable 
surroundings. Fumigation may cause excessively high concentrations but 
is usually rather short-lived at a given receptor. There are no 
recommended refined techniques to model this phenomenon. There are, 
however, screening procedures \24\ that may be used to approximate the 
concentrations. Considerable care should be exercised in using the 
results obtained from the screening techniques.
    ii. Shoreline Fumigation. Fumigation can be an important phenomenon 
on and near the shoreline of bodies of water. This can affect both 
individual plumes and area-wide emissions. When fumigation conditions 
are expected to occur from a source or sources with tall stacks located 
on or just inland of a shoreline, this should be addressed in the air 
quality modeling analysis. The Shoreline Dispersion Model (SDM) listed 
on EPA's Internet SCRAM Web site (subsection 2.3) may be applied on a 
case-by-case basis when air quality estimates under shoreline fumigation 
conditions are needed. \80\ Information

[[Page 512]]

on the results of EPA's evaluation of this model together with other 
coastal fumigation models is available.\81\ Selection of the appropriate 
model for applications where shoreline fumigation is of concern should 
be determined in consultation with the appropriate reviewing authority 
(paragraph 3.0(b)).
    iii. Stagnation. Stagnation conditions are characterized by calm or 
very low wind speeds, and variable wind directions. These stagnant 
meteorological conditions may persist for several hours to several days. 
During stagnation conditions, the dispersion of air pollutants, 
especially those from low-level emissions sources, tends to be 
minimized, potentially leading to relatively high ground-level 
concentrations. If point sources are of interest, users should note the 
guidance provided for CALPUFF in paragraph (a) of this subsection. 
Selection of the appropriate model for applications where stagnation is 
of concern should be determined in consultation with the appropriate 
reviewing authority (paragraph 3.0(b)).

                       7.2.9 Calibration of Models

    a. Calibration of models is not common practice and is subject to 
much error and misunderstanding. There have been attempts by some to 
compare model estimates and measurements on an event-by-event basis and 
then to calibrate a model with results of that comparison. This approach 
is severely limited by uncertainties in both source and meteorological 
data and therefore it is difficult to precisely estimate the 
concentration at an exact location for a specific increment of time. 
Such uncertainties make calibration of models of questionable benefit. 
Therefore, model calibration is unacceptable.

                          8.0 Model Input Data

    a. Data bases and related procedures for estimating input parameters 
are an integral part of the modeling procedure. The most appropriate 
data available should always be selected for use in modeling analyses. 
Concentrations can vary widely depending on the source data or 
meteorological data used. Input data are a major source of uncertainties 
in any modeling analysis. This section attempts to minimize the 
uncertainty associated with data base selection and use by identifying 
requirements for data used in modeling. A checklist of input data 
requirements for modeling analyses is posted on EPA's Internet SCRAM Web 
site (subsection 2.3). More specific data requirements and the format 
required for the individual models are described in detail in the users' 
guide for each model.

                             8.1 Source Data

                            8.1.1 Discussion

    a. Sources of pollutants can be classified as point, line and area/
volume sources. Point sources are defined in terms of size and may vary 
between regulatory programs. The line sources most frequently considered 
are roadways and streets along which there are well-defined movements of 
motor vehicles, but they may be lines of roof vents or stacks such as in 
aluminum refineries. Area and volume sources are often collections of a 
multitude of minor sources with individually small emissions that are 
impractical to consider as separate point or line sources. Large area 
sources are typically treated as a grid network of square areas, with 
pollutant emissions distributed uniformly within each grid square.
    b. Emission factors are compiled in an EPA publication commonly 
known as AP-42; \82\ an indication of the quality and amount of data on 
which many of the factors are based is also provided. Other information 
concerning emissions is available in EPA publications relating to 
specific source categories. The appropriate reviewing authority 
(paragraph 3.0(b)) should be consulted to determine appropriate source 
definitions and for guidance concerning the determination of emissions 
from and techniques for modeling the various source types.

                          8.1.2 Recommendations

    a. For point source applications the load or operating condition 
that causes maximum ground-level concentrations should be established. 
As a minimum, the source should be modeled using the design capacity 
(100 percent load). If a source operates at greater than design capacity 
for periods that could result in violations of the standards or PSD 
increments, this load) \a\ should be modeled. Where the source operates 
at substantially less than design capacity, and the changes in the stack 
parameters associated with the operating conditions could lead to higher 
ground level concentrations, loads such as 50 percent and 75 percent of 
capacity should also be modeled. A range of operating conditions should 
be considered in screening analyses; the load causing the highest 
concentration, in addition to the design load, should be included in 
refined modeling. For a steam power plant, the following (b-h) is 
typical of

[[Page 513]]

the kind of data on source characteristics and operating conditions that 
may be needed. Generally, input data requirements for air quality models 
necessitate the use of metric units; where English units are common for 
engineering usage, a conversion to metric is required.
---------------------------------------------------------------------------

    \a\ Malfunctions which may result in excess emissions are not 
considered to be a normal operating condition. They generally should not 
be considered in determining allowable emissions. However, if the excess 
emissions are the result of poor maintenance, careless operation, or 
other preventable conditions, it may be necessary to consider them in 
determining source impact.
---------------------------------------------------------------------------

    b. Plant layout. The connection scheme between boilers and stacks, 
and the distance and direction between stacks, building parameters 
(length, width, height, location and orientation relative to stacks) for 
plant structures which house boilers, control equipment, and surrounding 
buildings within a distance of approximately five stack heights.
    c. Stack parameters. For all stacks, the stack height and inside 
diameter (meters), and the temperature (K) and volume flow rate (actual 
cubic meters per second) or exit gas velocity (meters per second) for 
operation at 100 percent, 75 percent and 50 percent load.
    d. Boiler size. For all boilers, the associated megawatts, 10\6\ 
BTU/hr, and pounds of steam per hour, and the design and/or actual fuel 
consumption rate for 100 percent load for coal (tons/hour), oil 
(barrels/hour), and natural gas (thousand cubic feet/hour).
    e. Boiler parameters. For all boilers, the percent excess air used, 
the boiler type (e.g., wet bottom, cyclone, etc.), and the type of 
firing (e.g., pulverized coal, front firing, etc.).
    f. Operating conditions. For all boilers, the type, amount and 
pollutant contents of fuel, the total hours of boiler operation and the 
boiler capacity factor during the year, and the percent load for peak 
conditions.
    g. Pollution control equipment parameters. For each boiler served 
and each pollutant affected, the type of emission control equipment, the 
year of its installation, its design efficiency and mass emission rate, 
the date of the last test and the tested efficiency, the number of hours 
of operation during the latest year, and the best engineering estimate 
of its projected efficiency if used in conjunction with coal combustion; 
data for any anticipated modifications or additions.
    h. Data for new boilers or stacks. For all new boilers and stacks 
under construction and for all planned modifications to existing boilers 
or stacks, the scheduled date of completion, and the data or best 
estimates available for items (b) through (g) of this subsection 
following completion of construction or modification.
    i. In stationary point source applications for compliance with short 
term ambient standards, SIP control strategies should be tested using 
the emission input shown on Table 8-1. When using a refined model, 
sources should be modeled sequentially with these loads for every hour 
of the year. To evaluate SIPs for compliance with quarterly and annual 
standards, emission input data shown in Table 8-1 should again be used. 
Emissions from area sources should generally be based on annual average 
conditions. The source input information in each model user's guide 
should be carefully consulted and the checklist (paragraph 8.0(a)) 
should also be consulted for other possible emission data that could be 
helpful. NAAQS compliance demonstrations in a PSD analysis should follow 
the emission input data shown in Table 8-2. For purposes of emissions 
trading, new source review and demonstrations, refer to current EPA 
policy and guidance to establish input data.
    j. Line source modeling of streets and highways requires data on the 
width of the roadway and the median strip, the types and amounts of 
pollutant emissions, the number of lanes, the emissions from each lane 
and the height of emissions. The location of the ends of the straight 
roadway segments should be specified by appropriate grid coordinates. 
Detailed information and data requirements for modeling mobile sources 
of pollution are provided in the user's manuals for each of the models 
applicable to mobile sources.
    k. The impact of growth on emissions should be considered in all 
modeling analyses covering existing sources. Increases in emissions due 
to planned expansion or planned fuel switches should be identified. 
Increases in emissions at individual sources that may be associated with 
a general industrial/commercial/residential expansion in multi-source 
urban areas should also be treated. For new sources the impact of growth 
on emissions should generally be considered for the period prior to the 
start-up date for the source. Such changes in emissions should treat 
increased area source emissions, changes in existing point source 
emissions which were not subject to preconstruction review, and 
emissions due to sources with permits to construct that have not yet 
started operation.

[[Page 514]]



                           Table 8-1--Model Emission Input Data for Point Sources \1\
----------------------------------------------------------------------------------------------------------------
                                        Emission limit             Operating level            Operating factor
          Averaging time             (/MMBtu) \2\   x      (MMBtu/hr) \2\      x  (e.g., hr/yr, hr/day)
----------------------------------------------------------------------------------------------------------------
  Stationary Point Source(s) Subject to SIP Emission Limit(s) Evaluation for Compliance with Ambient Standards
                                       (Including Areawide Demonstrations)
----------------------------------------------------------------------------------------------------------------
Annual & quarterly................  Maximum allowable       ..  Actual or design       ..  Actual operating
                                     emission limit or           capacity (whichever        factor averaged over
                                     federally enforceable       is greater), or            most recent 2
                                     permit limit.               federally                  years.\3\
                                                                 enforceable permit
                                                                 condition.
Short term........................  Maximum allowable       ..  Actual or design       ..  Continuous operation,
                                     emission limit or           capacity (whichever        i.e., all hours of
                                     federally enforceable       is greater), or            each time period
                                     permit limit.               federally                  under consideration
                                                                 enforceable permit         (for all hours of
                                                                 condition.\4\              the meteorological
                                                                                            data base). \5\
----------------------------------------------------------------------------------------------------------------
                                             Nearby Source(s) \6,7\
                        Same input requirements as for stationary point source(s) above.
----------------------------------------------------------------------------------------------------------------
                                               Other Source(s) \7\
                    If modeled (subsection 8.2.3), input data requirements are defined below.
----------------------------------------------------------------------------------------------------------------
Annual & quarterly................  Maximum allowable       ..  Annual level when      ..  Actual operating
                                     emission limit or           actually operating,        factor averaged over
                                     federally enforceable       averaged over the          the most recent 2
                                     permit limit. \6\           most recent 2 years.       years. \3\
                                                                 \3\
Short term........................  Maximum allowable       ..  Annual level when      ..  Continuous operation,
                                     emission limit or           actually operating,        i.e., all hours of
                                     federally enforceable       averaged over the          each time period
                                     permit limit. \6\           most recent 2 years.       under consideration
                                                                 \3\                        (for all hours of
                                                                                            the meteorological
                                                                                            data base). \5\
----------------------------------------------------------------------------------------------------------------
\1\ The model input data requirements shown on this table apply to stationary source control strategies for
  STATE IMPLEMENTATION PLANS. For purposes of emissions trading, new source review, or prevention of significant
  deterioration, other model input criteria may apply. Refer to the policy and guidance for these programs to
  establish the input data.
\2\ Terminology applicable to fuel burning sources; analogous terminology (e.g., /throughput) may be
  used for other types of sources.
\3\ Unless it is determined that this period is not representative.
\4\ Operating levels such as 50 percent and 75 percent of capacity should also be modeled to determine the load
  causing the highest concentration.
\5\ If operation does not occur for all hours of the time period of consideration (e.g., 3 or 24 hours) and the
  source operation is constrained by a federally enforceable permit condition, an appropriate adjustment to the
  modeled emission rate may be made (e.g., if operation is only 8 a.m. to 4 p.m. each day, only these hours will
  be modeled with emissions from the source. Modeled emissions should not be averaged across non-operating time
  periods.)
\6\ See paragraph 8.2.3(c).
\7\ See paragraph 8.2.3(d).


          TABLE 8-2--Point Source Model Emission Input Data for NAAQS Compliance in PSD Demonstrations
----------------------------------------------------------------------------------------------------------------
                                        Emission limit             Operating level            Operating factor
          Averaging time             (/MMBtu) \1\   x      (MMBtu/hr) \1\      x  (e.g., hr/yr, hr/day)
----------------------------------------------------------------------------------------------------------------
                                      Proposed Major New or Modified Source
----------------------------------------------------------------------------------------------------------------
Annual & quarterly................  Maximum allowable       ..  Design capacity or     ..  Continuous operation
                                     emission limit or           federally                  (i.e., 8760 hours).
                                     federally enforceable       enforceable permit         \2\
                                     permit limit.               condition.
Short term (<= 24 hours)..........  Maximum allowable       ..  Design capacity or     ..   Continuous
                                     emission limit or           federally                  operation, i.e., all
                                     federally enforceable       enforceable permit         hours of each time
                                     permit limit.               condition.\3\              period under
                                                                                            consideration (for
                                                                                            all hours of the
                                                                                            meteorological data
                                                                                            base). \2\
----------------------------------------------------------------------------------------------------------------
                                             Nearby Source(s) \4,6\
----------------------------------------------------------------------------------------------------------------
Annual & quarterly................  Maximum allowable       ..  Actual or design       ..  Actual operating
                                     emission limit or           capacity (whichever        factor averaged over
                                     federally enforceable       is greater), or            the most recent 2
                                     permit limit. \5\           federally                  years. 7,8
                                                                 enforceable permit
                                                                 condition.

[[Page 515]]

 
Short term (<= 24 hours)..........  Maximum allowable       ..  Actual or design       ..  Continuous operation,
                                     emission limit or           capacity (whichever        i.e., all hours of
                                     federally enforceable       is greater), or            each time period
                                     permit limit. \5\           federally                  under consideration
                                                                 enforceable permit         (for all hours of
                                                                 condition. \3\             the meteorological
                                                                                            data base). \2\
----------------------------------------------------------------------------------------------------------------
                                              Other Source(s) \6,9\
----------------------------------------------------------------------------------------------------------------
Annual & quarterly................  Maximum allowable       ..  Annual level when      ..  Actual operating
                                     emission limit or           actually operating,        factor averaged over
                                     federally enforceable       averaged over the          the most recent 2
                                     permit limit. \5\           most recent 2 years.       years. 7,8
                                                                 \7\
Short term (<= 24 hours)..........  Maximum allowable       ..  Annual level when      ..  Continuous operation,
                                     emission limit or           actually operating,        i.e., all hours of
                                     federally enforceable       averaged over the          each time period
                                     permit limit. \5\           most recent 2 years.       under consideration
                                                                 \7\                        (for all hours of
                                                                                            the meteorological
                                                                                            data base). \2\
----------------------------------------------------------------------------------------------------------------
\1\ Terminology applicable to fuel burning sources; analogous terminology (e.g., /throughput) may be
  used for other types of sources.
\2\ If operation does not occur for all hours of the time period of consideration (e.g., 3 or 24 hours) and the
  source operation is constrained by a federally enforceable permit condition, an appropriate adjustment to the
  modeled emission rate may be made (e.g., if operation is only 8 a.m. to 4 p.m. each day, only these hours will
  be modeled with emissions from the source. Modeled emissions should not be averaged across non-operating time
  periods.
\3\ Operating levels such as 50 percent and 75 percent of capacity should also be modeled to determine the load
  causing the highest concentration.
\4\ Includes existing facility to which modification is proposed if the emissions from the existing facility
  will not be affected by the modification. Otherwise use the same parameters as for major modification.
\5\ See paragraph 8.2.3(c).
\6\ See paragraph 8.2.3(d).
\7\ Unless it is determined that this period is not representative.
\8\ For those permitted sources not in operation or that have not established an appropriate factor, continuous
  operation (i.e., 8760) should be used.
\9\ Generally, the ambient impacts from non-nearby (background) sources can be represented by air quality data
  unless adequate data do not exist.

                      8.2 Background Concentrations

                            8.2.1 Discussion

    a. Background concentrations are an essential part of the total air 
quality concentration to be considered in determining source impacts. 
Background air quality includes pollutant concentrations due to: (1) 
Natural sources; (2) nearby sources other than the one(s) currently 
under consideration; and (3) unidentified sources.
    b. Typically, air quality data should be used to establish 
background concentrations in the vicinity of the source(s) under 
consideration. The monitoring network used for background determinations 
should conform to the same quality assurance and other requirements as 
those networks established for PSD purposes. \83\ An appropriate data 
validation procedure should be applied to the data prior to use.
    c. If the source is not isolated, it may be necessary to use a 
multi-source model to establish the impact of nearby sources. Since 
sources don't typically operate at their maximum allowable capacity 
(which may include the use of ``dirtier'' fuels), modeling is necessary 
to express the potential contribution of background sources, and this 
impact would not be captured via monitoring. Background concentrations 
should be determined for each critical (concentration) averaging time.

             8.2.2 Recommendations (Isolated Single Source)

    a. Two options (paragraph (b) or (c) of this section) are available 
to determine the background concentration near isolated sources.
    b. Use air quality data collected in the vicinity of the source to 
determine the background concentration for the averaging times of 
concern. Determine the mean background concentration at each monitor by 
excluding values when the source in question is impacting the monitor. 
The mean annual background is the average of the annual concentrations 
so determined at each monitor. For shorter averaging periods, the 
meteorological conditions accompanying the concentrations of concern 
should be identified. Concentrations for meteorological conditions of 
concern, at monitors not impacted by the source in question, should be 
averaged for each separate averaging time to determine the average 
background value. Monitoring sites inside a 90[deg] sector downwind of 
the source may be used to determine the area of impact. One hour 
concentrations may

[[Page 516]]

be added and averaged to determine longer averaging periods.
    c. If there are no monitors located in the vicinity of the source, a 
``regional site'' may be used to determine background. A ``regional 
site'' is one that is located away from the area of interest but is 
impacted by similar natural and distant man-made sources.

               8.2.3 Recommendations (Multi-Source Areas)

    a. In multi-source areas, two components of background should be 
determined: contributions from nearby sources and contributions from 
other sources.
    b. Nearby Sources: All sources expected to cause a significant 
concentration gradient in the vicinity of the source or sources under 
consideration for emission limit(s) should be explicitly modeled. The 
number of such sources is expected to be small except in unusual 
situations. Owing to both the uniqueness of each modeling situation and 
the large number of variables involved in identifying nearby sources, no 
attempt is made here to comprehensively define this term. Rather, 
identification of nearby sources calls for the exercise of professional 
judgement by the appropriate reviewing authority (paragraph 3.0(b)). 
This guidance is not intended to alter the exercise of that judgement or 
to comprehensively define which sources are nearby sources.
    c. For compliance with the short-term and annual ambient standards, 
the nearby sources as well as the primary source(s) should be evaluated 
using an appropriate Appendix A model with the emission input data shown 
in Table 8-1 or 8-2. When modeling a nearby source that does not have a 
permit and the emission limit contained in the SIP for a particular 
source category is greater than the emissions possible given the 
source's maximum physical capacity to emit, the ``maximum allowable 
emission limit'' for such a nearby source may be calculated as the 
emission rate representative of the nearby source's maximum physical 
capacity to emit, considering its design specifications and allowable 
fuels and process materials. However, the burden is on the permit 
applicant to sufficiently document what the maximum physical capacity to 
emit is for such a nearby source.
    d. It is appropriate to model nearby sources only during those times 
when they, by their nature, operate at the same time as the primary 
source(s) being modeled. Where a primary source believes that a nearby 
source does not, by its nature, operate at the same time as the primary 
source being modeled, the burden is on the primary source to demonstrate 
to the satisfaction of the appropriate reviewing authority (paragraph 
3.0(b)) that this is, in fact, the case. Whether or not the primary 
source has adequately demonstrated that fact is a matter of professional 
judgement left to the discretion of the appropriate reviewing authority. 
The following examples illustrate two cases in which a nearby source may 
be shown not to operate at the same time as the primary source(s) being 
modeled. Some sources are only used during certain seasons of the year. 
Those sources would not be modeled as nearby sources during times in 
which they do not operate. Similarly, emergency backup generators that 
never operate simultaneously with the sources that they back up would 
not be modeled as nearby sources. To reiterate, in these examples and 
other appropriate cases, the burden is on the primary source being 
modeled to make the appropriate demonstration to the satisfaction of the 
appropriate reviewing authority.
    e. The impact of the nearby sources should be examined at locations 
where interactions between the plume of the point source under 
consideration and those of nearby sources (plus natural background) can 
occur. Significant locations include: (1) the area of maximum impact of 
the point source; (2) the area of maximum impact of nearby sources; and 
(3) the area where all sources combine to cause maximum impact. These 
locations may be identified through trial and error analyses.
    f. Other Sources: That portion of the background attributable to all 
other sources (e.g., natural sources, minor sources and distant major 
sources) should be determined by the procedures found in subsection 
89.2.2 or by application of a model using Table 8-1 or 8-2.

                      8.3 Meteorological Input Data

    a. The meteorological data used as input to a dispersion model 
should be selected on the basis of spatial and climatological (temporal) 
representativeness as well as the ability of the individual parameters 
selected to characterize the transport and dispersion conditions in the 
area of concern. The representativeness of the data is dependent on: (1) 
The proximity of the meteorological monitoring site to the area under 
consideration; (2) the complexity of the terrain; (3) the exposure of 
the meteorological monitoring site; and (4) the period of time during 
which data are collected. The spatial representativeness of the data can 
be adversely affected by large distances between the source and 
receptors of interest and the complex topographic characteristics of the 
area. Temporal representativeness is a function of the year-to-year 
variations in weather conditions. Where appropriate, data 
representativeness should be viewed in terms of the appropriateness of 
the data for constructing realistic boundary layer profiles and three 
dimensional meteorological fields, as described in paragraphs (c) and 
(d) below.
    b. Model input data are normally obtained either from the National 
Weather Service or

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as part of a site specific measurement program. Local universities, 
Federal Aviation Administration (FAA), military stations, industry and 
pollution control agencies may also be sources of such data. Some 
recommendations for the use of each type of data are included in this 
subsection.
    c. Regulatory application of AERMOD requires careful consideration 
of minimum data for input to AERMET. Data representativeness, in the 
case of AERMOD, means utilizing data of an appropriate type for 
constructing realistic boundary layer profiles. Of paramount importance 
is the requirement that all meteorological data used as input to AERMOD 
must be both laterally and vertically representative of the transport 
and dispersion within the analysis domain. Where surface conditions vary 
significantly over the analysis domain, the emphasis in assessing 
representativeness should be given to adequate characterization of 
transport and dispersion between the source(s) of concern and areas 
where maximum design concentrations are anticipated to occur. The 
representativeness of data that were collected off-site should be 
judged, in part, by comparing the surface characteristics in the 
vicinity of the meteorological monitoring site with the surface 
characteristics that generally describe the analysis domain. The surface 
characteristics input to AERMET should be based on the topographic 
conditions in the vicinity of the meteorological tower. Furthermore, 
since the spatial scope of each variable could be different, 
representativeness should be judged for each variable separately. For 
example, for a variable such as wind direction, the data may need to be 
collected very near plume height to be adequately representative, 
whereas, for a variable such as temperature, data from a station several 
kilometers away from the source may in some cases be considered to be 
adequately representative.
    d. For long range transport modeling assessments (subsection 6.2.3) 
or for assessments where the transport winds are complex and the 
application involves a non-steady-state dispersion model (subsection 
7.2.8), use of output from prognostic mesoscale meteorological models is 
encouraged. \84,85,86\ Some diagnostic meteorological processors are 
designed to appropriately blend available NWS comparable meteorological 
observations, local site specific meteorological observations, and 
prognostic mesoscale meteorological data, using empirical relationships, 
to diagnostically adjust the wind field for mesoscale and local-scale 
effects. These diagnostic adjustments can sometimes be improved through 
the use of strategically placed site specific meteorological 
observations. The placement of these special meteorological observations 
(often more than one location is needed) involves expert judgement, and 
is specific to the terrain and land use of the modeling domain. 
Acceptance for use of output from prognostic mesoscale meteorological 
models is contingent on concurrence by the appropriate reviewing 
authorities (paragraph 3.0(b)) that the data are of acceptable quality, 
which can be demonstrated through statistical comparisons with 
observations of winds aloft and at the surface at several appropriate 
locations.

              8.3.1 Length of Record of Meteorological Data

                           8.3.1.1 Discussion

    a. The model user should acquire enough meteorological data to 
ensure that worst-case meteorological conditions are adequately 
represented in the model results. The trend toward statistically based 
standards suggests a need for all meteorological conditions to be 
adequately represented in the data set selected for model input. The 
number of years of record needed to obtain a stable distribution of 
conditions depends on the variable being measured and has been estimated 
by Landsberg and Jacobs \87\ for various parameters. Although that study 
indicates in excess of 10 years may be required to achieve stability in 
the frequency distributions of some meteorological variables, such long 
periods are not reasonable for model input data. This is due in part to 
the fact that hourly data in model input format are frequently not 
available for such periods and that hourly calculations of concentration 
for long periods may be prohibitively expensive. Another study \88\ 
compared various periods from a 17-year data set to determine the 
minimum number of years of data needed to approximate the concentrations 
modeled with a 17-year period of meteorological data from one station. 
This study indicated that the variability of model estimates due to the 
meteorological data input was adequately reduced if a 5-year period of 
record of meteorological input was used.

                         8.3.1.2 Recommendations

    a. Five years of representative meteorological data should be used 
when estimating concentrations with an air quality model. Consecutive 
years from the most recent, readily available 5-year period are 
preferred. The meteorological data should be adequately representative, 
and may be site specific or from a nearby NWS station. Where 
professional judgment indicates NWS-collected ASOS (automated surface 
observing stations) data are inadequate {for cloud cover 
observations{time} , the most recent 5 years of NWS data that are 
observer-based may be considered for use.
    b. The use of 5 years of NWS meteorological data or at least l year 
of site specific

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data is required. If one year or more (including partial years), up to 
five years, of site specific data is available, these data are preferred 
for use in air quality analyses. Such data should have been subjected to 
quality assurance procedures as described in subsection 8.3.3.2.
    c. For permitted sources whose emission limitations are based on a 
specific year of meteorological data, that year should be added to any 
longer period being used (e.g., 5 years of NWS data) when modeling the 
facility at a later time.
    d. For LRT situations (subsection 6.2.3) and for complex wind 
situations (paragraph 7.2.8(a)), if only NWS or comparable standard 
meteorological observations are employed, five years of meteorological 
data (within and near the modeling domain) should be used. Consecutive 
years from the most recent, readily available 5-year period are 
preferred. Less than five, but at least three, years of meteorological 
data (need not be consecutive) may be used if mesoscale meteorological 
fields are available, as discussed in paragraph 8.3(d). These mesoscale 
meteorological fields should be used in conjunction with available 
standard NWS or comparable meteorological observations within and near 
the modeling domain.
    e. For solely LRT applications (subsection 6.2.3), if site specific 
meteorological data are available, these data may be helpful when used 
in conjunction with available standard NWS or comparable observations 
and mesoscale meteorological fields as described in paragraph 
8.3.1.2(d).
    f. For complex wind situations (paragraph 7.2.8(a)) where site 
specific meteorological data are being relied upon as the basis for 
characterizing the meteorological conditions, a data base of at least 1 
full-year of meteorological data is required. If more data are 
available, they should be used. Site specific meteorological data may 
have to be collected at multiple locations. Such data should have been 
subjected to quality assurance procedures as described in paragraph 
8.3.3.2(a), and should be reviewed for spatial and temporal 
representativeness.

                   8.3.2 National Weather Service Data

                           8.3.2.1 Discussion

    a. The NWS meteorological data are routinely available and familiar 
to most model users. Although the NWS does not provide direct 
measurements of all the needed dispersion model input variables, methods 
have been developed and successfully used to translate the basic NWS 
data to the needed model input. Site specific measurements of model 
input parameters have been made for many modeling studies, and those 
methods and techniques are becoming more widely applied, especially in 
situations such as complex terrain applications, where available NWS 
data are not adequately representative. However, there are many model 
applications where NWS data are adequately representative, and the 
applications still rely heavily on the NWS data.
    b. Many models use the standard hourly weather observations 
available from the National Climatic Data Center (NCDC). These 
observations are then preprocessed before they can be used in the 
models.

                         8.3.2.2 Recommendations

    a. The preferred models listed in Appendix A all accept as input the 
NWS meteorological data preprocessed into model compatible form. If NWS 
data are judged to be adequately representative for a particular 
modeling application, they may be used. NCDC makes available surface 
\89,90\ and upper air \91\ meteorological data in CD-ROM format.
    b. Although most NWS measurements are made at a standard height of 
10 meters, the actual anemometer height should be used as input to the 
preferred model. Note that AERMOD at a minimum requires wind 
observations at a height above ground between seven times the local 
surface roughness height and 100 meters.
    c. Wind directions observed by the National Weather Service are 
reported to the nearest 10 degrees. A specific set of randomly generated 
numbers has been developed for use with the preferred EPA models and 
should be used with NWS data to ensure a lack of bias in wind direction 
assignments within the models.
    d. Data from universities, FAA, military stations, industry and 
pollution control agencies may be used if such data are equivalent in 
accuracy and detail to the NWS data, and they are judged to be 
adequately representative for the particular application.

                        8.3.3 Site Specific Data

                           8.3.3.1 Discussion

    a. Spatial or geographical representativeness is best achieved by 
collection of all of the needed model input data in close proximity to 
the actual site of the source(s). Site specific measured data are 
therefore preferred as model input, provided that appropriate 
instrumentation and quality assurance procedures are followed and that 
the data collected are adequately representative (free from 
inappropriate local or microscale influences) and compatible with the 
input requirements of the model to be used. It should be noted that, 
while site specific measurements are frequently made ``on-property'' 
(i.e., on the source's premises), acquisition of adequately 
representative site specific data does not preclude collection of data 
from a location off property. Conversely, collection of meteorological 
data on a source's property

[[Page 519]]

does not of itself guarantee adequate representativeness. For help in 
determining representativeness of site specific measurements, technical 
guidance \92\ is available. Site specific data should always be reviewed 
for representativeness and consistency by a qualified meteorologist.

                         8.3.3.2 Recommendations

    a. EPA guidance \92\ provides recommendations on the collection and 
use of site specific meteorological data. Recommendations on 
characteristics, siting, and exposure of meteorological instruments and 
on data recording, processing, completeness requirements, reporting, and 
archiving are also included. This publication should be used as a 
supplement to other limited guidance on these subjects.\83,93,94\ 
Detailed information on quality assurance is also available. \95\ As a 
minimum, site specific measurements of ambient air temperature, 
transport wind speed and direction, and the variables necessary to 
estimate atmospheric dispersion should be available in meteorological 
data sets to be used in modeling. Care should be taken to ensure that 
meteorological instruments are located to provide representative 
characterization of pollutant transport between sources and receptors of 
interest. The appropriate reviewing authority (paragraph 3.0(b)) is 
available to help determine the appropriateness of the measurement 
locations.
    b. All site specific data should be reduced to hourly averages. 
Table 8-3 lists the wind related parameters and the averaging time 
requirements.
    c. Missing Data Substitution. After valid data retrieval 
requirements have been met, \92\ hours in the record having missing data 
should be treated according to an established data substitution protocol 
provided that data from an adequately representative alternative site 
are available. Such protocols are usually part of the approved 
monitoring program plan. Data substitution guidance is provided in 
Section 5.3 of reference 92. If no representative alternative data are 
available for substitution, the absent data should be coded as missing 
using missing data codes appropriate to the applicable meteorological 
pre-processor. Appropriate model options for treating missing data, if 
available in the model, should be employed.
    d. Solar Radiation Measurements. Total solar radiation or net 
radiation should be measured with a reliable pyranometer or net 
radiometer, sited and operated in accordance with established site 
specific meteorological guidance. \92,95\
    e. Temperature Measurements. Temperature measurements should be made 
at standard shelter height (2m) in accordance with established site 
specific meteorological guidance. \92\
    f. Temperature Difference Measurements. Temperature difference 
([Delta]T) measurements should be obtained using matched thermometers or 
a reliable thermocouple system to achieve adequate accuracy. Siting, 
probe placement, and operation of [Delta]T systems should be based on 
guidance found in Chapter 3 of reference 92, and such guidance should be 
followed when obtaining vertical temperature gradient data. AERMET 
employs the Bulk Richardson scheme which requires measurements of 
temperature difference. To ensure correct application and acceptance, 
AERMOD users should consult with the appropriate Reviewing Authority 
before using the Bulk Richardson scheme for their analysis.
    g. Winds Aloft. For simulation of plume rise and dispersion of a 
plume emitted from a stack, characterization of the wind profile up 
through the layer in which the plume disperses is required. This is 
especially important in complex terrain and/or complex wind situations 
where wind measurements at heights up to hundreds of meters above stack 
base may be required in some circumstances. For tall stacks when site 
specific data are needed, these winds have been obtained traditionally 
using meteorological sensors mounted on tall towers. A feasible 
alternative to tall towers is the use of meteorological remote sensing 
instruments (e.g., acoustic sounders or radar wind profilers) to provide 
winds aloft, coupled with 10-meter towers to provide the near-surface 
winds. (For specific requirements for AERMOD and CTDMPLUS, see Appendix 
A.) Specifications for wind measuring instruments and systems are 
contained in reference 92.
    h. Turbulence. There are several dispersion models that are capable 
of using direct measurements of turbulence (wind fluctuations) in the 
characterization of the vertical and lateral dispersion (e.g., CTDMPLUS, 
AERMOD, and CALPUFF). For specific requirements for CTDMPLUS, AERMOD, 
and CALPUFF, see Appendix A. For technical guidance on measurement and 
processing of turbulence parameters, see reference 92. When turbulence 
data are used in this manner to directly characterize the vertical and 
lateral dispersion, the averaging time for the turbulence measurements 
should be one hour (Table 8-3). There are other dispersion models (e.g., 
BLP, and CALINE3) that employ P-G stability categories for the 
characterization of the vertical and lateral dispersion. Methods for 
using site specific turbulence data for the characterization of P-G 
stability categories are discussed in reference 92. When turbulence data 
are used in this manner to determine the P-G stability category, the 
averaging time for the turbulence measurements should be 15 minutes.
    i. Stability Categories. For dispersion models that employ P-G 
stability categories for the characterization of the vertical and 
lateral dispersion, the P-G stability categories, as

[[Page 520]]

originally defined, couple near-surface measurements of wind speed with 
subjectively determined insolation assessments based on hourly cloud 
cover and ceiling height observations. The wind speed measurements are 
made at or near 10m. The insolation rate is typically assessed using 
observations of cloud cover and ceiling height based on criteria 
outlined by Turner. \70\ It is recommended that the P-G stability 
category be estimated using the Turner method with site specific wind 
speed measured at or near 10m and representative cloud cover and ceiling 
height. Implementation of the Turner method, as well as considerations 
in determining representativeness of cloud cover and ceiling height in 
cases for which site specific cloud observations are unavailable, may be 
found in Section 6 of reference 92. In the absence of requisite data to 
implement the Turner method, the SRDT method or wind fluctuation 
statistics (i.e., the [sigma]E and [sigma]A 
methods) may be used.
    j. The SRDT method, described in Section 6.4.4.2 of reference 92, is 
modified slightly from that published from earlier work \96\ and has 
been evaluated with three site specific data bases.\97\ The two methods 
of stability classification which use wind fluctuation statistics, the 
[sigma]E and [sigma]A methods, are also described 
in detail in Section 6.4.4 of reference 92 (note applicable tables in 
Section 6). For additional information on the wind fluctuation methods, 
several references are available. \98,99,100,101\
    k. Meteorological Data Preprocessors. The following meteorological 
preprocessors are recommended by EPA: AERMET, \102\ PCRAMMET, \103\ 
MPRM, \104\ METPRO, \105\ and CALMET \106\ AERMET, which is patterned 
after MPRM, should be used to preprocess all data for use with AERMOD. 
Except for applications that employ AERMOD, PCRAMMET is the recommended 
meteorological preprocessor for use in applications employing hourly NWS 
data. MPRM is a general purpose meteorological data preprocessor which 
supports regulatory models requiring PCRAMMET formatted (NWS) data. MPRM 
is available for use in applications employing site specific 
meteorological data. The latest version (MPRM 1.3) has been configured 
to implement the SRDT method for estimating P-G stability categories. 
METPRO is the required meteorological data preprocessor for use with 
CTDMPLUS. CALMET is available for use with applications of CALPUFF. All 
of the above mentioned data preprocessors are available for downloading 
from EPA's Internet SCRAM Web site (subsection 2.3).

    Table 8-3--Averaging Times for Site Specific Wind and Turbulence
                              Measurements
------------------------------------------------------------------------
                                                              Averaging
                         Parameter                               time
                                                                (hour)
------------------------------------------------------------------------
Surface wind speed (for use in stability determinations)...            1
Transport direction........................................            1
Dilution wind speed........................................            1
Turbulence measurements ([sigma]E and [sigma]A) for use in         1 \1\
 stability determinations..................................
Turbulence measurements for direct input to dispersion                1
 models....................................................
------------------------------------------------------------------------
\1\ To minimize meander effects in [sigma]A when wind conditions are
  light and/or variable, determine the hourly average [sigma] value from
  four sequential 15-minute [sigma]'s according to the following
  formula:

  [GRAPHIC] [TIFF OMITTED] TR09NO05.002
  
                 8.3.4 Treatment of Near-Calms and Calms

                           8.3.4.1 Discussion

    a. Treatment of calm or light and variable wind poses a special 
problem in model applications since steady-state Gaussian plume models 
assume that concentration is inversely proportional to wind speed. 
Furthermore, concentrations may become unrealistically large when wind 
speeds less than 1 m/s are input to the model. Procedures have been 
developed to prevent the occurrence of overly conservative concentration 
estimates during periods of calms. These procedures acknowledge that a 
steady-state Gaussian plume model does not apply during calm conditions, 
and that our knowledge of wind patterns and plume behavior during these 
conditions does not, at present, permit the development of a better 
technique. Therefore, the procedures disregard hours which are 
identified as calm. The hour is treated as missing and a convention for 
handling missing hours is recommended.
    b. AERMOD, while fundamentally a steady-state Gaussian plume model, 
contains algorithms for dealing with low wind speed (near calm) 
conditions. As a result, AERMOD can produce model estimates for 
conditions when the wind speed may be less than 1 m/s, but still greater 
than the instrument threshold. Required input to AERMET, the 
meteorological processor for AERMOD, includes a threshold wind speed and 
a reference wind speed. The threshold wind speed is typically the 
threshold of the instrument used to collect the wind speed data. The 
reference wind speed is selected by the model as the lowest level of 
non-missing wind speed and direction data where the speed is greater 
than the wind speed threshold, and the height of the measurement is 
between seven times the local surface roughness and 100 meters. If the 
only valid observation of the

[[Page 521]]

reference wind speed between these heights is less than the threshold, 
the hour is considered calm, and no concentration is calculated. None of 
the observed wind speeds in a measured wind profile that are less than 
the threshold speed are used in construction of the modeled wind speed 
profile in AERMOD.

                         8.3.4.2 Recommendations

    a. Hourly concentrations calculated with steady-state Gaussian plume 
models using calms should not be considered valid; the wind and 
concentration estimates for these hours should be disregarded and 
considered to be missing. Critical concentrations for 3-, 8-, and 24-
hour averages should be calculated by dividing the sum of the hourly 
concentrations for the period by the number of valid or non-missing 
hours. If the total number of valid hours is less than 18 for 24-hour 
averages, less than 6 for 8-hour averages or less than 3 for 3-hour 
averages, the total concentration should be divided by 18 for the 24-
hour average, 6 for the 8-hour average and 3 for the 3-hour average. For 
annual averages, the sum of all valid hourly concentrations is divided 
by the number of non-calm hours during the year. AERMOD has been coded 
to implement these instructions. For models listed in Appendix A, a 
post-processor computer program, CALMPRO \107\ has been prepared, is 
available on the SCRAM Internet Web site (subsection 2.3), and should be 
used.
    b. Stagnant conditions that include extended periods of calms often 
produce high concentrations over wide areas for relatively long 
averaging periods. The standard steady-state Gaussian plume models are 
often not applicable to such situations. When stagnation conditions are 
of concern, other modeling techniques should be considered on a case-by-
case basis (see also subsection 7.2.8).
    c. When used in steady-state Gaussian plume models, measured site 
specific wind speeds of less than 1 m/s but higher than the response 
threshold of the instrument should be input as 1 m/s; the corresponding 
wind direction should also be input. Wind observations below the 
response threshold of the instrument should be set to zero, with the 
input file in ASCII format. For input to AERMOD, no adjustment should be 
made to the site specific wind data. In all cases involving steady-state 
Gaussian plume models, calm hours should be treated as missing, and 
concentrations should be calculated as in paragraph (a) of this 
subsection.

                 9.0 Accuracy and Uncertainty of Models

                             9.1 Discussion

    a. Increasing reliance has been placed on concentration estimates 
from models as the primary basis for regulatory decisions concerning 
source permits and emission control requirements. In many situations, 
such as review of a proposed source, no practical alternative exists. 
Therefore, there is an obvious need to know how accurate models really 
are and how any uncertainty in the estimates affects regulatory 
decisions. During the 1980's, attempts were made to encourage 
development of standardized evaluation methods. \11,108\ EPA recognized 
the need for incorporating such information and has sponsored workshops 
\109\ on model accuracy, the possible ways to quantify accuracy, and on 
considerations in the incorporation of model accuracy and uncertainty in 
the regulatory process. The Second (EPA) Conference on Air Quality 
Modeling, August 1982 \110\, was devoted to that subject.
    b. To better deduce the statistical significance of differences seen 
in model performance in the face of unaccounted for uncertainties and 
variations, investigators have more recently explored the use of 
bootstrap techniques. \111,112\ Work is underway to develop a new 
generation of evaluation metrics \16\ that takes into account the 
statistical differences (in error distributions) between model 
predictions and observations. \113\ Even though the procedures and 
measures are still evolving to describe performance of models that 
characterize atmospheric fate, transport and diffusion, \114,115,116\ 
there has been general acceptance of a need to address the uncertainties 
inherent in atmospheric processes.

                   9.1.1 Overview of Model Uncertainty

    a. Dispersion models generally attempt to estimate concentrations at 
specific sites that really represent an ensemble average of numerous 
repetitions of the same event. \16\ The event is characterized by 
measured or ``known'' conditions that are input to the models, e.g., 
wind speed, mixed layer height, surface heat flux, emission 
characteristics, etc. However, in addition to the known conditions, 
there are unmeasured or unknown variations in the conditions of this 
event, e.g., unresolved details of the atmospheric flow such as the 
turbulent velocity field. These unknown conditions, may vary among 
repetitions of the event. As a result, deviations in observed 
concentrations from their ensemble average, and from the concentrations 
estimated by the model, are likely to occur even though the known 
conditions are fixed. Even with a perfect model that predicts the 
correct ensemble average, there are likely to be deviations from the 
observed concentrations in individual repetitions of the event, due to 
variations in the unknown conditions. The statistics of these 
concentration residuals are termed ``inherent'' uncertainty. Available 
evidence suggests that this source of uncertainty alone may be 
responsible for a typical range of variation in concentrations of as 
much as 50 percent. \117\

[[Page 522]]

    b. Moreover, there is ``reducible'' uncertainty \108\ associated 
with the model and its input conditions; neither models nor data bases 
are perfect. Reducible uncertainties are caused by: (1) Uncertainties in 
the input values of the known conditions (i.e., emission characteristics 
and meteorological data); (2) errors in the measured concentrations 
which are used to compute the concentration residuals; and (3) 
inadequate model physics and formulation. The ``reducible'' 
uncertainties can be minimized through better (more accurate and more 
representative) measurements and better model physics.
    c. To use the terminology correctly, reference to model accuracy 
should be limited to that portion of reducible uncertainty which deals 
with the physics and the formulation of the model. The accuracy of the 
model is normally determined by an evaluation procedure which involves 
the comparison of model concentration estimates with measured air 
quality data. \118\ The statement of accuracy is based on statistical 
tests or performance measures such as bias, noise, correlation, etc. 
\11\ However, information that allows a distinction between 
contributions of the various elements of inherent and reducible 
uncertainty is only now beginning to emerge.\16\ As a result most 
discussions of the accuracy of models make no quantitative distinction 
between (1) limitations of the model versus (2) limitations of the data 
base and of knowledge concerning atmospheric variability. The reader 
should be aware that statements on model accuracy and uncertainty may 
imply the need for improvements in model performance that even the 
``perfect'' model could not satisfy.

                     9.1.2 Studies of Model Accuracy

    a. A number of studies \119,120\ have been conducted to examine 
model accuracy, particularly with respect to the reliability of short-
term concentrations required for ambient standard and increment 
evaluations. The results of these studies are not surprising. Basically, 
they confirm what expert atmospheric scientists have said for some time: 
(1) Models are more reliable for estimating longer time-averaged 
concentrations than for estimating short-term concentrations at specific 
locations; and (2) the models are reasonably reliable in estimating the 
magnitude of highest concentrations occurring sometime, somewhere within 
an area. For example, errors in highest estimated concentrations of 
 10 to 40 percent are found to be typical, 
\121,122\ i.e., certainly well within the often quoted factor-of-two 
accuracy that has long been recognized for these models. However, 
estimates of concentrations that occur at a specific time and site, are 
poorly correlated with actually observed concentrations and are much 
less reliable.
    b. As noted above, poor correlations between paired concentrations 
at fixed stations may be due to ``reducible'' uncertainties in knowledge 
of the precise plume location and to unquantified inherent 
uncertainties. For example, Pasquill \123\ estimates that, apart from 
data input errors, maximum ground-level concentrations at a given hour 
for a point source in flat terrain could be in error by 50 percent due 
to these uncertainties. Uncertainty of five to 10 degrees in the 
measured wind direction, which transports the plume, can result in 
concentration errors of 20 to 70 percent for a particular time and 
location, depending on stability and station location. Such 
uncertainties do not indicate that an estimated concentration does not 
occur, only that the precise time and locations are in doubt.

               9.1.3 Use of Uncertainty in Decision-Making

    a. The accuracy of model estimates varies with the model used, the 
type of application, and site specific characteristics. Thus, it is 
desirable to quantify the accuracy or uncertainty associated with 
concentration estimates used in decision-making. Communications between 
modelers and decision-makers must be fostered and further developed. 
Communications concerning concentration estimates currently exist in 
most cases, but the communications dealing with the accuracy of models 
and its meaning to the decision-maker are limited by the lack of a 
technical basis for quantifying and directly including uncertainty in 
decisions. Procedures for quantifying and interpreting uncertainty in 
the practical application of such concepts are only beginning to evolve; 
much study is still required. \108,109,110,124,125\
    b. In all applications of models an effort is encouraged to identify 
the reliability of the model estimates for that particular area and to 
determine the magnitude and sources of error associated with the use of 
the model. The analyst is responsible for recognizing and quantifying 
limitations in the accuracy, precision and sensitivity of the procedure. 
Information that might be useful to the decision-maker in recognizing 
the seriousness of potential air quality violations includes such model 
accuracy estimates as accuracy of peak predictions, bias, noise, 
correlation, frequency distribution, spatial extent of high 
concentration, etc. Both space/time pairing of estimates and 
measurements and unpaired comparisons are recommended. Emphasis should 
be on the highest concentrations and the averaging times of the 
standards or increments of concern. Where possible, confidence intervals 
about the statistical values should be provided. However, while such 
information can be provided by the modeler to

[[Page 523]]

the decision-maker, it is unclear how this information should be used to 
make an air pollution control decision. Given a range of possible 
outcomes, it is easiest and tends to ensure consistency if the decision-
maker confines his judgement to use of the ``best estimate'' provided by 
the modeler (i.e., the design concentration estimated by a model 
recommended in the Guideline or an alternate model of known accuracy). 
This is an indication of the practical limitations imposed by current 
abilities of the technical community.
    c. To improve the basis for decision-making, EPA has developed and 
is continuing to study procedures for determining the accuracy of 
models, quantifying the uncertainty, and expressing confidence levels in 
decisions that are made concerning emissions controls. \126,127\ 
However, work in this area involves ``breaking new ground'' with slow 
and sporadic progress likely. As a result, it may be necessary to 
continue using the ``best estimate'' until sufficient technical progress 
has been made to meaningfully implement such concepts dealing with 
uncertainty.

                       9.1.4 Evaluation of Models

    a. A number of actions have been taken to ensure that the best model 
is used correctly for each regulatory application and that a model is 
not arbitrarily imposed. First, the Guideline clearly recommends the 
most appropriate model be used in each case. Preferred models, based on 
a number of factors, are identified for many uses. General guidance on 
using alternatives to the preferred models is also provided. Second, the 
models have been subjected to a systematic performance evaluation and a 
peer scientific review. Statistical performance measures, including 
measures of difference (or residuals) such as bias, variance of 
difference and gross variability of the difference, and measures of 
correlation such as time, space, and time and space combined as 
recommended by the AMS Woods Hole Workshop, \11\ were generally 
followed. Third, more specific information has been provided for 
justifying the site specific use of alternative models in previously 
cited EPA guidance, \15\ and new models are under consideration and 
review. \16\ Together these documents provide methods that allow a 
judgement to be made as to what models are most appropriate for a 
specific application. For the present, performance and the theoretical 
evaluation of models are being used as an indirect means to quantify one 
element of uncertainty in air pollution regulatory decisions.
    b. EPA has participated in a series of conferences entitled, 
``Harmonisation within Atmospheric Dispersion Modelling for Regulatory 
Purposes.'' \128\ for the purpose of promoting the development of 
improved methods for the characterization of model performance. There is 
a consensus developing on what should be considered in the evaluation of 
air quality models \129\, namely quality assurance planning, 
documentation and scrutiny should be consistent with the intended use, 
and should include:
     Scientific peer review;
     Supportive analyses (diagnostic evaluations, code 
verification, sensitivity and uncertainty analyses);
     Diagnostic and performance evaluations with data 
obtained in trial locations, and
     Statistical performance evaluations in the 
circumstances of the intended applications.

    Performance evaluations and diagnostic evaluations assess different 
qualities of how well a model is performing, and both are needed to 
establish credibility within the client and scientific community. 
Performance evaluations allow us to decide how well the model simulates 
the average temporal and spatial patterns seen in the observations, and 
employ large spatial/temporal scale data sets (e.g., national data 
sets). Performance evaluations also allow determination of relative 
performance of a model in comparison with alternative modeling systems. 
Diagnostic evaluations allow determination of a model capability to 
simulate individual processes that affect the results, and usually 
employ smaller spatial/temporal scale date sets (e.g., field studies). 
Diagnostic evaluations allow us to decide if we get the right answer for 
the right reason. The objective comparison of modeled concentrations 
with observed field data provides only a partial means for assessing 
model performance. Due to the limited supply of evaluation data sets, 
there are severe practical limits in assessing model performance. For 
this reason, the conclusions reached in the science peer reviews and the 
supportive analyses have particular relevance in deciding whether a 
model will be useful for its intended purposes.
    c. To extend information from diagnostic and performance 
evaluations, sensitivity and uncertainty analyses are encouraged since 
they can provide additional information on the effect of inaccuracies in 
the data bases and on the uncertainty in model estimates. Sensitivity 
analyses can aid in determining the effect of inaccuracies of variations 
or uncertainties in the data bases on the range of likely 
concentrations. Uncertainty analyses can aid in determining the range of 
likely concentration values, resulting from uncertainties in the model 
inputs, the model formulations, and parameterizations. Such information 
may be used to determine source impact and to evaluate control 
strategies. Where possible, information from such sensitivity analyses 
should be made available to the decision-maker with an appropriate 
interpretation of the effect on the critical concentrations.

[[Page 524]]

                           9.2 Recommendations

    a. No specific guidance on the quantification of model uncertainty 
for use in decision-making is being given at this time. As procedures 
for considering uncertainty develop and become implementable, this 
guidance will be changed and expanded. For the present, continued use of 
the ``best estimate'' is acceptable; however, in specific circumstances 
for O3, PM-2.5 and regional haze, additional information and/
or procedures may be appropriate. \32,33\

                  10.0 Regulatory Application of Models

                             10.1 Discussion

    a. Procedures with respect to the review and analysis of air quality 
modeling and data analyses in support of SIP revisions, PSD permitting 
or other regulatory requirements need a certain amount of 
standardization to ensure consistency in the depth and comprehensiveness 
of both the review and the analysis itself. This section recommends 
procedures that permit some degree of standardization while at the same 
time allowing the flexibility needed to assure the technically best 
analysis for each regulatory application.
    b. Dispersion model estimates, especially with the support of 
measured air quality data, are the preferred basis for air quality 
demonstrations. Nevertheless, there are instances where the performance 
of recommended dispersion modeling techniques, by comparison with 
observed air quality data, may be shown to be less than acceptable. 
Also, there may be no recommended modeling procedure suitable for the 
situation. In these instances, emission limitations may be established 
solely on the basis of observed air quality data as would be applied to 
a modeling analysis. The same care should be given to the analyses of 
the air quality data as would be applied to a modeling analysis.
    c. The current NAAQS for SO2 and CO are both stated in 
terms of a concentration not to be exceeded more than once a year. There 
is only an annual standard for NO2 and a quarterly standard 
for Pb. Standards for fine particulate matter (PM-2.5) are expressed in 
terms of both long-term (annual) and short-term (daily) averages. The 
long-term standard is calculated using the three year average of the 
annual averages while the short-term standard is calculated using the 
three year average of the 98th percentile of the daily average 
concentration. For PM-10, the convention is to compare the arithmetic 
mean, averaged over 3 consecutive years, with the concentration 
specified in the NAAQS (50 [micro]g/m\3\). The 24-hour NAAQS (150 
[micro]g/m\3\) is met if, over a 3-year period, there is (on average) no 
more than one exceedance per year. As noted in subsection 7.2.1.1, the 
modeled compliance for this NAAQS is based on the highest 6th highest 
concentration over 5 years. For ozone the short term 1-hour standard is 
expressed in terms of an expected exceedance limit while the short term 
8-hour standard is expressed in terms of a three year average of the 
annual fourth highest daily maximum 8-hour value. The NAAQS are 
subjected to extensive review and possible revision every 5 years.
    d. This section discusses general requirements for concentration 
estimates and identifies the relationship to emission limits. The 
following recommendations apply to: (1) Revisions of State 
Implementation Plans and (2) the review of new sources and the 
prevention of significant deterioration (PSD).

                          10.2 Recommendations

                      10.2.1 Analysis Requirements

    a. Every effort should be made by the Regional Office to meet with 
all parties involved in either a SIP revision or a PSD permit 
application prior to the start of any work on such a project. During 
this meeting, a protocol should be established between the preparing and 
reviewing parties to define the procedures to be followed, the data to 
be collected, the model to be used, and the analysis of the source and 
concentration data. An example of requirements for such an effort is 
contained in the Air Quality Analysis Checklist posted on EPA's Internet 
SCRAM Web site (subsection 2.3). This checklist suggests the level of 
detail required to assess the air quality resulting from the proposed 
action. Special cases may require additional data collection or analysis 
and this should be determined and agreed upon at this preapplication 
meeting. The protocol should be written and agreed upon by the parties 
concerned, although a formal legal document is not intended. Changes in 
such a protocol are often required as the data collection and analysis 
progresses. However, the protocol establishes a common understanding of 
the requirements.
    b. An air quality analysis should begin with a screening model to 
determine the potential of the proposed source or control strategy to 
violate the PSD increment or NAAQS. For traditional stationary sources, 
EPA guidance \24\ should be followed. Guidance is also available for 
mobile sources. \48\
    c. If the concentration estimates from screening techniques indicate 
a significant impact or that the PSD increment or NAAQS may be 
approached or exceeded, then a more refined modeling analysis is 
appropriate and the model user should select a model according to 
recommendations in Sections 4-8. In some instances, no refined technique 
may be specified in this guide for the situation. The model user is then 
encouraged to submit a model developed specifically for

[[Page 525]]

the case at hand. If that is not possible, a screening technique may 
supply the needed results.
    d. Regional Offices should require permit applicants to incorporate 
the pollutant contributions of all sources into their analysis. Where 
necessary this may include emissions associated with growth in the area 
of impact of the new or modified source. PSD air quality assessments 
should consider the amount of the allowable air quality increment that 
has already been consumed by other sources. Therefore, the most recent 
source applicant should model the existing or permitted sources in 
addition to the one currently under consideration. This would permit the 
use of newly acquired data or improved modeling techniques if such have 
become available since the last source was permitted. When remodeling, 
the worst case used in the previous modeling analysis should be one set 
of conditions modeled in the new analysis. All sources should be modeled 
for each set of meteorological conditions selected.

         10.2.2 Use of Measured Data in Lieu of Model Estimates

    a. Modeling is the preferred method for determining emission 
limitations for both new and existing sources. When a preferred model is 
available, model results alone (including background) are sufficient. 
Monitoring will normally not be accepted as the sole basis for emission 
limitation. In some instances when the modeling technique available is 
only a screening technique, the addition of air quality data to the 
analysis may lend credence to model results.
    b. There are circumstances where there is no applicable model, and 
measured data may need to be used. However, only in the case of a NAAQS 
assessment for an existing source should monitoring data alone be a 
basis for emission limits. In addition, the following items (i-vi) 
should be considered prior to the acceptance of the measured data:
    i. Does a monitoring network exist for the pollutants and averaging 
times of concern?
    ii. Has the monitoring network been designed to locate points of 
maximum concentration?
    iii. Do the monitoring network and the data reduction and storage 
procedures meet EPA monitoring and quality assurance requirements?
    iv. Do the data set and the analysis allow impact of the most 
important individual sources to be identified if more than one source or 
emission point is involved?
    v. Is at least one full year of valid ambient data available?
    vi. Can it be demonstrated through the comparison of monitored data 
with model results that available models are not applicable?
    c. The number of monitors required is a function of the problem 
being considered. The source configuration, terrain configuration, and 
meteorological variations all have an impact on number and placement of 
monitors. Decisions can only be made on a case-by-case basis. Guidance 
is available for establishing criteria for demonstrating that a model is 
not applicable?
    d. Sources should obtain approval from the appropriate reviewing 
authority (paragraph 3.0(b)) for the monitoring network prior to the 
start of monitoring. A monitoring protocol agreed to by all concerned 
parties is highly desirable. The design of the network, the number, type 
and location of the monitors, the sampling period, averaging time as 
well as the need for meteorological monitoring or the use of mobile 
sampling or plume tracking techniques, should all be specified in the 
protocol and agreed upon prior to start-up of the network.

                         10.2.3 Emission Limits

                     10.2.3.1 Design Concentrations

    a. Emission limits should be based on concentration estimates for 
the averaging time that results in the most stringent control 
requirements. The concentration used in specifying emission limits is 
called the design value or design concentration and is a sum of the 
concentration contributed by the primary source, other applicable 
sources, and--for NAAQS assessments--the background concentration.
    b. To determine the averaging time for the design value, the most 
restrictive NAAQS or PSD increment, as applicable, should be identified. 
For a NAAQS assessment, the averaging time for the design value is 
determined by calculating, for each averaging time, the ratio of the 
difference between the applicable NAAQS (S) and the background 
concentration (B) to the (model) predicted concentration (P) (i.e., (S-
B)/P). For a PSD increment assessment, the averaging time for the design 
value is determined by calculating, for each averaging time, the ratio 
of the applicable PSD increment (I) and the model-predicted 
concentration (P) (i.e., I/P). The averaging time with the lowest ratio 
identifies the most restrictive standard or increment. If the annual 
average is the most restrictive, the highest estimated annual average 
concentration from one or a number of years of data is the design value. 
When short term standards are most restrictive, it may be necessary to 
consider a broader range of concentrations than the highest value. For 
example, for pollutants such as SO2, the highest, second-
highest concentration is the design value. For pollutants with 
statistically based NAAQS, the design value is found by determining the 
more restrictive of: (1) The short-term concentration over the period 
specified in the standard, or (2) the long-term concentration that is 
not expected

[[Page 526]]

to exceed the long-term NAAQS. Determination of design values for PM-10 
is presented in more detail in EPA guidance. \34\

           10.2.3.2 NAAQS Analyses for New or Modified Sources

    a. For new or modified sources predicted to have a significant 
ambient impact \83\ and to be located in areas designated attainment or 
unclassifiable for the SO2, Pb, NO2, or CO NAAQS, 
the demonstration as to whether the source will cause or contribute to 
an air quality violation should be based on: (1) The highest estimated 
annual average concentration determined from annual averages of 
individual years; or (2) the highest, second-highest estimated 
concentration for averaging times of 24-hours or less; and (3) the 
significance of the spatial and temporal contribution to any modeled 
violation. For Pb, the highest estimated concentration based on an 
individual calendar quarter averaging period should be used. Background 
concentrations should be added to the estimated impact of the source. 
The most restrictive standard should be used in all cases to assess the 
threat of an air quality violation. For new or modified sources 
predicted to have a significant ambient impact \83\ in areas designated 
attainment or unclassifiable for the PM-10 NAAQS, the demonstration of 
whether or not the source will cause or contribute to an air quality 
violation should be based on sufficient data to show whether: (1) The 
projected 24-hour average concentrations will exceed the 24-hour NAAQS 
more than once per year, on average; (2) the expected (i.e., average) 
annual mean concentration will exceed the annual NAAQS; and (3) the 
source contributes significantly, in a temporal and spatial sense, to 
any modeled violation.

             10.2.3.3 PSD Air Quality Increments and Impacts

    a. The allowable PSD increments for criteria pollutants are 
established by regulation and cited in 40 CFR 51.166. These maximum 
allowable increases in pollutant concentrations may be exceeded once per 
year at each site, except for the annual increment that may not be 
exceeded. The highest, second-highest increase in estimated 
concentrations for the short term averages as determined by a model 
should be less than or equal to the permitted increment. The modeled 
annual averages should not exceed the increment.
    b. Screening techniques defined in subsection 4.2.1 can sometimes be 
used to estimate short term incremental concentrations for the first new 
source that triggers the baseline in a given area. However, when 
multiple increment-consuming sources are involved in the calculation, 
the use of a refined model with at least 1 year of site specific or 5 
years of (off-site) NWS data is normally required (subsection 8.3.1.2). 
In such cases, sequential modeling must demonstrate that the allowable 
increments are not exceeded temporally and spatially, i.e., for all 
receptors for each time period throughout the year(s) (time period means 
the appropriate PSD averaging time, e.g., 3-hour, 24-hour, etc.).
    c. The PSD regulations require an estimation of the SO2, 
particulate matter (PM-10), and NO2 impact on any Class I 
area. Normally, steady-state Gaussian plume models should not be applied 
at distances greater than can be accommodated by the steady state 
assumptions inherent in such models. The maximum distance for refined 
steady-state Gaussian plume model application for regulatory purposes is 
generally considered to be 50km. Beyond the 50km range, screening 
techniques may be used to determine if more refined modeling is needed. 
If refined models are needed, long range transport models should be 
considered in accordance with subsection 6.2.3. As previously noted in 
Sections 3 and 7, the need to involve the Federal Land Manager in 
decisions on potential air quality impacts, particularly in relation to 
PSD Class I areas, cannot be overemphasized.

                          11.0 Bibliography \a\
---------------------------------------------------------------------------

    \a\ The documents listed here are major sources of supplemental 
information on the theory and application of mathematical air quality 
models.
---------------------------------------------------------------------------

    American Meteorological Society. Symposia on Turbulence, Diffusion, 
and Air Pollution (1st-10th); 1971-1992. Symposia on Boundary Layers & 
Turb. 11th-12th; 1995-1997. Boston, MA.
    American Meteorological Society, 1977-1998. Joint Conferences on 
Applications of Air Pollution Meteorology (1st-10th). Sponsored by the 
American Meteorological Society and the Air & Waste Management 
Association. Boston, MA.
    American Meteorological Society, 1978. Accuracy of Dispersion 
Models. Bulletin of the American Meteorological Society, 59(8): 1025-
1026.
    American Meteorological Society, 1981. Air Quality Modeling and the 
Clean Air Act: Recommendations to EPA on Dispersion Modeling for 
Regulatory Applications. Boston, MA.
    Briggs, G.A., 1969. Plume Rise. U.S. Atomic Energy Commission 
Critical Review Series, Oak Ridge National Laboratory, Oak Ridge, TN.
    Drake, R.L. and S.M. Barrager, 1979. Mathematical Models for 
Atmospheric Pollutants. EPRI EA-1131. Electric Power Research Institute, 
Palo Alto, CA.

[[Page 527]]

    Environmental Protection Agency, 1978. Workbook for Comparison of 
Air Quality Models. Publication No. EPA-450/2-78-028a and b. Office of 
Air Quality Planning & Standards, Research Triangle Park, NC.
    Erisman J.W., Van Pul A. and Wyers P. (1994) Parameterization of 
surface resistance for the quantification of atmospheric deposition of 
acidifying pollutants and ozone. Atmos. Environ., 28: 2595-2607.
    Fox, D.G., and J.E. Fairobent, 1981. NCAQ Panel Examines Uses and 
Limitations of Air Quality Models. Bulletin of the American 
Meteorological Society, 62(2): 218-221.
    Gifford, F.A., 1976. Turbulent Diffusion Typing Schemes: A Review. 
Nuclear Safety, 17(1): 68-86.
    Gudiksen, P.H., and M.H. Dickerson, Eds., Executive Summary: 
Atmospheric Studies in Complex Terrain Technical Progress Report FY-1979 
Through FY-1983. Lawrence Livermore National Laboratory, Livermore, CA. 
(Docket Reference No. II-I-103).
    Hanna, S.R., G.A. Briggs, J. Deardorff, B.A. Egan, G.A. Gifford and 
F. Pasquill, 1977. AMS Workshop on Stability Classification Schemes And 
Sigma Curves--Summary of Recommendations. Bulletin of the American 
Meteorological Society, 58(12): 1305-1309.
    Hanna, S.R., G.A. Briggs and R.P. Hosker, Jr., 1982. Handbook on 
Atmospheric Diffusion. Technical Information Center, U.S. Department of 
Energy, Washington, D.C.
    Haugen, D.A., Workshop Coordinator, 1975. Lectures on Air Pollution 
and Environmental Impact Analyses. Sponsored by the American 
Meteorological Society, Boston, MA.
    Hoffnagle, G.F., M.E. Smith, T.V. Crawford and T.J. Lockhart, 1981. 
On-site Meteorological Instrumentation Requirements to Characterize 
Diffusion from Point Sources--A Workshop, 15-17 January 1980, Raleigh, 
NC. Bulletin of the American Meteorological Society, 62(2): 255-261.
    Hunt, J.C.R., R.G. Holroyd, D.J. Carruthers, A.G. Robins, D.D. 
Apsley, F.B. Smith and D.J. Thompson, 1990. Developments in Modeling Air 
Pollution for Regulatory Uses. In Proceedings of the 18th NATO/CCMS 
International Technical Meeting on Air Pollution Modeling and its 
Application, Vancouver, Canada. Also In Air Pollution Modeling and its 
Application VIII (1991). H. van Dop and D.G. Steyn, eds. Plenum Press, 
New York, NY. pp. 17-59
    Pasquill, F. and F.B. Smith, 1983. Atmospheric Diffusion, 3rd 
Edition. Ellis Horwood Limited, Chichester, West Sussex, England, 438pp.
    Randerson, D., Ed., 1984. Atmospheric Science and Power Production. 
DOE/TIC 2760l. Office of Scientific and Technical Information, U.S. 
Department of Energy, Oak Ridge, TN.
    Scire, J.S. and L.L. Schulman, 1980: Modeling plume rise from low-
level buoyant line and point sources. AMS/APCA Second Joint Conference 
on Applications of Air Pollution Meteorology, March 24-27, New Orleans, 
LA.
    Smith, M.E., Ed., 1973. Recommended Guide for the Prediction of the 
Dispersion of Airborne Effluents. The American Society of Mechanical 
Engineers, New York, NY.
    Stern, A.C., Ed., 1976. Air Pollution, Third Edition, Volume I: Air 
Pollutants, Their Transformation and Transport. Academic Press, New 
York, NY.
    Turner, D.B., 1979. Atmospheric Dispersion Modeling: A Critical 
Review. Journal of the Air Pollution Control Association, 29(5): 502-
519.
    Venkatram, A. and J.C. Wyngaard, Editors, 1988. Lectures on Air 
Pollution Modeling. American Meteorological Society, Boston, MA. 390pp.

                             12.0 References

    1. Code of Federal Regulations; Title 40 (Protection of 
Environment). Sections 51.112, 51.117, 51.150, 51.160.
    2. Environmental Protection Agency, 1990. New Source Review Workshop 
Manual: Prevention of Significant Deterioration and Nonattainment Area 
Permitting (Draft). Office of Air Quality Planning & Standards, Research 
Triangle Park, NC. (Available at: http://www.epa.gov/ttn/nsr/)
    3. Code of Federal Regulations; Title 40 (Protection of 
Environment). Sections 51.166 and 52.21.
    4. Code of Federal Regulations (Title 40, Part 50): Protection of 
the Environment; National Primary and Secondary Ambient Air Quality 
Standards.
    5. Environmental Protection Agency, 1988. Model Clearinghouse: 
Operational Plan (Revised). Staff Report. Office of Air Quality Planning 
& Standards, Research Triangle Park, NC. (Docket No. A-88-04, II-J-1)
    6. Environmental Protection Agency, 1980. Guidelines on Air Quality 
Models. Federal Register, 45(61): 20157-20158.
    7. Scire, J.S. and L.L. Schulman, 1981. Evaluation of the BLP and 
ISC Models with SF6 Tracer Data and SO2 Measurements at 
Aluminum Reduction Plants. APCA Specialty Conference on Dispersion 
Modeling for Complex Sources, St. Louis, MO.
    8. Environmental Protection Agency, 1986. Evaluation of Mobile 
Source Air Quality Simulation Models. Publication No. EPA-450/4-86-002. 
Office of Air Quality Planning & Standards, Research Triangle Park, NC. 
(NTIS No. PB 86-167293)
    9. Strimaitis, D.G., J.S. Scire and J.C. Chang. 1998. Evaluation of 
the CALPUFF Dispersion Model with Two Power Plant Data Sets. Tenth Joint 
Conference on the Application of Air Pollution Meteorology, Phoenix, 
Arizona. American Meteorological Society, Boston, MA. January 11-16, 
1998.
    10. Environmental Protection Agency, 2003. AERMOD: Latest Features 
and Evaluation Results. Publication No. EPA-454/R-03-003.

[[Page 528]]

U.S. Environmental Protection Agency, Research Triangle Park, NC. 
(Available at http://www.epa.gov/scram001/)
    11. Fox, D.G., 1981. Judging Air Quality Model Performance. Bulletin 
of the American Meteorological Society, 62(5): 599-609.
    12. American Meteorological Society, 1983. Synthesis of the Rural 
Model Reviews. Publication No. EPA-600/3-83-108. Office of Research & 
Development, Research Triangle Park, NC. (NTIS No. PB 84-121037)
    13. Allwine, K.J., W.F. Dabberdt and L.L. Simmons. 1998. Peer Review 
of the CALMET/CALPUFF Modeling System. Prepared by the KEVRIC Company, 
Inc. under EPA Contract No. 68-D-98-092 for Environmental Protection 
Agency, Research Triangle Park, NC. (Docket No. A-99-05, II-A-8)
    14. Hanna, S., M. Garrison and B. Turner, 1998. AERMOD Peer Review 
report. Prepared by SAI, Inc. under EPA Contract No. 68-D6-0064/1-14 for 
Environmental Protection Agency, Research Triangle Park, NC. 12pp. & 
appendices (Docket No. A-99-05, II-A-6)
    15. Environmental Protection Agency, 1992. Protocol for Determining 
the Best Performing Model. Publication No. EPA-454/R-92-025. Office of 
Air Quality Planning & Standards, Research Triangle Park, NC. (NTIS No. 
PB 93-226082)
    16. ASTM D6589: Standard Guide for Statistical Evaluation of 
Atmospheric Dispersion Model Performance. (2000)
    17. Environmental Protection Agency, 1995. User's Guide for the 
Industrial Source Complex (ISC3) Dispersion Models, Volumes 1 and 2. 
Publication Nos. EPA-454/B-95-003a & b. U.S. Environmental Protection 
Agency, Research Triangle Park, NC. (NTIS Nos. PB 95-222741 and PB 95-
222758, respectively)
    18. Hanna, S.R. and R.J. Paine, 1989. Hybrid Plume Dispersion Model 
(HPDM) Development and Evaluation. J. Appl. Meteorol., 28: 206-224.
    19. Hanna, S.R. and J.C. Chang, 1992. Boundary layer 
parameterizations for applied dispersion modeling over urban areas. 
Bound. Lay. Meteorol., 58, 229-259.
    20. Hanna, S.R. and J.C. Chang, 1993. Hybrid Plume Dispersion Model 
(HPDM) Improvements and Testing at Three Field Sites. Atmos. Environ., 
27A: 1491-1508.
    21. American Meteorological Society, 1984. Workshop on Updating 
Applied Diffusion Models. 24-27 January 1984. Clearwater, Florida. J. 
Climate and Appl. Met., 24(11): 1111-1207.
    22. Environmental Protection Agency, 2002. AERMOD: Description of 
Model Formulation. Research Triangle Park, NC. EPA Report No. EPA-454/R-
02-002d; April 2002; AND Cimorelli, A. et al., 2005. AERMOD: A 
Dispersion Model for Industrial Source Applications. Part I: General 
Model Formulation and Boundary Layer Characterization. Journal of 
Applied Meteorology, 44(5): 682-693.
    23. L.L. Schulman, D.G. Strimaitis and J.S. Scire, 2002. Development 
and evaluation of the PRIME plume rise and building downwash model. 
Journal of the Air & Waste Management Association, 50: 378-390.
    24. Environmental Protection Agency, 1992. Screening Procedures for 
Estimating the Air Quality Impact of Stationary Sources, Revised. 
Publication No. EPA-454/R-92-019. U.S. Environmental Protection Agency, 
Research Triangle Park, NC. (NTIS No. PB 93-219095)
    25. Environmental Protection Agency, 1995. SCREEN3 User's Guide. 
Publication No. EPA-454/B-95-004. U.S. Environmental Protection Agency, 
Research Triangle Park, NC. (NTIS No. PB 95-222766)
    26. Perry, S.G., D.J. Burns and A.J. Cimorelli, 1990. User's Guide 
to CTDMPLUS: Volume 2. The Screening Mode (CTSCREEN). Publication No. 
EPA-600/8-90-087. U.S. Environmental Protection Agency, Research 
Triangle Park, NC. (NTIS No. PB 91-136564)
    27. Mills, M.T., R.J. Paine, E.A. Insley and B.A. Egan, 1987. The 
Complex Terrain Dispersion Model Terrain Preprocessor System--User's 
Guide and Program Description. Publication No. EPA-600/8-88-003. U.S. 
Environmental Protection Agency, Research Triangle Park, NC. (NTIS No. 
PB 88-162094)
    28. Burns, D.J., S.G. Perry and A.J. Cimorelli, 1991. An Advanced 
Screening Model for Complex Terrain Applications. Paper presented at the 
7th Joint Conference on Applications of Air Pollution Meteorology 
(cosponsored by the American Meteorological Society and the Air & Waste 
Management Association), January 13-18, 1991, New Orleans, LA.
    29. Environmental Research and Technology, 1987. User's Guide to the 
Rough Terrain Diffusion Model (RTDM), Rev. 3.20. ERT Document No. P-
D535-585. Environmental Research and Technology, Inc., Concord, MA. 
(NTIS No. PB 88-171467)
    30. Meng, Z.D. Dabdub and J.H. Seinfeld, 1997. Chemical Coupling 
between Atmospheric Ozone and Particulate Matter. Science, 277: 116-119.
    31. Hidy, G.M, P.M. Roth, J.M. Hales and R.D. Scheffe, 1998. Fine 
Particles and Oxidant Pollution: Developing an Agenda for Cooperative 
Research. JAWMA, 50: 613-632.
    32. Environmental Protection Agency, 2005. Guidance on the Use of 
Models and Other Analyses in Attainment Demonstrations for the 8-hr 
Ozone NAAQS (Draft Final). Office of Air Quality Planning & Standards, 
Research Triangle Park, NC. (Latest version available on SCRAM Web site 
as draft-final-O3.pdf; see subsection 2.3)
    33. Environmental Protection Agency, 2005. Guidance on the Use of 
Models and Other Analyses in Attainment Demonstrations for the PM-2.5 
NAAQS and Regional Haze Goals. Office of Air Quality Planning & 
Standards, Research Triangle Park, NC. (As of May 2005, this document 
has not been finalized; latest

[[Page 529]]

version available on SCRAM Web site as draft-pm.pdf; see subsection 2.3)
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APPENDIX A TO APPENDIX W OF PART 51--SUMMARIES OF PREFERRED AIR QUALITY 
                                 MODELS

                            Table of Contents

A.0 Introduction and Availability
A.1 Aermod
A.2 Buoyant Line and Point Source Dispersion Model (BLP)
A.3 CALINE3
A.4 CALPUFF
A.5 Complex Terrain Dispersion Model Plus Algorithms for Unstable 
          Situations (CTDMPLUS)
A.6 Offshore and Coastal Dispersion Model (OCD)
A.REF References

                    A.0 Introduction and Availability

    (1) This appendix summarizes key features of refined air quality 
models preferred for specific regulatory applications. For each model, 
information is provided on availability, approximate cost (where 
applicable), regulatory use, data input, output format and options, 
simulation of atmospheric physics, and accuracy. These models may be 
used without a formal demonstration of applicability provided they 
satisfy the recommendations for regulatory use; not all options in the 
models are necessarily recommended for regulatory use.
    (2) Many of these models have been subjected to a performance 
evaluation using comparisons with observed air quality data. Where 
possible, several of the models contained herein have been subjected to 
evaluation exercises, including (1) statistical performance tests 
recommended by the American Meteorological Society and (2) peer 
scientific reviews. The models in this appendix have been selected on 
the basis of the results of the model evaluations, experience with 
previous use, familiarity of the model to various air quality programs, 
and the costs and resource requirements for use.
    (3) Codes and documentation for all models listed in this appendix 
are available from EPA's Support Center for Regulatory Air Models 
(SCRAM) Web site at http://www.epa.gov/scram001. Documentation is also 
available from the National Technical Information Service (NTIS), http:/
/www.ntis.gov or U.S. Department of Commerce, Springfield, VA 22161; 
phone: (800) 553-6847. Where possible, accession numbers are provided.

                  A.1 AMS/EPA Regulatory Model--AERMOD

                               References

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Protection Agency, Research Triangle Park, NC 27711; September 2004. 
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    Cimorelli, A. et al., 2005. AERMOD: A Dispersion Model for 
Industrial Source Applications. Part I: General Model Formulation and 
Boundary Layer Characterization. Journal of Applied Meteorology, 44(5): 
682-693.
    Perry, S. et al., 2005. AERMOD: A Dispersion Model for Industrial 
Source Applications. Part II: Model Performance against 17 Field Study 
Databases. Journal of Applied Meteorology, 44(5): 694-708.
    Environmental Protection Agency, 2004. User's Guide for the AMS/EPA 
Regulatory Model--AERMOD. Publication No. EPA-454/B-03-001. U.S. 
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September 2004. (Available at http://www.epa.gov/scram001/)
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Meteorological Preprocessor (AERMET). Publication No. EPA-454/B-03-002. 
U.S. Environmental Protection Agency, Research Triangle Park, NC 27711; 
November 2004. (Available at http://www.epa.gov/scram001/)

[[Page 534]]

    Environmental Protection Agency, 2004. User's Guide for the AERMOD 
Terrain Preprocessor (AERMAP). Publication No. EPA-454/B-03-003. U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711; 
October 2004. (Available at http://www.epa.gov/scram001/)
    Schulman, L.L., D.G. Strimaitis and J.S. Scire, 2000. Development 
and evaluation of the PRIME plume rise and building downwash model. 
Journal of the Air and Waste Management Association, 50: 378-390.

                              Availability

    The model codes and associated documentation are available on EPA's 
Internet SCRAM Web site (Section A.0).

                                Abstract

    AERMOD is a steady-state plume dispersion model for assessment of 
pollutant concentrations from a variety of sources. AERMOD simulates 
transport and dispersion from multiple point, area, or volume sources 
based on an up-to-date characterization of the atmospheric boundary 
layer. Sources may be located in rural or urban areas, and receptors may 
be located in simple or complex terrain. AERMOD accounts for building 
wake effects (i.e., plume downwash) based on the PRIME building downwash 
algorithms. The model employs hourly sequential preprocessed 
meteorological data to estimate concentrations for averaging times from 
one hour to one year (also multiple years). AERMOD is designed to 
operate in concert with two pre-processor codes: AERMET processes 
meteorological data for input to AERMOD, and AERMAP processes terrain 
elevation data and generates receptor information for input to AERMOD.

                  a. Recommendations for Regulatory Use

    (1) AERMOD is appropriate for the following applications:
     Point, volume, and area sources;
     Surface, near-surface, and elevated releases;
     Rural or urban areas;
     Simple and complex terrain;
     Transport distances over which steady-state 
assumptions are appropriate, up to 50km;
     1-hour to annual averaging times; and
     Continuous toxic air emissions.
    (2) For regulatory applications of AERMOD, the regulatory default 
option should be set, i.e., the parameter DFAULT should be employed in 
the MODELOPT record in the COntrol Pathway. The DFAULT option requires 
the use of terrain elevation data, stack-tip downwash, sequential date 
checking, and does not permit the use of the model in the SCREEN mode. 
In the regulatory default mode, pollutant half life or decay options are 
not employed, except in the case of an urban source of sulfur dioxide 
where a four-hour half life is applied. Terrain elevation data from the 
U.S. Geological Survey 7.5-Minute Digital Elevation Model 
(edcwww.cr.usgs.gov/doc/edchome/ndcdb/ndcdb.html) or equivalent (approx. 
30-meter resolution) should be used in all applications. In some cases, 
exceptions of the terrain data requirement may be made in consultation 
with the permit/SIP reviewing authority.

                          b. Input Requirements

    (1) Source data: Required input includes source type, location, 
emission rate, stack height, stack inside diameter, stack gas exit 
velocity, stack gas temperature, area and volume source dimensions, and 
source elevation. Building dimensions and variable emission rates are 
optional.
    (2) Meteorological data: The AERMET meteorological preprocessor 
requires input of surface characteristics, including surface roughness 
(zo), Bowen ratio, and albedo, as well as, hourly observations of wind 
speed between 7zo and 100m (reference wind speed measurement from which 
a vertical profile can be developed), wind direction, cloud cover, and 
temperature between zo and 100m (reference temperature measurement from 
which a vertical profile can be developed). Surface characteristics may 
be varied by wind sector and by season or month. A morning sounding (in 
National Weather Service format) from a representative upper air 
station, latitude, longitude, time zone, and wind speed threshold are 
also required in AERMET (instrument threshold is only required for site 
specific data). Additionally, measured profiles of wind, temperature, 
vertical and lateral turbulence may be required in certain applications 
(e.g., in complex terrain) to adequately represent the meteorology 
affecting plume transport and dispersion. Optionally, measurements of 
solar, or net radiation may be input to AERMET. Two files are produced 
by the AERMET meteorological preprocessor for input to the AERMOD 
dispersion model. The surface file contains observed and calculated 
surface variables, one record per hour. The profile file contains the 
observations made at each level of a meteorological tower (or remote 
sensor), or the one-level observations taken from other representative 
data (e.g., National Weather Service surface observations), one record 
per level per hour.
    (i) Data used as input to AERMET should possess an adequate degree 
of representativeness to insure that the wind, temperature and 
turbulence profiles derived by AERMOD are both laterally and vertically 
representative of the source area. The adequacy of input data should be 
judged independently for each variable. The values for surface 
roughness, Bowen ratio, and albedo should

[[Page 535]]

reflect the surface characteristics in the vicinity of the 
meteorological tower, and should be adequately representative of the 
modeling domain. Finally, the primary atmospheric input variables 
including wind speed and direction, ambient temperature, cloud cover, 
and a morning upper air sounding should also be adequately 
representative of the source area.
    (ii) For recommendations regarding the length of meteorological 
record needed to perform a regulatory analysis with AERMOD, see Section 
8.3.1.
    (3) Receptor data: Receptor coordinates, elevations, height above 
ground, and hill height scales are produced by the AERMAP terrain 
preprocessor for input to AERMOD. Discrete receptors and/or multiple 
receptor grids, Cartesian and/or polar, may be employed in AERMOD. 
AERMAP requires input of Digital Elevation Model (DEM) terrain data 
produced by the U.S. Geological Survey (USGS), or other equivalent data. 
AERMAP can be used optionally to estimate source elevations.

                                c. Output

    Printed output options include input information, high concentration 
summary tables by receptor for user-specified averaging periods, maximum 
concentration summary tables, and concurrent values summarized by 
receptor for each day processed. Optional output files can be generated 
for: a listing of occurrences of exceedances of user-specified threshold 
value; a listing of concurrent (raw) results at each receptor for each 
hour modeled, suitable for post-processing; a listing of design values 
that can be imported into graphics software for plotting contours; an 
unformatted listing of raw results above a threshold value with a 
special structure for use with the TOXX model component of TOXST; a 
listing of concentrations by rank (e.g., for use in quantile-quantile 
plots); and, a listing of concentrations, including arc-maximum 
normalized concentrations, suitable for model evaluation studies.

                            d. Type of Model

    AERMOD is a steady-state plume model, using Gaussian distributions 
in the vertical and horizontal for stable conditions, and in the 
horizontal for convective conditions. The vertical concentration 
distribution for convective conditions results from an assumed bi-
Gaussian probability density function of the vertical velocity.

                           e. Pollutant Types

    AERMOD is applicable to primary pollutants and continuous releases 
of toxic and hazardous waste pollutants. Chemical transformation is 
treated by simple exponential decay.

                    f. Source-Receptor Relationships

    AERMOD applies user-specified locations for sources and receptors. 
Actual separation between each source-receptor pair is used. Source and 
receptor elevations are user input or are determined by AERMAP using 
USGS DEM terrain data. Receptors may be located at user-specified 
heights above ground level.

                            g. Plume Behavior

    (1) In the convective boundary layer (CBL), the transport and 
dispersion of a plume is characterized as the superposition of three 
modeled plumes: The direct plume (from the stack), the indirect plume, 
and the penetrated plume, where the indirect plume accounts for the 
lofting of a buoyant plume near the top of the boundary layer, and the 
penetrated plume accounts for the portion of a plume that, due to its 
buoyancy, penetrates above the mixed layer, but can disperse downward 
and re-enter the mixed layer. In the CBL, plume rise is superposed on 
the displacements by random convective velocities (Weil et al., 1997).
    (2) In the stable boundary layer, plume rise is estimated using an 
iterative approach, similar to that in the CTDMPLUS model (see A.5 in 
this appendix).
    (3) Stack-tip downwash and buoyancy induced dispersion effects are 
modeled. Building wake effects are simulated for stacks less than good 
engineering practice height using the methods contained in the PRIME 
downwash algorithms (Schulman, et al., 2000). For plume rise affected by 
the presence of a building, the PRIME downwash algorithm uses a 
numerical solution of the mass, energy and momentum conservation laws 
(Zhang and Ghoniem, 1993). Streamline deflection and the position of the 
stack relative to the building affect plume trajectory and dispersion. 
Enhanced dispersion is based on the approach of Weil (1996). Plume mass 
captured by the cavity is well-mixed within the cavity. The captured 
plume mass is re-emitted to the far wake as a volume source.
    (4) For elevated terrain, AERMOD incorporates the concept of the 
critical dividing streamline height, in which flow below this height 
remains horizontal, and flow above this height tends to rise up and over 
terrain (Snyder et al., 1985). Plume concentration estimates are the 
weighted sum of these two limiting plume states. However, consistent 
with the steady-state assumption of uniform horizontal wind direction 
over the modeling domain, straight-line plume trajectories are assumed, 
with adjustment in the plume/receptor geometry used to account for the 
terrain effects.

[[Page 536]]

                           h. Horizontal Winds

    Vertical profiles of wind are calculated for each hour based on 
measurements and surface-layer similarity (scaling) relationships. At a 
given height above ground, for a given hour, winds are assumed constant 
over the modeling domain. The effect of the vertical variation in 
horizontal wind speed on dispersion is accounted for through simple 
averaging over the plume depth.

                         i. Vertical Wind Speed

    In convective conditions, the effects of random vertical updraft and 
downdraft velocities are simulated with a bi-Gaussian probability 
density function. In both convective and stable conditions, the mean 
vertical wind speed is assumed equal to zero.

                        j. Horizontal Dispersion

    Gaussian horizontal dispersion coefficients are estimated as 
continuous functions of the parameterized (or measured) ambient lateral 
turbulence and also account for buoyancy-induced and building wake-
induced turbulence. Vertical profiles of lateral turbulence are 
developed from measurements and similarity (scaling) relationships. 
Effective turbulence values are determined from the portion of the 
vertical profile of lateral turbulence between the plume height and the 
receptor height. The effective lateral turbulence is then used to 
estimate horizontal dispersion.

                         k. Vertical Dispersion

    In the stable boundary layer, Gaussian vertical dispersion 
coefficients are estimated as continuous functions of parameterized 
vertical turbulence. In the convective boundary layer, vertical 
dispersion is characterized by a bi-Gaussian probability density 
function, and is also estimated as a continuous function of 
parameterized vertical turbulence. Vertical turbulence profiles are 
developed from measurements and similarity (scaling) relationships. 
These turbulence profiles account for both convective and mechanical 
turbulence. Effective turbulence values are determined from the portion 
of the vertical profile of vertical turbulence between the plume height 
and the receptor height. The effective vertical turbulence is then used 
to estimate vertical dispersion.

                       l. Chemical Transformation

    Chemical transformations are generally not treated by AERMOD. 
However, AERMOD does contain an option to treat chemical transformation 
using simple exponential decay, although this option is typically not 
used in regulatory applications, except for sources of sulfur dioxide in 
urban areas. Either a decay coefficient or a half life is input by the 
user. Note also that the Plume Volume Molar Ratio Method (subsection 
5.1) and the Ozone Limiting Method (subsection 5.2.4) and for point-
source NO2 analyses are available as non-regulatory options.

                           m. Physical Removal

    AERMOD can be used to treat dry and wet deposition for both gases 
and particles.

                          n. Evaluation Studies

    American Petroleum Institute, 1998. Evaluation of State of the 
Science of Air Quality Dispersion Model, Scientific Evaluation, prepared 
by Woodward-Clyde Consultants, Lexington, Massachusetts, for American 
Petroleum Institute, Washington, D.C., 20005-4070.
    Brode, R.W., 2002. Implementation and Evaluation of PRIME in AERMOD. 
Preprints of the 12th Joint Conference on Applications of Air Pollution 
Meteorology, May 20-24, 2002; American Meteorological Society, Boston, 
MA.
    Brode, R.W., 2004. Implementation and Evaluation of Bulk Richardson 
Number Scheme in AERMOD. 13th Joint Conference on Applications of Air 
Pollution Meteorology, August 23-26, 2004; American Meteorological 
Society, Boston, MA.
    Environmental Protection Agency, 2003. AERMOD: Latest Features and 
Evaluation Results. Publication No. EPA-454/R-03-003. U.S. Environmental 
Protection Agency, Research Triangle Park, NC. Available at http://
www.epa.gov/scram001/.

        A.2 Buoyant Line and Point Source Dispersion Model (BLP)

                                Reference

    Schulman, Lloyd L., and Joseph S. Scire, 1980. Buoyant Line and 
Point Source (BLP) Dispersion Model User's Guide. Document P-7304B. 
Environmental Research and Technology, Inc., Concord, MA. (NTIS No. PB 
81-164642; also available at http://www.epa.gov/scram001/)

                              Availability

    The computer code is available on EPA's Internet SCRAM Web site and 
also on diskette (as PB 2002-500051) from the National Technical 
Information Service (see Section A.0).

                                Abstract

    BLP is a Gaussian plume dispersion model designed to handle unique 
modeling problems associated with aluminum reduction plants, and other 
industrial sources where plume rise and downwash effects from stationary 
line sources are important.

                  a. Recommendations for Regulatory Use

    (1) The BLP model is appropriate for the following applications:
     Aluminum reduction plants which contain buoyant, 
elevated line sources;

[[Page 537]]

     Rural areas;
     Transport distances less than 50 kilometers;
     Simple terrain; and
     One hour to one year averaging times.
    (2) The following options should be selected for regulatory 
applications:
    (i) Rural (IRU=1) mixing height option;
    (ii) Default (no selection) for plume rise wind shear (LSHEAR), 
transitional point source plume rise (LTRANS), vertical potential 
temperature gradient (DTHTA), vertical wind speed power law profile 
exponents (PEXP), maximum variation in number of stability classes per 
hour (IDELS), pollutant decay (DECFAC), the constant in Briggs' stable 
plume rise equation (CONST2), constant in Briggs' neutral plume rise 
equation (CONST3), convergence criterion for the line source 
calculations (CRIT), and maximum iterations allowed for line source 
calculations (MAXIT); and
    (iii) Terrain option (TERAN) set equal to 0.0, 0.0, 0.0, 0.0, 0.0, 
0.0
    (3) For other applications, BLP can be used if it can be 
demonstrated to give the same estimates as a recommended model for the 
same application, and will subsequently be executed in that mode.
    (4) BLP can be used on a case-by-case basis with specific options 
not available in a recommended model if it can be demonstrated, using 
the criteria in Section 3.2, that the model is more appropriate for a 
specific application.

                          b. Input Requirements

    (1) Source data: point sources require stack location, elevation of 
stack base, physical stack height, stack inside diameter, stack gas exit 
velocity, stack gas exit temperature, and pollutant emission rate. Line 
sources require coordinates of the end points of the line, release 
height, emission rate, average line source width, average building 
width, average spacing between buildings, and average line source 
buoyancy parameter.
    (2) Meteorological data: surface weather data from a preprocessor 
such as PCRAMMET which provides hourly stability class, wind direction, 
wind speed, temperature, and mixing height.
    (3) Receptor data: locations and elevations of receptors, or 
location and size of receptor grid or request automatically generated 
receptor grid.

                                c. Output

    (1) Printed output (from a separate post-processor program) 
includes:
    (2) Total concentration or, optionally, source contribution 
analysis; monthly and annual frequency distributions for 1-, 3-, and 24-
hour average concentrations; tables of 1-, 3-, and 24-hour average 
concentrations at each receptor; table of the annual (or length of run) 
average concentrations at each receptor;
    (3) Five highest 1-, 3-, and 24-hour average concentrations at each 
receptor; and
    (4) Fifty highest 1-, 3-, and 24-hour concentrations over the 
receptor field.

                            d. Type of Model

    BLP is a gaussian plume model.

                           e. Pollutant Types

    BLP may be used to model primary pollutants. This model does not 
treat settling and deposition.

                     f. Source-Receptor Relationship

    (1) BLP treats up to 50 point sources, 10 parallel line sources, and 
100 receptors arbitrarily located.
    (2) User-input topographic elevation is applied for each stack and 
each receptor.

                            g. Plume Behavior

    (1) BLP uses plume rise formulas of Schulman and Scire (1980).
    (2) Vertical potential temperature gradients of 0.02 Kelvin per 
meter for E stability and 0.035 Kelvin per meter are used for stable 
plume rise calculations. An option for user input values is included.
    (3) Transitional rise is used for line sources.
    (4) Option to suppress the use of transitional plume rise for point 
sources is included.
    (5) The building downwash algorithm of Schulman and Scire (1980) is 
used.

                           h. Horizontal Winds

    (1) Constant, uniform (steady-state) wind is assumed for an hour.
    Straight line plume transport is assumed to all downwind distances.
    (2) Wind speeds profile exponents of 0.10, 0.15, 0.20, 0.25, 0.30, 
and 0.30 are used for stability classes A through F, respectively. An 
option for user-defined values and an option to suppress the use of the 
wind speed profile feature are included.

                         i. Vertical Wind Speed

    Vertical wind speed is assumed equal to zero.

                        j. Horizontal Dispersion

    (1) Rural dispersion coefficients are from Turner (1969), with no 
adjustment made for variations in surface roughness or averaging time.
    (2) Six stability classes are used.

                         k. Vertical Dispersion

    (1) Rural dispersion coefficients are from Turner (1969), with no 
adjustment made for variations in surface roughness.

[[Page 538]]

    (2) Six stability classes are used.
    (3) Mixing height is accounted for with multiple reflections until 
the vertical plume standard deviation equals 1.6 times the mixing 
height; uniform mixing is assumed beyond that point.
    (4) Perfect reflection at the ground is assumed.

                       l. Chemical Transformation

    Chemical transformations are treated using linear decay. Decay rate 
is input by the user.

                           m. Physical Removal

    Physical removal is not explicitly treated.

                          n. Evaluation Studies

    Schulman, L.L. and J.S. Scire, 1980. Buoyant Line and Point Source 
(BLP) Dispersion Model User's Guide, P-7304B. Environmental Research and 
Technology, Inc., Concord, MA.
    Scire, J.S. and L.L. Schulman, 1981. Evaluation of the BLP and ISC 
Models with SF6 Tracer Data and SO2 Measurements 
at Aluminum Reduction Plants. APCA Specialty Conference on Dispersion 
Modeling for Complex Sources, St. Louis, MO.

                               A.3 CALINE3

                                Reference

    Benson, Paul E., 1979. CALINE3--A Versatile Dispersion Model for 
Predicting Air Pollutant Levels Near Highways and Arterial Streets. 
Interim Report, Report Number FHWA/CA/TL-79/23. Federal Highway 
Administration, Washington, DC (NTIS No. PB 80-220841).

                              Availability

    The CALINE3 model is available on diskette (as PB 95-502712) from 
NTIS. The source code and user's guide are also available on EPA's 
Internet SCRAM Web site ( Section A.0).

                                Abstract

    CALINE3 can be used to estimate the concentrations of nonreactive 
pollutants from highway traffic. This steady-state Gaussian model can be 
applied to determine air pollution concentrations at receptor locations 
downwind of ``at-grade,'' ``fill,'' ``bridge,'' and ``cut section'' 
highways located in relatively uncomplicated terrain. The model is 
applicable for any wind direction, highway orientation, and receptor 
location. The model has adjustments for averaging time and surface 
roughness, and can handle up to 20 links and 20 receptors. It also 
contains an algorithm for deposition and settling velocity so that 
particulate concentrations can be predicted.

                  a. Recommendations for Regulatory Use

    CALINE-3 is appropriate for the following applications:
     Highway (line) sources;
     Urban or rural areas;
     Simple terrain;
     Transport distances less than 50 kilometers; and
     One-hour to 24-hour averaging times.

                          b. Input Requirements

    (1) Source data: up to 20 highway links classed as ``at-grade,'' 
``fill,'' ``bridge,'' or ``depressed''; coordinates of link end points; 
traffic volume; emission factor; source height; and mixing zone width.
    (2) Meteorological data: wind speed, wind angle (measured in degrees 
clockwise from the Y axis), stability class, mixing height, ambient 
(background to the highway) concentration of pollutant.
    (3) Receptor data: coordinates and height above ground for each 
receptor.

                                c. Output

    Printed output includes concentration at each receptor for the 
specified meteorological condition.

                            d. Type of Model

    CALINE-3 is a Gaussian plume model.

                           e. Pollutant Types

    CALINE-3 may be used to model primary pollutants.

                     f. Source-Receptor Relationship

    (1) Up to 20 highway links are treated.
    (2) CALINE-3 applies user input location and emission rate for each 
link. User-input receptor locations are applied.

                            g. Plume Behavior

    Plume rise is not treated.

                           h. Horizontal Winds

    (1) User-input hourly wind speed and direction are applied.
    (2) Constant, uniform (steady-state) wind is assumed for an hour.

                         i. Vertical Wind Speed

    Vertical wind speed is assumed equal to zero.

                        j. Horizontal Dispersion

    (1) Six stability classes are used.
    (2) Rural dispersion coefficients from Turner (1969) are used, with 
adjustment for roughness length and averaging time.
    (3) Initial traffic-induced dispersion is handled implicitly by 
plume size parameters.

[[Page 539]]

                         k. Vertical Dispersion

    (1) Six stability classes are used.
    (2) Empirical dispersion coefficients from Benson (1979) are used 
including an adjustment for roughness length.
    (3) Initial traffic-induced dispersion is handled implicitly by 
plume size parameters.
    (4) Adjustment for averaging time is included.

                       l. Chemical Transformation

    Not treated.

                           m. Physical Removal

    Optional deposition calculations are included.

                          n. Evaluation Studies

    Bemis, G.R. et al., 1977. Air Pollution and Roadway Location, 
Design, and Operation--Project Overview. FHWA-CA-TL-7080-77-25, Federal 
Highway Administration, Washington, DC.
    Cadle, S.H. et al., 1976. Results of the General Motors Sulfate 
Dispersion Experiment, GMR-2107. General Motors Research Laboratories, 
Warren, MI.
    Dabberdt, W.F., 1975. Studies of Air Quality on and Near Highways, 
Project 2761. Stanford Research Institute, Menlo Park, CA.
    Environmental Protection Agency, 1986. Evaluation of Mobile Source 
Air Quality Simulation Models. EPA Publication No. EPA-450/4-86-002. 
Office of Air Quality Planning & Standards, Research Triangle Park, NC. 
(NTIS No. PB 86-167293)

                               A.4 CALPUFF

                               References

    Scire, J.S., D.G. Strimaitis and R.J. Yamartino, 2000. A User's 
Guide for the CALPUFF Dispersion Model (Version 5.0). Earth Tech, Inc., 
Concord, MA.
    Scire J.S., F.R. Robe, M.E. Fernau and R.J. Yamartino, 2000. A 
User's Guide for the CALMET Meteorological Model (Version 5.0). Earth 
Tech, Inc., Concord, MA.

                              Availability

    The model code and its documentation are available at no cost for 
download from the model developers' Internet Web site: http://
www.src.com/calpuff/calpuff1.htm. You may also contact Joseph Scire, 
Earth Tech, Inc., 196 Baker Avenue, Concord, MA 01742; Telephone: (978) 
371-4270; Fax: (978) 371-2468; e-mail: [email protected].

                                Abstract

    CALPUFF is a multi-layer, multi-species non-steady-state puff 
dispersion modeling system that simulates the effects of time- and 
space-varying meteorological conditions on pollutant transport, 
transformation, and removal. CALPUFF is intended for use on scales from 
tens of meters from a source to hundreds of kilometers. It includes 
algorithms for near-field effects such as stack tip downwash, building 
downwash, transitional buoyant and momentum plume rise, rain cap 
effects, partial plume penetration, subgrid scale terrain and coastal 
interactions effects, and terrain impingement as well as longer range 
effects such as pollutant removal due to wet scavenging and dry 
deposition, chemical transformation, vertical wind shear effects, 
overwater transport, plume fumigation, and visibility effects of 
particulate matter concentrations.

                  a. Recommendations for Regulatory Use

    (1) CALPUFF is appropriate for long range transport (source-receptor 
distances of 50 to several hundred kilometers) of emissions from point, 
volume, area, and line sources. The meteorological input data should be 
fully characterized with time-and-space-varying three dimensional wind 
and meteorological conditions using CALMET, as discussed in paragraphs 
8.3(d) and 8.3.1.2(d) of Appendix W.
    (2) CALPUFF may also be used on a case-by-case basis if it can be 
demonstrated using the criteria in Section 3.2 that the model is more 
appropriate for the specific application. The purpose of choosing a 
modeling system like CALPUFF is to fully treat stagnation, wind 
reversals, and time and space variations of meteorological conditions on 
transport and dispersion, as discussed in paragraph 7.2.8(a).
    (3) For regulatory applications of CALMET and CALPUFF, the 
regulatory default option should be used. Inevitably, some of the model 
control options will have to be set specific for the application using 
expert judgment and in consultation with the appropriate reviewing 
authorities.

                          b. Input Requirements

    Source Data:
    1. Point sources: Source location, stack height, diameter, exit 
velocity, exit temperature, base elevation, wind direction specific 
building dimensions (for building downwash calculations), and emission 
rates for each pollutant. Particle size distributions may be entered for 
particulate matter. Temporal emission factors (diurnal cycle, monthly 
cycle, hour/season, wind speed/stability class, or temperature-dependent 
emission factors) may also be entered. Arbitrarily-varying point source 
parameters may be entered from an external file.
    2. Area sources: Source location and shape, release height, base 
elevation, initial vertical distribution ([sigma]z) and 
emission rates for each pollutant. Particle size distributions

[[Page 540]]

may be entered for particulate matter. Temporal emission factors 
(diurnal cycle, monthly cycle, hour/season, wind speed/stability class, 
or temperature-dependent emission factors) may also be entered. 
Arbitrarily-varying area source parameters may be entered from an 
external file. Area sources specified in the external file are allowed 
to be buoyant and their location, size, shape, and other source 
characteristics are allowed to change in time.
    3. Volume sources: Source location, release height, base elevation, 
initial horizontal and vertical distributions ([sigma]y, 
[sigma]z) and emission rates for each pollutant. Particle 
size distributions may be entered for particulate matter. Temporal 
emission factors (diurnal cycle, monthly cycle, hour/season, wind speed/
stability class, or temperature-dependent emission factors) may also be 
entered. Arbitrarily-varying volume source parameters may be entered 
from an external file. Volume sources with buoyancy can be simulated by 
treating the source as a point source and entering initial plume size 
parameters--initial ([sigma]y, [sigma]z)--to 
define the initial size of the volume source.
    4. Line sources: Source location, release height, base elevation, 
average buoyancy parameter, and emission rates for each pollutant. 
Building data may be entered for line source emissions experiencing 
building downwash effects. Particle size distributions may be entered 
for particulate matter. Temporal emission factors (diurnal cycle, 
monthly cycle, hour/season, wind speed/stability class, or temperature-
dependent emission factors) may also be entered. Arbitrarily-varying 
line source parameters may be entered from an external file.
    Meteorological Data (different forms of meteorological input can be 
used by CALPUFF):
    1. Time-dependent three-dimensional (3-D) meteorological fields 
generated by CALMET. This is the preferred mode for running CALPUFF. 
Data inputs used by CALMET include surface observations of wind speed, 
wind direction, temperature, cloud cover, ceiling height, relative 
humidity, surface pressure, and precipitation (type and amount), and 
upper air sounding data (wind speed, wind direction, temperature, and 
height) and air-sea temperature differences (over water). Optional 3-D 
meteorological prognostic model output (e.g., from models such as MM5, 
RUC, Eta and RAMS) can be used by CALMET as well (paragraph 8.3.1.2(d)). 
CALMET contains an option to be run in ``No-observations'' mode (Robe et 
al., 2002), which allows the 3-D CALMET meteorological fields to be 
based on prognostic model output alone, without observations. This 
allows CALMET and CALPUFF to be run in prognostic mode for forecast 
applications.
    2. Single station surface and upper air meteorological data in 
CTDMPLUS data file formats (SURFACE.DAT and PROFILE.DAT files) or AERMOD 
data file formats. These options allow a vertical variation in the 
meteorological parameters but no horizontal spatial variability.
    3. Single station meteorological data in ISCST3 data file format. 
This option does not account for variability of the meteorological 
parameters in the horizontal or vertical, except as provided for by the 
use of stability-dependent wind shear exponents and average temperature 
lapse rates.
    Gridded terrain and land use data are required as input into CALMET 
when Option 1 is used. Geophysical processor programs are provided that 
interface the modeling system to standard terrain and land use data 
bases available from various sources such as the U.S. Geological Survey 
(USGS) and the National Aeronautics and Space Administration (NASA).
    Receptor Data:
    CALPUFF includes options for gridded and non-gridded (discrete) 
receptors. Special subgrid-scale receptors are used with the subgrid-
scale complex terrain option. An option is provided for discrete 
receptors to be placed at ground-level or above the local ground level 
(i.e., flagpole receptors). Gridded and subgrid-scale receptors are 
placed at the local ground level only.
    Other Input:
    CALPUFF accepts hourly observations of ozone concentrations for use 
in its chemical transformation algorithm. Monthly concentrations of 
ammonia concentrations can be specified in the CALPUFF input file, 
although higher time-resolution ammonia variability can be computed 
using the POSTUTIL program. Subgrid-scale coastlines can be specified in 
its coastal boundary file. Optional, user-specified deposition 
velocities and chemical transformation rates can also be entered. 
CALPUFF accepts the CTDMPLUS terrain and receptor files for use in its 
subgrid-scale terrain algorithm. Inflow boundary conditions of modeled 
pollutants can be specified in a boundary condition file. Liquid water 
content variables including cloud water/ice and precipitation water/ice 
can be used as input for visibility analyses and other CALPUFF modules.

                                c. Output

    CALPUFF produces files of hourly concentrations of ambient 
concentrations for each modeled species, wet deposition fluxes, dry 
deposition fluxes, and for visibility applications, extinction 
coefficients. Postprocessing programs (PRTMET, CALPOST, CALSUM, APPEND, 
and POSTUTIL) provide options for summing, scaling, analyzing and 
displaying the modeling results. CALPOST contains options for computing 
of light extinction (visibility) and

[[Page 541]]

POSTUTIL allows the re-partitioning of nitric acid and nitrate to 
account for the effects of ammonia limitation (Scire et al., 2001; 
Escoffier-Czaja and Scire, 2002). CALPUFF contains an options to output 
liquid water concentrations for use in computing visible plume lengths 
and frequency of icing and fogging from cooling towers and other water 
vapor sources. The CALPRO Graphical User Interface (GUI) contains 
options for creating graphics such as contour plots, vector plots and 
other displays when linked to graphics software.

                            d. Type of Model

    (1) CALPUFF is a non-steady-state time- and space-dependent Gaussian 
puff model. CALPUFF treats primary pollutants and simulates secondary 
pollutant formation using a parameterized, quasi-linear chemical 
conversion mechanism. Pollutants treated include SO2, 
SO4=, NOX (i.e., NO + NO2), 
HNO3, NO3-, NH3, PM-10, PM-
2.5, toxic pollutants and others pollutant species that are either inert 
or subject to quasi-linear chemical reactions. The model includes a 
resistance-based dry deposition model for both gaseous pollutants and 
particulate matter. Wet deposition is treated using a scavenging 
coefficient approach. The model has detailed parameterizations of 
complex terrain effects, including terrain impingement, side-wall 
scrapping, and steep-walled terrain influences on lateral plume growth. 
A subgrid-scale complex terrain module based on a dividing streamline 
concept divides the flow into a lift component traveling over the 
obstacle and a wrap component deflected around the obstacle.
    (2) The meteorological fields used by CALPUFF are produced by the 
CALMET meteorological model. CALMET includes a diagnostic wind field 
model containing parameterized treatments of slope flows, valley flows, 
terrain blocking effects, and kinematic terrain effects, lake and sea 
breeze circulations, a divergence minimization procedure, and objective 
analysis of observational data. An energy-balance scheme is used to 
compute sensible and latent heat fluxes and turbulence parameters over 
land surfaces. A profile method is used over water. CALMET contains 
interfaces to prognostic meteorological models such as the Penn State/
NCAR Mesoscale Model (e.g., MM5; Section 12.0, ref. 86), as well as the 
RAMS, Ruc and Eta models.

                           e. Pollutant Types

    CALPUFF may be used to model gaseous pollutants or particulate 
matter that are inert or which undergo quasi-linear chemical reactions, 
such as SO2, SO4 =, NOX (i.e., NO + 
NO2), HNO3, NO3-, NH3, PM-
10, PM-2.5 and toxic pollutants. For regional haze analyses, sulfate and 
nitrate particulate components are explicitly treated.

                    f. Source-Receptor Relationships

    CALPUFF contains no fundamental limitations on the number of sources 
or receptors. Parameter files are provided that allow the user to 
specify the maximum number of sources, receptors, puffs, species, grid 
cells, vertical layers, and other model parameters. Its algorithms are 
designed to be suitable for source-receptor distances from tens of 
meters to hundreds of kilometers.

                            g. Plume Behavior

    Momentum and buoyant plume rise is treated according to the plume 
rise equations of Briggs (1975) for non-downwashing point sources, 
Schulman and Scire (1980) for line sources and point sources subject to 
building downwash effects using the Schulman-Scire downwash algorithm, 
and Zhang (1993) for buoyant area sources and point sources affected by 
building downwash when using the PRIME building downwash method. Stack 
tip downwash effects and partial plume penetration into elevated 
temperature inversions are included. An algorithm to treat horizontally-
oriented vents and stacks with rain caps is included.

                           h. Horizontal Winds

    A three-dimensional wind field is computed by the CALMET 
meteorological model. CALMET combines an objective analysis procedure 
using wind observations with parameterized treatments of slope flows, 
valley flows, terrain kinematic effects, terrain blocking effects, and 
sea/lake breeze circulations. CALPUFF may optionally use single station 
(horizontally-constant) wind fields in the CTDMPLUS, AERMOD or ISCST3 
data formats.

                         i. Vertical Wind Speed

    Vertical wind speeds are not used explicitly by CALPUFF. Vertical 
winds are used in the development of the horizontal wind components by 
CALMET.

                        j. Horizontal Dispersion

    Turbulence-based dispersion coefficients provide estimates of 
horizontal plume dispersion based on measured or computed values of 
[sigma]v. The effects of building downwash and buoyancy-
induced dispersion are included. The effects of vertical wind shear are 
included through the puff splitting algorithm. Options are provided to 
use Pasquill-Gifford (rural) and McElroy-Pooler (urban) dispersion 
coefficients. Initial plume size from area or volume sources is allowed.

[[Page 542]]

                         k. Vertical Dispersion

    Turbulence-based dispersion coefficients provide estimates of 
vertical plume dispersion based on measured or computed values of 
[sigma]w. The effects of building downwash and buoyancy-
induced dispersion are included. Vertical dispersion during convective 
conditions is simulated with a probability density function (pdf) model 
based on Weil et al. (1997). Options are provided to use Pasquill-
Gifford (rural) and McElroy-Pooler (urban) dispersion coefficients. 
Initial plume size from area or volume sources is allowed.

                       l. Chemical Transformation

    Gas phase chemical transformations are treated using parameterized 
models of SO2 conversion to SO4= and NO conversion 
to NO3-, HNO3, and NO2. Organic aerosol 
formation is treated. The POSTUTIL program contains an option to re-
partition HNO3 and NO3- in order to treat the 
effects of ammonia limitation.

                           m. Physical Removal

    Dry deposition of gaseous pollutants and particulate matter is 
parameterized in terms of a resistance-based deposition model. 
Gravitational settling, inertial impaction, and Brownian motion effects 
on deposition of particulate matter is included. CALPUFF contains an 
option to evaluate the effects of plume tilt resulting from 
gravitational settling. Wet deposition of gases and particulate matter 
is parameterized in terms of a scavenging coefficient approach.

                          n. Evaluation Studies

    Berman, S., J.Y. Ku, J. Zhang and S.T. Rao, 1977. Uncertainties in 
estimating the mixing depth--Comparing three mixing depth models with 
profiler measurements, Atmospheric Environment, 31: 3023-3039.
    Chang, J.C., P. Franzese, K. Chayantrakom and S.R. Hanna, 2001. 
Evaluations of CALPUFF, HPAC and VLSTRACK with Two Mesoscale Field 
Datasets. Journal of Applied Meteorology, 42(4): 453-466.
    Environmental Protection Agency, 1998. Interagency Workgroup on Air 
Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations for 
Modeling Long-Range Transport Impacts. EPA Publication No. EPA-454/R-98-
019. Office of Air Quality Planning & Standards, Research Triangle Park, 
NC.
    Irwin, J.S., 1997. A Comparison of CALPUFF Modeling Results with 
1997 INEL Field Data Results. In Air Pollution Modeling and its 
Application, XII. Edited by S.E. Gyrning and N. Chaumerliac. Plenum 
Press, New York, NY.
    Irwin, J.S., J.S. Scire and D.G. Strimaitis, 1996. A Comparison of 
CALPUFF Modeling Results with CAPTEX Field Data Results. In Air 
Pollution Modeling and its Application, XI. Edited by S.E. Gyrning and 
F.A. Schiermeier. Plenum Press, New York, NY.
    Morrison, K, Z-X Wu, J.S. Scire, J. Chenier and T. Jeffs-
Schonewille, 2003. CALPUFF-Based Predictive and Reactive Emission 
Control System. 96th A&WMA Annual Conference & Exhibition, 22-26 June 
2003; San Diego, CA.
    Schulman, L.L., D.G. Strimaitis and J.S. Scire, 2000. Development 
and evaluation of the PRIME Plume Rise and Building Downwash Model. 
JAWMA, 50: 378-390.
    Scire, J.S., Z-X Wu, D.G. Strimaitis and G.E. Moore, 2001. The 
Southwest Wyoming Regional CALPUFF Air Quality Modeling Study--Volume I. 
Prepared for the Wyoming Dept. of Environmental Quality. Available from 
Earth Tech at http://www.src.com.
    Strimaitis, D.G., J.S. Scire and J.C. Chang, 1998. Evaluation of the 
CALPUFF Dispersion Model with Two Power Plant Data Sets. Tenth Joint 
Conference on the Application of Air Pollution Meteorology, Phoenix, 
Arizona. American Meteorological Society, Boston, MA. January 11-16, 
1998.

   A.5 Complex Terrain Dispersion Model Plus Algorithms for Unstable 
                          Situations (CTDMPLUS)

                                Reference

    Perry, S.G., D.J. Burns, L.H. Adams, R.J. Paine, M.G. Dennis, M.T. 
Mills, D.G. Strimaitis, R.J. Yamartino and E.M. Insley, 1989. User's 
Guide to the Complex Terrain Dispersion Model Plus Algorithms for 
Unstable Situations (CTDMPLUS). Volume 1: Model Descriptions and User 
Instructions. EPA Publication No. EPA-600/8-89-041. Environmental 
Protection Agency, Research Triangle Park, NC. (NTIS No. PB 89-181424)
    Perry, S.G., 1992. CTDMPLUS: A Dispersion Model for Sources near 
Complex Topography. Part I: Technical Formulations. Journal of Applied 
Meteorology, 31(7): 633-645.

                              Availability

    This model code is available on EPA's Internet SCRAM Web site and 
also on diskette (as PB 90-504119) from the National Technical 
Information Service (Section A.0).

                                Abstract

    CTDMPLUS is a refined point source Gaussian air quality model for 
use in all stability conditions for complex terrain applications. The 
model contains, in its entirety, the technology of CTDM for stable and 
neutral conditions. However, CTDMPLUS can also simulate daytime, 
unstable conditions, and has a number of additional capabilities for 
improved user friendliness. Its use of meteorological data and terrain 
information is

[[Page 543]]

different from other EPA models; considerable detail for both types of 
input data is required and is supplied by preprocessors specifically 
designed for CTDMPLUS. CTDMPLUS requires the parameterization of 
individual hill shapes using the terrain preprocessor and the 
association of each model receptor with a particular hill.

                  a. Recommendation for Regulatory Use

    CTDMPLUS is appropriate for the following applications:
     Elevated point sources;
     Terrain elevations above stack top;
     Rural or urban areas;
     Transport distances less than 50 kilometers; and
     One hour to annual averaging times when used with 
a post-processor program such as CHAVG.

                          b. Input Requirements

    (1) Source data: For each source, user supplies source location, 
height, stack diameter, stack exit velocity, stack exit temperature, and 
emission rate; if variable emissions are appropriate, the user supplies 
hourly values for emission rate, stack exit velocity, and stack exit 
temperature.
    (2) Meteorological data: For applications of CTDMPLUS, multiple 
level (typically three or more) measurements of wind speed and 
direction, temperature and turbulence (wind fluctuation statistics) are 
required to create the basic meteorological data file (``PROFILE''). 
Such measurements should be obtained up to the representative plume 
height(s) of interest (i.e., the plume height(s) under those conditions 
important to the determination of the design concentration). The 
representative plume height(s) of interest should be determined using an 
appropriate complex terrain screening procedure (e.g., CTSCREEN) and 
should be documented in the monitoring/modeling protocol. The necessary 
meteorological measurements should be obtained from an appropriately 
sited meteorological tower augmented by SODAR and/or RASS if the 
representative plume height(s) of interest is above the levels 
represented by the tower measurements. Meteorological preprocessors then 
create a SURFACE data file (hourly values of mixed layer heights, 
surface friction velocity, Monin-Obukhov length and surface roughness 
length) and a RAWINsonde data file (upper air measurements of pressure, 
temperature, wind direction, and wind speed).
    (3) Receptor data: receptor names (up to 400) and coordinates, and 
hill number (each receptor must have a hill number assigned).
    (4) Terrain data: user inputs digitized contour information to the 
terrain preprocessor which creates the TERRAIN data file (for up to 25 
hills).

                                c. Output

    (1) When CTDMPLUS is run, it produces a concentration file, in 
either binary or text format (user's choice), and a list file containing 
a verification of model inputs, i.e.,
     Input meteorological data from ``SURFACE'' and 
``PROFILE''.
     Stack data for each source.
     Terrain information.
     Receptor information.
     Source-receptor location (line printer map).
    (2) In addition, if the case-study option is selected, the listing 
includes:
     Meteorological variables at plume height.
     Geometrical relationships between the source and 
the hill.
     Plume characteristics at each receptor, i.e.,

--Distance in along-flow and cross flow direction
--Effective plume-receptor height difference
--Effective [sigma]y & [sigma]z values, both flat 
terrain and hill induced (the difference shows the effect of the hill)
--Concentration components due to WRAP, LIFT and FLAT.
    (3) If the user selects the TOPN option, a summary table of the top 
4 concentrations at each receptor is given. If the ISOR option is 
selected, a source contribution table for every hour will be printed.
    (4) A separate disk file of predicted (1-hour only) concentrations 
(``CONC'') is written if the user chooses this option. Three forms of 
output are possible:
    (i) A binary file of concentrations, one value for each receptor in 
the hourly sequence as run;
    (ii) A text file of concentrations, one value for each receptor in 
the hourly sequence as run; or
    (iii) A text file as described above, but with a listing of receptor 
information (names, positions, hill number) at the beginning of the 
file.
    (3) Hourly information provided to these files besides the 
concentrations themselves includes the year, month, day, and hour 
information as well as the receptor number with the highest 
concentration.

                            d. Type of Model

    CTDMPLUS is a refined steady-state, point source plume model for use 
in all stability conditions for complex terrain applications.

                           e. Pollutant Types

    CTDMPLUS may be used to model non-reactive, primary pollutants.

                     f. Source-Receptor Relationship

    Up to 40 point sources, 400 receptors and 25 hills may be used. 
Receptors and sources are

[[Page 544]]

allowed at any location. Hill slopes are assumed not to exceed 15[deg], 
so that the linearized equation of motion for Boussinesq flow are 
applicable. Receptors upwind of the impingement point, or those 
associated with any of the hills in the modeling domain, require 
separate treatment.

                            g. Plume Behavior

    (1) As in CTDM, the basic plume rise algorithms are based on Briggs' 
(1975) recommendations.
    (2) A central feature of CTDMPLUS for neutral/stable conditions is 
its use of a critical dividing-streamline height (Hc) to 
separate the flow in the vicinity of a hill into two separate layers. 
The plume component in the upper layer has sufficient kinetic energy to 
pass over the top of the hill while streamlines in the lower portion are 
constrained to flow in a horizontal plane around the hill. Two separate 
components of CTDMPLUS compute ground-level concentrations resulting 
from plume material in each of these flows.
    (3) The model calculates on an hourly (or appropriate steady 
averaging period) basis how the plume trajectory (and, in stable/neutral 
conditions, the shape) is deformed by each hill. Hourly profiles of wind 
and temperature measurements are used by CTDMPLUS to compute plume rise, 
plume penetration (a formulation is included to handle penetration into 
elevated stable layers, based on Briggs (1984)), convective scaling 
parameters, the value of Hc, and the Froude number above 
Hc.

                           h. Horizontal Winds

    CTDMPLUS does not simulate calm meteorological conditions. Both 
scalar and vector wind speed observations can be read by the model. If 
vector wind speed is unavailable, it is calculated from the scalar wind 
speed. The assignment of wind speed (either vector or scalar) at plume 
height is done by either:
     Interpolating between observations above and 
below the plume height, or
     Extrapolating (within the surface layer) from the 
nearest measurement height to the plume height.

                         i. Vertical Wind Speed

    Vertical flow is treated for the plume component above the critical 
dividing streamline height (Hc); see ``Plume Behavior''.

                        j. Horizontal Dispersion

    Horizontal dispersion for stable/neutral conditions is related to 
the turbulence velocity scale for lateral fluctuations, 
[sigma]v, for which a minimum value of 0.2 m/s is used. 
Convective scaling formulations are used to estimate horizontal 
dispersion for unstable conditions.

                         k. Vertical Dispersion

    Direct estimates of vertical dispersion for stable/neutral 
conditions are based on observed vertical turbulence intensity, e.g., 
[sigma]w (standard deviation of the vertical velocity 
fluctuation). In simulating unstable (convective) conditions, CTDMPLUS 
relies on a skewed, bi-Gaussian probability density function (pdf) 
description of the vertical velocities to estimate the vertical 
distribution of pollutant concentration.

                       l. Chemical Transformation

    Chemical transformation is not treated by CTDMPLUS.

                           m. Physical Removal

    Physical removal is not treated by CTDMPLUS (complete reflection at 
the ground/hill surface is assumed).

                          n. Evaluation Studies

    Burns, D.J., L.H. Adams and S.G. Perry, 1990. Testing and Evaluation 
of the CTDMPLUS Dispersion Model: Daytime Convective Conditions. 
Environmental Protection Agency, Research Triangle Park, NC.
    Paumier, J.O., S.G. Perry and D.J. Burns, 1990. An Analysis of 
CTDMPLUS Model Predictions with the Lovett Power Plant Data Base. 
Environmental Protection Agency, Research Triangle Park, NC.
    Paumier, J.O., S.G. Perry and D.J. Burns, 1992. CTDMPLUS: A 
Dispersion Model for Sources near Complex Topography. Part II: 
Performance Characteristics. Journal of Applied Meteorology, 31(7): 646-
660.

             A.6 Offshore and Coastal Dispersion Model (OCD)

                                Reference

    DiCristofaro, D.C. and S.R. Hanna, 1989. OCD: The Offshore and 
Coastal Dispersion Model, Version 4. Volume I: User's Guide, and Volume 
II: Appendices. Sigma Research Corporation, Westford, MA. (NTIS Nos. PB 
93-144384 and PB 93-144392; also available at http://www.epa.gov/
scram001/)

                              Availability

    This model code is available on EPA's Internet SCRAM Web site and 
also on diskette (as PB 91-505230) from the National Technical 
Information Service (see Section A.0). Official contact at Minerals 
Management Service: Mr. Dirk Herkhof, Parkway Atrium Building, 381 Elden 
Street, Herndon, VA 20170, Phone: (703) 787-1735.

                                Abstract

    (1) OCD is a straight-line Gaussian model developed to determine the 
impact of offshore emissions from point, area or line sources on the air 
quality of coastal regions.

[[Page 545]]

OCD incorporates overwater plume transport and dispersion as well as 
changes that occur as the plume crosses the shoreline. Hourly 
meteorological data are needed from both offshore and onshore locations. 
These include water surface temperature, overwater air temperature, 
mixing height, and relative humidity.
    (2) Some of the key features include platform building downwash, 
partial plume penetration into elevated inversions, direct use of 
turbulence intensities for plume dispersion, interaction with the 
overland internal boundary layer, and continuous shoreline fumigation.

                  a. Recommendations for Regulatory Use

    OCD has been recommended for use by the Minerals Management Service 
for emissions located on the Outer Continental Shelf (50 FR 12248; 28 
March 1985). OCD is applicable for overwater sources where onshore 
receptors are below the lowest source height. Where onshore receptors 
are above the lowest source height, offshore plume transport and 
dispersion may be modeled on a case-by-case basis in consultation with 
the appropriate reviewing authority (paragraph 3.0(b)).

                          b. Input Requirements

    (1) Source data: Point, area or line source location, pollutant 
emission rate, building height, stack height, stack gas temperature, 
stack inside diameter, stack gas exit velocity, stack angle from 
vertical, elevation of stack base above water surface and gridded 
specification of the land/water surfaces. As an option, emission rate, 
stack gas exit velocity and temperature can be varied hourly.
    (2) Meteorological data (over water): Wind direction, wind speed, 
mixing height, relative humidity, air temperature, water surface 
temperature, vertical wind direction shear (optional), vertical 
temperature gradient (optional), turbulence intensities (optional).
    (2) Meteorological data:
    Over land: Surface weather data from a preprocessor such as PCRAMMET 
which provides hourly stability class, wind direction, wind speed, 
ambient temperature, and mixing height are required.
    Over water: Hourly values for mixing height, relative humidity, air 
temperature, and water surface temperature are required; if wind speed/
direction are missing, values over land will be used (if available); 
vertical wind direction shear, vertical temperature gradient, and 
turbulence intensities are optional.
    (3) Receptor data: Location, height above local ground-level, 
ground-level elevation above the water surface.

                                c. Output

    (1) All input options, specification of sources, receptors and land/
water map including locations of sources and receptors.
    (2) Summary tables of five highest concentrations at each receptor 
for each averaging period, and average concentration for entire run 
period at each receptor.
    (3) Optional case study printout with hourly plume and receptor 
characteristics. Optional table of annual impact assessment from non-
permanent activities.
    (4) Concentration files written to disk or tape can be used by 
ANALYSIS postprocessor to produce the highest concentrations for each 
receptor, the cumulative frequency distributions for each receptor, the 
tabulation of all concentrations exceeding a given threshold, and the 
manipulation of hourly concentration files.

                            d. Type of Model

    OCD is a Gaussian plume model constructed on the framework of the 
MPTER model.

                           e. Pollutant Types

    OCD may be used to model primary pollutants. Settling and deposition 
are not treated.

                     f. Source-Receptor Relationship

    (1) Up to 250 point sources, 5 area sources, or 1 line source and 
180 receptors may be used.
    (2) Receptors and sources are allowed at any location.
    (3) The coastal configuration is determined by a grid of up to 3600 
rectangles. Each element of the grid is designated as either land or 
water to identify the coastline.

                            g. Plume Behavior

    (1) As in ISC, the basic plume rise algorithms are based on Briggs' 
recommendations.
    (2) Momentum rise includes consideration of the stack angle from the 
vertical.
    (3) The effect of drilling platforms, ships, or any overwater 
obstructions near the source are used to decrease plume rise using a 
revised platform downwash algorithm based on laboratory experiments.
    (4) Partial plume penetration of elevated inversions is included 
using the suggestions of Briggs (1975) and Weil and Brower (1984).
    (5) Continuous shoreline fumigation is parameterized using the 
Turner method where complete vertical mixing through the thermal 
internal boundary layer (TIBL) occurs as soon as the plume intercepts 
the TIBL.

                           h. Horizontal Winds

    (1) Constant, uniform wind is assumed for each hour.

[[Page 546]]

    (2) Overwater wind speed can be estimated from overland wind speed 
using relationship of Hsu (1981).
    (3) Wind speed profiles are estimated using similarity theory 
(Businger, 1973). Surface layer fluxes for these formulas are calculated 
from bulk aerodynamic methods.

                         i. Vertical Wind Speed

    Vertical wind speed is assumed equal to zero.

                        j. Horizontal Dispersion

    (1) Lateral turbulence intensity is recommended as a direct estimate 
of horizontal dispersion. If lateral turbulence intensity is not 
available, it is estimated from boundary layer theory. For wind speeds 
less than 8 m/s, lateral turbulence intensity is assumed inversely 
proportional to wind speed.
    (2) Horizontal dispersion may be enhanced because of obstructions 
near the source. A virtual source technique is used to simulate the 
initial plume dilution due to downwash.
    (3) Formulas recommended by Pasquill (1976) are used to calculate 
buoyant plume enhancement and wind direction shear enhancement.
    (4) At the water/land interface, the change to overland dispersion 
rates is modeled using a virtual source. The overland dispersion rates 
can be calculated from either lateral turbulence intensity or Pasquill-
Gifford curves. The change is implemented where the plume intercepts the 
rising internal boundary layer.

                         k. Vertical Dispersion

    (1) Observed vertical turbulence intensity is not recommended as a 
direct estimate of vertical dispersion. Turbulence intensity should be 
estimated from boundary layer theory as default in the model. For very 
stable conditions, vertical dispersion is also a function of lapse rate.
    (2) Vertical dispersion may be enhanced because of obstructions near 
the source. A virtual source technique is used to simulate the initial 
plume dilution due to downwash.
    (3) Formulas recommended by Pasquill (1976) are used to calculate 
buoyant plume enhancement.
    (4) At the water/land interface, the change to overland dispersion 
rates is modeled using a virtual source. The overland dispersion rates 
can be calculated from either vertical turbulence intensity or the 
Pasquill-Gifford coefficients. The change is implemented where the plume 
intercepts the rising internal boundary layer.

                       1. Chemical Transformation

    Chemical transformations are treated using exponential decay. 
Different rates can be specified by month and by day or night.

                           m. Physical Removal

    Physical removal is also treated using exponential decay.

                          n. Evaluation Studies

    DiCristofaro, D.C. and S.R. Hanna, 1989. OCD: The Offshore and 
Coastal Dispersion Model. Volume I: User's Guide. Sigma Research 
Corporation, Westford, MA.
    Hanna, S.R., L.L. Schulman, R.J. Paine and J.E. Pleim, 1984. The 
Offshore and Coastal Dispersion (OCD) Model User's Guide, Revised. OCS 
Study, MMS 84-0069. Environmental Research & Technology, Inc., Concord, 
MA. (NTIS No. PB 86-159803).
    Hanna, S.R., L.L. Schulman, R.J. Paine, J.E. Pleim and M. Baer, 
1985. Development and Evaluation of the Offshore and Coastal Dispersion 
(OCD) Model. Journal of the Air Pollution Control Association, 35: 1039-
1047.
    Hanna, S.R. and D.C. DiCristofaro, 1988. Development and Evaluation 
of the OCD/API Model. Final Report, API Pub. 4461, American Petroleum 
Institute, Washington, DC.

                              A. REFERENCES

    Benson, P.E., 1979. CALINE3--A Versatile Dispersion Model for 
Predicting Air Pollution Levels Near Highways and Arterial Streets. 
Interim Report, Report Number FHWA/CA/TL-79/23. Federal Highway 
Administration, Washington, DC.
    Briggs, G.A., 1975. Plume Rise Predictions. Lectures on Air 
Pollution and Environmental Impact Analyses. American Meteorological 
Society, Boston, MA, pp. 59-111.
    Briggs, G.A., 1984. Analytical Parameterizations of Diffusion: The 
Convective Boundary Layer. Journal of Climate and Applied Meteorology, 
24(11): 1167-1186.
    Environmental Protection Agency, 1980. Recommendations on Modeling 
(October 1980 Meetings). Appendix G to: Summary of Comments and 
Responses on the October 1980 Proposed Revisions to the Guideline on Air 
Quality Models. Meteorology and Assessment Division, Office of Research 
and Development, Research Triangle Park, NC 27711.
    Environmental Protection Agency, 1998. Interagency Workgroup on Air 
Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations for 
Modeling Long-Range Transport Impacts. Publication No. EPA-454/R-98-019. 
(NTIS No. PB 99-121089).
    Escoffier-Czaja, C. and J.S. Scire, 2002. The Effects of Ammonia 
Limitation on Nitrate Aerosol Formation and Visibility Impacts in Class 
I Areas. Twelfth AMS/AWMA Conference on the Application of Air Pollution 
Meteorology, 20-24 May 2002; Norfolk, VA.
    Gifford, F.A., Jr. 1976. Turbulent Diffusion Typing Schemes--A 
Review. Nuclear Safety, 17: 68-86.

[[Page 547]]

    Horst, T.W., 1983. A Correction to the Gaussian Source-depletion 
Model. In Precipitation Scavenging, Dry Deposition and Resuspension. H. 
R. Pruppacher, R.G. Semonin and W.G.N. Slinn, eds., Elsevier, NY.
    Hsu, S.A., 1981. Models for Estimating Offshore Winds from Onshore 
Meteorological Measurements. Boundary Layer Meteorology, 20: 341-352.
    Huber, A.H. and W.H. Snyder, 1976. Building Wake Effects on Short 
Stack Effluents. Third Symposium on Atmospheric Turbulence, Diffusion 
and Air Quality, American Meteorological Society, Boston, MA.
    Irwin, J.S., 1979. A Theoretical Variation of the Wind Profile 
Power-Law Exponent as a Function of Surface Roughness and Stability. 
Atmospheric Environment, 13: 191-194.
    Liu, M.K. et al., 1976. The Chemistry, Dispersion, and Transport of 
Air Pollutants Emitted from Fossil Fuel Power Plants in California: Data 
Analysis and Emission Impact Model. Systems Applications, Inc., San 
Rafael, CA.
    Pasquill, F., 1976. Atmospheric Dispersion Parameters in Gaussian 
Plume Modeling Part II. Possible Requirements for Change in the Turner 
Workbook Values. Publication No. EPA-600/4-76-030b. Office of Air 
Quality Planning & Standards, Research Triangle Park, NC 27711.
    Petersen, W.B., 1980. User's Guide for HIWAY-2 A Highway Air 
Pollution Model. Publication No. EPA-600/8-80-018. Office of Research & 
Development, Research Triangle Park, NC 27711. (NTIS PB 80-227556)
    Rao, T.R. and M.T. Keenan, 1980. Suggestions for Improvement of the 
EPA-HIWAY Model. Journal of the Air Pollution Control Association, 30: 
247-256 (and reprinted as Appendix C in Petersen, 1980).
    Robe, F.R., Z-X. Wu and J.S. Scire, 2002: Real-time SO2 
Forecasting System with Combined ETA Analysis and CALPUFF Modeling. 
Proceedings of the 8th International Conference on Harmonisation within 
Atmospheric Dispersion Modelling for Regulatory Purposes, 14-17 October 
2002; Sofia, Bulgaria.
    Schulman, L.L. and J.S. Scire, 1980: Buoyant Line and Point Source 
(BLP) dispersion model user's guide. The Aluminum Association; 
Washington, DC. (See A.2 in this appendix.)
    Schulman, L.L. and S.R. Hanna, 1986. Evaluation of Downwash 
Modification to the Industrial Source Complex Model. Journal of the Air 
Pollution Control Association, 36: 258-264.
    Segal, H.M., 1983. Microcomputer Graphics in Atmospheric Dispersion 
Modeling. Journal of the Air Pollution Control Association, 23: 598-600.
    Snyder, W.H., R.S. Thompson, R.E. Eskridge, R.E. Lawson, I.P. 
Castro, J.T. Lee, J.C.R. Hunt, and Y. Ogawa, 1985. The structure of the 
strongly stratified flow over hills: Dividing streamline concept. 
Journal of Fluid Mechanics, 152: 249-288.
    Turner, D.B., 1969. Workbook of Atmospheric Dispersion Estimates. 
PHS Publication No. 999-26. U.S. Environmental Protection Agency, 
Research Triangle, Park, NC 27711.
    Weil, J.C. and R.P. Brower, 1984. An Updated Gaussian Plume Model 
for Tall Stacks. Journal of the Air Pollution Control Association, 34: 
818-827.
    Weil, J.C., 1996. A new dispersion algorithm for stack sources in 
building wakes, Paper 6.6. Ninth Joint Conference on Applications of Air 
Pollution Meteorology with A&WMA, January 28-February 2, 1996. Atlanta, 
GA.
    Weil, J.C., L.A. Corio, and R.P. Brower, 1997. A PDF dispersion 
model for buoyant plumes in the convective boundary layer. Journal of 
Applied Meteorology, 36: 982-1003.
    Zhang, X., 1993. A computational analysis of the rise, dispersion, 
and deposition of buoyant plumes. Ph.D. Thesis, Massachusetts Institute 
of Technology, Cambridge, MA.
    Zhang, X. and A.F. Ghoniem, 1993. A computational model for the rise 
and dispersion of wind-blown, buoyancy-driven plumes--I. Neutrally 
stratified atmosphere. Atmospheric Environment, 15: 2295-2311.

[70 FR 68228, Nov. 9, 2005]

     Appendix X to Part 51--Examples of Economic Incentive Programs

                       I. Introduction and Purpose

    This appendix contains examples of EIP's which are covered by the 
EIP rules. Program descriptions identify key provisions which 
distinguish the different model program types. The examples provide 
additional information and guidance on various types of regulatory 
programs collectively referred to as EIP's. The examples include 
programs involving stationary, area, and mobile sources. The definition 
section at 40 CFR 51.491 defines an EIP as a program which may include 
State established emission fees or a system of marketable permits, or a 
system of State fees on sale or manufacture of products the use of which 
contributes to O3 formation, or any combination of the 
foregoing or other similar measures, as well as incentives and 
requirements to reduce vehicle emissions and vehicle miles traveled in 
the area, including any of the transportation control measures 
identified in section 108(f). Such programs span a wide spectrum of 
program designs.
    The EIP's are comprised of several elements that, in combination 
with each other, must insure that the fundamental principles of any 
regulatory program (including accountability, enforceability and 
noninterference with other requirements of the Act)

[[Page 548]]

are met. There are many possible combinations of program elements that 
would be acceptable. Also, it is important to emphasize that the 
effectiveness of an EIP is dependent upon the particular area in which 
it is implemented. No two areas face the same air quality circumstances 
and, therefore, effective strategies and programs will differ among 
areas.
    Because of these considerations, the EPA is not specifying one 
particular design or type of strategy as acceptable for any given EIP. 
Such specific guidance would potentially discourage States (or other 
entities with delegated authority to administer parts of an 
implementation plan) from utilizing other equally viable program designs 
that may be more appropriate for their situation. Thus, the examples 
given in this Appendix are general in nature so as to avoid limiting 
innovation on the part of the States in developing programs tailored to 
individual State needs.
    Another important consideration in designing effective EIP's is the 
extent to which different strategies, or programs targeted at different 
types of sources, can complement one another when implemented together 
as an EIP ``package.'' The EPA encourages States to consider packaging 
different measures together when such a strategy is likely to increase 
the overall benefits from the program as a whole. Furthermore, some 
activities, such as information distribution or public awareness 
programs, while not EIP's in and of themselves, are often critical to 
the success of other measures and, therefore, would be appropriate 
complementary components of a program package. All SIP emissions 
reductions credits should reflect a consideration of the effectiveness 
of the entire package.

    II. Examples of Stationary and Mobile Source Economic Incentive 
                               Strategies

    There is a wide variety of programs that fall under the general 
heading of EIP's. Further, within each general type of program are 
several different basic program designs. This section describes common 
types of EIP's that have been implemented, designed, or discussed in the 
literature for stationary and mobile sources. The program types 
discussed below do not include all of the possible types of EIP's. 
Innovative approaches incorporating new ideas in existing programs, 
different combinations of existing program elements, or wholly new 
incentive systems provide additional opportunities for States to find 
ways to meet environmental goals at lower total cost.

                      A. Emissions Trading Markets

    One prominent class of EIP's is based upon the creation of a market 
in which trading of source-specific emissions requirements may occur. 
Such programs may include traditional rate-based emissions limits 
(generally referred to as emissions averaging) or overall limits on a 
source's total mass emissions per unit of time (generally referred to as 
an emissions cap). The emissions limits, which may be placed on 
individual emitting units or on facilities as a whole, may decline over 
time. The common feature of such programs is that sources have an 
ongoing incentive to reduce pollution and increased flexibility in 
meeting their regulatory requirements. A source may meet its own 
requirements either by directly preventing or controlling emissions or 
by trading or averaging with another source. Trading or averaging may 
occur within the same facility, within the same firm, or between 
different firms. Sources with lower cost abatement alternatives may 
provide the necessary emissions reductions to sources facing more 
expensive alternatives. These programs can lower the overall cost of 
meeting a given total level of abatement. All sources eligible to trade 
in an emissions market are faced with continuing incentives to find 
better ways of reducing emissions at the lowest possible cost, even if 
they are already meeting their own emissions requirements.
    Stationary, area, and mobile sources could be allowed to participate 
in a common emissions trading market. Programs involving emissions 
trading markets are particularly effective at reducing overall costs 
when individual affected sources face significantly different emissions 
control costs. A wider range in control costs among affected sources 
creates greater opportunities for cost-reducing trades. Thus, for 
example, areas which face relatively high stationary source control 
costs relative to mobile source control costs benefit most by including 
both stationary and mobile sources in a single emissions trading market.
    Programs involving emissions trading markets have generally been 
designated as either emission allowance or emission reduction credit 
(ERC) trading programs. The Federal Acid Rain Program is an example of 
an emission allowance trading program, while ``bubbles'' and ``generic 
bubbles'' created under the EPA's 1986 Emission Trading Policy Statement 
are examples of ERC trading. Allowance trading programs can establish 
emission allocations to be effective at the start of a program, at some 
specific time in the future, or at varying levels over time. An ERC 
trading program requires ERC's to be measured against a pre-established 
emission baseline. Allowance allocations or emission baselines can be 
established either directly by the EIP rules or by reference to 
traditional regulations (e.g., RACT requirements). In either type of 
program, sources can either meet their EIP requirements by maintaining 
their own emissions within the

[[Page 549]]

limits established by the program, or by buying surplus allowances or 
ERC's from other sources. In any case, the State will need to establish 
adequate enforceable procedures for certifying and tracking trades, and 
for monitoring and enforcing compliance with the EIP.
    The definition of the commodity to be traded and the design of the 
administrative procedures the buyer and seller must follow to complete a 
trade are obvious elements that must be carefully selected to help 
ensure a successful trading market that achieves the desired 
environmental goal at the lowest cost. An emissions market is defined as 
efficient if it achieves the environmental goal at the lowest possible 
total cost. Any feature of a program that unnecessarily increases the 
total cost without helping achieve the environmental goals causes market 
inefficiency. Thus, the design of an emission trading program should be 
evaluated not only in terms of the likelihood that the program design 
will ensure that the environmental goals of the program will be met, but 
also in terms of the costs that the design imposes upon market 
transactions and the impact of those costs on market efficiency.
    Transaction costs are the investment in time and resources to 
acquire information about the price and availability of allowances or 
ERC's, to negotiate a trade, and to assure the trade is properly 
recorded and legally enforceable. All trading markets impose some level 
of transaction costs. The level of transaction costs in an emissions 
trading market are affected by various aspects of the design of the 
market, such as the nature of the procedures for reviewing, approving, 
and recording trades, the timing of such procedures (i.e., before or 
after the trade is made), uncertainties in the value of the allowance or 
credit being traded, the legitimacy of the allowance or credit being 
offered for sale, and the long-term integrity of the market itself. 
Emissions trading programs in which every transaction is different, such 
as programs requiring significant consideration of the differences in 
the chemical properties or geographic location of the emissions, can 
result in higher transaction costs than programs with a standardized 
trading commodity and well-defined rules for acceptable trades. 
Transaction costs are also affected by the relative ease with which 
information can be obtained about the availability and price of 
allowances or credits.
    While the market considerations discussed above are clearly 
important in designing an efficient market to minimize the transaction 
costs of such a program, other considerations, such as regulatory 
certainty, enforcement issues, and public acceptance, also clearly need 
to be factored into the design of any emissions trading program.

                             B. Fee Programs

    A fee on each unit of emissions is a strategy that can provide a 
direct incentive for sources to reduce emissions. Ideally, fees should 
be set so as to result in emissions being reduced to the socially 
optimal level considering the costs of control and the benefits of the 
emissions reductions. In order to motivate a change in emissions, the 
fees must be high enough that sources will actively seek to reduce 
emissions. It is important to note that not all emission fee programs 
are designed to motivate sources to lower emissions. Fee programs using 
small fees are designed primarily to generate revenue, often to cover 
some of the administrative costs of a regulatory program.
    There can be significant variations in emission fee programs. For 
example, potential emissions could be targeted by placing a fee on an 
input (e.g., a fee on the quantity and BTU content of fuel used in an 
industrial boiler) rather than on actual emissions. Sources paying a fee 
on potential emissions could be eligible for a fee waiver or rebate by 
demonstrating that potential emissions are not actually emitted, such as 
through a carbon absorber system on a coating operation.
    Some fee program variations are designed to mitigate the potentially 
large amount of revenue that a fee program could generate. Although more 
complex than a simple fee program, programs that reduce or eliminate the 
total revenues may be more readily adopted in a SIP than a simple 
emission fee. Some programs lower the amount of total revenues generated 
by waiving the fee on some emissions. These programs reduce the total 
amount of revenue generated, while providing an incentive to decrease 
emissions. Alternatively, a program may impose higher per-unit fees on a 
portion of the emissions stream, providing a more powerful but targeted 
incentive at the same revenue levels. For example, fees could be 
collected on all emissions in excess of some fixed level. The level 
could be set as a percentage of a baseline (e.g., fees on emissions 
above some percentage of historical emissions), or as the lowest 
emissions possible (e.g., fees on emissions in excess of the lowest 
demonstrated emissions from the source category).
    Other fee programs are ``revenue neutral,'' meaning that the 
pollution control agency does not receive any net revenues. One way to 
design a revenue-neutral program is to have both a fee provision and a 
rebate provision. Rebates must be carefully designed to avoid lessening 
the incentive provided by the emission fee. For example, a rebate based 
on comparing a source's actual emissions and the average emissions for 
the source category can be designed to be revenue neutral and not 
diminish the incentive.
    Other types of fee programs collect a fee in relation to particular 
activities or types of

[[Page 550]]

products to encourage the use of alternatives. While these fees are not 
necessarily directly linked to the total amount of emissions from the 
activity or product, the relative simplicity of a usage fee may make 
such programs an effective way to lower emissions. An area source 
example is a construction permit fee for wood stoves. Such a permit fee 
is directly related to the potential to emit inherent in a wood stove, 
and not to the actual emissions from each wood stove in use. Fees on raw 
materials to a manufacturing process can encourage product reformulation 
(e.g., fees on solvent sold to makers of architectural coatings) or 
changes in work practices (e.g., fees on specialty solvents and 
degreasing compounds used in manufacturing).
    Road pricing mechanisms are fee programs that are available to 
curtail low occupancy vehicle use, fund transportation system 
improvements and control measures, spatially and temporally shift 
driving patterns, and attempt to effect land usage changes. Primary 
examples include increased peak period roadway, bridge, or tunnel tolls 
(this could also be accomplished with automated vehicle identification 
systems as well), and toll discounts for pooling arrangements and zero-
emitting/low-emitting vehicles.

                    C. Tax Code and Zoning Provisions

    Modifications to existing State or local tax codes, zoning 
provisions, and land use planning can provide effective economic 
incentives. Possible modifications to encourage emissions reductions 
cover a broad span of programs, such as accelerated depreciation of 
capital equipment used for emissions reductions, corporate income tax 
deductions or credits for emission abatement costs, property tax waivers 
based on decreasing emissions, exempting low-emitting products from 
sales tax, and limitations on parking spaces for office facilities. 
Mobile source strategies include waiving or lowering any of the 
following for zero- or low-emitting vehicles: vehicle registration fees, 
vehicle property tax, sales tax, taxicab license fees, and parking 
taxes.

                              D. Subsidies

    A State may create incentives for reducing emissions by offering 
direct subsidies, grants or low-interest loans to encourage the purchase 
of lower-emitting capital equipment, or a switch to less polluting 
operating practices. Examples of such programs include clean vehicle 
conversions, starting shuttle bus or van pool programs, and mass transit 
fare subsidies. Subsidy programs often suffer from a variety of ``free 
rider'' problems. For instance, subsidies for people or firms who were 
going to switch to the cleaner alternative anyway lower the 
effectiveness of the subsidy program, or drive up the cost of achieving 
a targeted level of emissions reductions.

                   E. Transportation Control Measures

    The following measures are the TCM's listed in section 108(f):
    (i) Programs for improved public transit;
    (ii) Restriction of certain roads or lanes to, or construction of 
such roads or lanes for use by, passenger buses or high occupancy 
vehicles;
    (iii) Employer-based transportation management plans, including 
incentives;
    (iv) Trip-reduction ordinances;
    (v) Traffic flow improvement programs that achieve emission 
reductions;
    (vi) Fringe and transportation corridor parking facilities serving 
multiple-occupancy vehicle programs or transit service;
    (vii) Programs to limit or restrict vehicle use in downtown areas or 
other areas of emission concentration particularly during periods of 
peak use;
    (viii) Programs for the provision of all forms of high-occupancy, 
shared-ride services;
    (ix) Programs to limit portions of road surfaces or certain sections 
of the metropolitan area to the use of non-motorized vehicles or 
pedestrian use, both as to time and place;
    (x) Programs for secure bicycle storage facilities and other 
facilities, including bicycle lanes, for the convenience and protection 
of bicyclists, in both public and private areas;
    (xi) Programs to control extended idling of vehicles;
    (xii) Programs to reduce motor vehicle emissions, consistent with 
title II, which are caused by extreme cold start conditions;
    (xiii) Employer-sponsored programs to permit flexible work 
schedules;
    (xiv) Programs and ordinances to facilitate non-automobile travel, 
provision and utilization of mass transit, and to generally reduce the 
need for single-occupant vehicle travel, as part of transportation 
planning and development efforts of a locality, including programs and 
ordinances applicable to new shopping centers, special events, and other 
centers of vehicle activity;
    (xv) Programs for new construction and major reconstruction of 
paths, tracks or areas solely for the use by pedestrian or other non-
motorized means of transportation when economically feasible and in the 
public interest. For purposes of this clause, the Administrator shall 
also consult with the Secretary of the Interior; and
    (xvi) Programs to encourage the voluntary removal from use and the 
marketplace of pre-1980 model year light-duty vehicles and pre-1980 
model light-duty trucks.

[59 FR 16715, Apr. 7, 1994]

[[Page 551]]

  Appendix Y to Part 51--Guidelines for BART Determinations Under the 
                           Regional Haze Rule

                            Table of Contents

I. Introduction and Overview
A. What is the purpose of the guidelines?
B. What does the CAA require generally for improving visibility?
C. What is the BART requirement in the CAA?
D. What types of visibility problems does EPA address in its 
regulations?
E. What are the BART requirements in EPA's regional haze regulations?
F. What is included in the guidelines?
G. Who is the target audience for the guidelines?
H. Do EPA regulations require the use of these guidelines?
II. How to Identify BART-eligible Sources
A. What are the steps in identifying BART-eligible sources?
1. Step 1: Identify emission units in the BART categories
2. Step 2: Identify the start-up dates of the emission units
3. Step 3: Compare the potential emissions to the 250 ton/yr cutoff
4. Final step: Identify the emission units and pollutants that 
constitute the BART-eligible source.
III. How to Identify Sources ``Subject to BART''
IV. The BART Determination: Analysis of BART Options
A. What factors must I address in the BART Analysis?
B. What is the scope of the BART review?
C. How does a BART review relate to maximum achievable control 
technology (MACT) standards under CAA section 112?
D. What are the five basic steps of a case-by-case BART analysis?
1. Step 1: How do I identify all available retrofit emission control 
techniques?
2. Step 2: How do I determine whether the options identified in Step 1 
are technically feasible?
3. Step 3: How do I evaluate technically feasible alternatives?
4. Step 4: For a BART review, what impacts am I expected to calculate 
and report? What methods does EPA recommend for the impacts analyses?
a. Impact analysis part 1: how do I estimate the costs of control?
b. What do we mean by cost effectiveness?
c. How do I calculate average cost effectiveness?
d. How do I calculate baseline emissions?
e. How do I calculate incremental cost effectiveness?
f. What other information should I provide in the cost impacts analysis?
g. What other things are important to consider in the cost impacts 
analysis?
h. Impact analysis part 2: How should I analyze and report energy 
impacts?
i. Impact analysis part 3: How do I analyze ``non-air quality 
environmental impacts?''
j. Impact analysis part 4: What are examples of non-air quality 
environmental impacts?
k. How do I take into account a project's ``remaining useful life'' in 
calculating control costs?
5. Step 5: How should I determine visibility impacts in the BART 
determination?
E. How do I select the ``best'' alternative, using the results of Steps 
1 through 5?
1. Summary of the impacts analysis
2. Selecting a ``best'' alternative
3. In selecting a ``best'' alternative, should I consider the 
affordability of controls?
4. SO2 limits for utility boilers
5. NOX limits for utility boilers
V. Enforceable Limits/Compliance Date

                      I. Introduction and Overview

                A. What is the purpose of the guidelines?

    The Clean Air Act (CAA), in sections 169A and 169B, contains 
requirements for the protection of visibility in 156 scenic areas across 
the United States. To meet the CAA's requirements, we published 
regulations to protect against a particular type of visibility 
impairment known as ``regional haze.'' The regional haze rule is found 
in this part at 40 CFR 51.300 through 51.309. These regulations require, 
in 40 CFR 51.308(e), that certain types of existing stationary sources 
of air pollutants install best available retrofit technology (BART). The 
guidelines are designed to help States and others (1) identify those 
sources that must comply with the BART requirement, and (2) determine 
the level of control technology that represents BART for each source.

    B. What does the CAA require generally for improving visibility?

    Section 169A of the CAA, added to the CAA by the 1977 amendments, 
requires States to protect and improve visibility in certain scenic 
areas of national importance. The scenic areas protected by section 169A 
are ``the mandatory Class I Federal Areas * * * where visibility is an 
important value.'' In these guidelines, we refer to these as ``Class I 
areas.'' There are 156 Class I areas, including 47 national parks (under 
the jurisdiction of the Department of Interior--National Park Service), 
108 wilderness areas (under the jurisdiction of the Department of the 
Interior--Fish and Wildlife Service or the Department of Agriculture--
U.S. Forest Service), and one International Park (under the jurisdiction 
of the Roosevelt-Campobello International Commission). The Federal

[[Page 552]]

Agency with jurisdiction over a particular Class I area is referred to 
in the CAA as the Federal Land Manager. A complete list of the Class I 
areas is contained in 40 CFR 81.401 through 81.437, and you can find a 
map of the Class I areas at the following Internet site: http://
www.epa.gov/ttn/oarpg/t1/fr--notices/classimp.gif.
    The CAA establishes a national goal of eliminating man-made 
visibility impairment from all Class I areas. As part of the plan for 
achieving this goal, the visibility protection provisions in the CAA 
mandate that EPA issue regulations requiring that States adopt measures 
in their State implementation plans (SIPs), including long-term 
strategies, to provide for reasonable progress towards this national 
goal. The CAA also requires States to coordinate with the Federal Land 
Managers as they develop their strategies for addressing visibility.

               C. What is the BART requirement in the CAA?

    1. Under section 169A(b)(2)(A) of the CAA, States must require 
certain existing stationary sources to install BART. The BART provision 
applies to ``major stationary sources'' from 26 identified source 
categories which have the potential to emit 250 tons per year or more of 
any air pollutant. The CAA requires only sources which were put in place 
during a specific 15-year time interval to be subject to BART. The BART 
provision applies to sources that existed as of the date of the 1977 CAA 
amendments (that is, August 7, 1977) but which had not been in operation 
for more than 15 years (that is, not in operation as of August 7, 1962).
    2. The CAA requires BART review when any source meeting the above 
description ``emits any air pollutant which may reasonably be 
anticipated to cause or contribute to any impairment of visibility'' in 
any Class I area. In identifying a level of control as BART, States are 
required by section 169A(g) of the CAA to consider:
    (a) The costs of compliance,
    (b) The energy and non-air quality environmental impacts of 
compliance,
    (c) Any existing pollution control technology in use at the source,
    (d) The remaining useful life of the source, and
    (e) The degree of visibility improvement which may reasonably be 
anticipated from the use of BART.
    3. The CAA further requires States to make BART emission limitations 
part of their SIPs. As with any SIP revision, States must provide an 
opportunity for public comment on the BART determinations, and EPA's 
action on any SIP revision will be subject to judicial review.

      D. What types of visibility problems does EPA address in its 
                              regulations?

    1. We addressed the problem of visibility in two phases. In 1980, we 
published regulations addressing what we termed ``reasonably 
attributable'' visibility impairment. Reasonably attributable visibility 
impairment is the result of emissions from one or a few sources that are 
generally located in close proximity to a specific Class I area. The 
regulations addressing reasonably attributable visibility impairment are 
published in 40 CFR 51.300 through 51.307.
    2. On July 1, 1999, we amended these regulations to address the 
second, more common, type of visibility impairment known as ``regional 
haze.'' Regional haze is the result of the collective contribution of 
many sources over a broad region. The regional haze rule slightly 
modified 40 CFR 51.300 through 51.307, including the addition of a few 
definitions in Sec. 51.301, and added new Sec. Sec. 51.308 and 51.309.

  E. What are the BART requirements in EPA's regional haze regulations?

    1. In the July 1, 1999 rulemaking, we added a BART requirement for 
regional haze. We amended the BART requirements in 2005. You will find 
the BART requirements in 40 CFR 51.308(e). Definitions of terms used in 
40 CFR 51.308(e)(1) are found in 40 CFR 51.301.
    2. As we discuss in detail in these guidelines, the regional haze 
rule codifies and clarifies the BART provisions in the CAA. The rule 
requires that States identify and list ``BART-eligible sources,'' that 
is, that States identify and list those sources that fall within the 26 
source categories, were put in place during the 15-year window of time 
from 1962 to 1977, and have potential emissions greater than 250 tons 
per year. Once the State has identified the BART-eligible sources, the 
next step is to identify those BART-eligible sources that may ``emit any 
air pollutant which may reasonably be anticipated to cause or contribute 
to any impairment of visibility.'' Under the rule, a source which fits 
this description is ``subject to BART.'' For each source subject to 
BART, 40 CFR 51.308(e)(1)(ii)(A) requires that States identify the level 
of control representing BART after considering the factors set out in 
CAA section 169A(g), as follows:

--States must identify the best system of continuous emission control 
technology for each source subject to BART taking into account the 
technology available, the costs of compliance, the energy and non-air 
quality environmental impacts of compliance, any pollution control 
equipment in use at the source, the remaining useful life of the source, 
and the degree of visibility improvement that may be expected from 
available control technology.


[[Page 553]]


    3. After a State has identified the level of control representing 
BART (if any), it must establish an emission limit representing BART and 
must ensure compliance with that requirement no later than 5 years after 
EPA approves the SIP. States may establish design, equipment, work 
practice or other operational standards when limitations on measurement 
technologies make emission standards infeasible.

                 F. What is included in the guidelines?

    1. The guidelines provide a process for making BART determinations 
that States can use in implementing the regional haze BART requirements 
on a source-by-source basis, as provided in 40 CFR 51.308(e)(1). States 
must follow the guidelines in making BART determinations on a source-by-
source basis for 750 megawatt (MW) power plants but are not required to 
use the process in the guidelines when making BART determinations for 
other types of sources.
    2. The BART analysis process, and the contents of these guidelines, 
are as follows:
    (a) Identification of all BART-eligible sources. Section II of these 
guidelines outlines a step-by-step process for identifying BART-eligible 
sources.
    (b) Identification of sources subject to BART. As noted above, 
sources ``subject to BART'' are those BART-eligible sources which ``emit 
a pollutant which may reasonably be anticipated to cause or contribute 
to any impairment of visibility in any Class I area.'' We discuss 
considerations for identifying sources subject to BART in section III of 
the guidance.
    (c) The BART determination process. For each source subject to BART, 
the next step is to conduct an analysis of emissions control 
alternatives. This step includes the identification of available, 
technically feasible retrofit technologies, and for each technology 
identified, an analysis of the cost of compliance, the energy and non-
air quality environmental impacts, and the degree of visibility 
improvement in affected Class I areas resulting from the use of the 
control technology. As part of the BART analysis, the State should also 
take into account the remaining useful life of the source and any 
existing control technology present at the source. For each source, the 
State will determine a ``best system of continuous emission reduction'' 
based upon its evaluation of these factors. Procedures for the BART 
determination step are described in section IV of these guidelines.
    (d) Emissions limits. States must establish emission limits, 
including a deadline for compliance, consistent with the BART 
determination process for each source subject to BART. Considerations 
related to these limits are discussed in section V of these guidelines.

            G. Who is the target audience for the guidelines?

    1. The guidelines are written primarily for the benefit of State, 
local and Tribal agencies, and describe a process for making the BART 
determinations and establishing the emission limitations that must be 
included in their SIPs or Tribal implementation plans (TIPs). Throughout 
the guidelines, which are written in a question and answer format, we 
ask questions ``How do I * * *? '' and answer with phrases ``you should 
* * *, you must * * * '' The ``you'' means a State, local or Tribal 
agency conducting the analysis. We have used this format to make the 
guidelines simpler to understand, but we recognize that States have the 
authority to require source owners to assume part of the analytical 
burden, and that there will be differences in how the supporting 
information is collected and documented. We also recognize that data 
collection, analysis, and rule development may be performed by Regional 
Planning Organizations, for adoption within each SIP or TIP.
    2. The preamble to the 1999 regional haze rule discussed at length 
the issue of Tribal implementation of the requirements to submit a plan 
to address visibility. As explained there, requirements related to 
visibility are among the programs for which Tribes may be determined 
eligible and receive authorization to implement under the ``Tribal 
Authority Rule'' (``TAR'') (40 CFR 49.1 through 49.11). Tribes are not 
subject to the deadlines for submitting visibility implementation plans 
and may use a modular approach to CAA implementation. We believe there 
are very few BART-eligible sources located on Tribal lands. Where such 
sources exist, the affected Tribe may apply for delegation of 
implementation authority for this rule, following the process set forth 
in the TAR.

       H. Do EPA regulations require the use of these guidelines?

    Section 169A(b) requires us to issue guidelines for States to follow 
in establishing BART emission limitations for fossil-fuel fired power 
plants having a capacity in excess of 750 megawatts. This document 
fulfills that requirement, which is codified in 40 CFR 
51.308(e)(1)(ii)(B). The guidelines establish an approach to 
implementing the requirements of the BART provisions of the regional 
haze rule; we believe that these procedures and the discussion of the 
requirements of the regional haze rule and the CAA should be useful to 
the States. For sources other than 750 MW power plants, however, States 
retain the discretion to adopt approaches that differ from the 
guidelines.

                II. How To Identify BART-Eligible Sources

    This section provides guidelines on how to identify BART-eligible 
sources. A BART-eligible source is an existing stationary source

[[Page 554]]

in any of 26 listed categories which meets criteria for startup dates 
and potential emissions.

       A. What are the steps in identifying BART-eligible sources?

    Figure 1 shows the steps for identifying whether the source is a 
``BART-eligible source:''
    Step 1: Identify the emission units in the BART categories,
    Step 2: Identify the start-up dates of those emission units, and
    Step 3: Compare the potential emissions to the 250 ton/yr cutoff.
    Figure 1. How to determine whether a source is BART-eligible:
    Step 1: Identify emission units in the BART categories

Does the plant contain emissions units in one or more of the 26 source 
          categories?
 [rtarr2] No [rtarr2] Stop
 [rtarr2] Yes [rtarr2] Proceed to Step 2

    Step 2: Identify the start-up dates of these emission units

Do any of these emissions units meet the following two tests?
In existence on August 7, 1977
     AND
Began operation after August 7, 1962
 [rtarr2] No [rtarr2] Stop
 [rtarr2] Yes [rtarr2] Proceed to Step 3

    Step 3: Compare the potential emissions from these emission units to 
the 250 ton/yr cutoff

Identify the ``stationary source'' that includes the emission units you 
identified in Step 2.
Add the current potential emissions from all the emission units 
identified in Steps 1 and 2 that are included within the ``stationary 
source'' boundary.
Are the potential emissions from these units 250 tons per year or more 
for any visibility-impairing pollutant?
 [rtarr2] No [rtarr2] Stop
 [rtarr2] Yes [rtarr2] These emissions units comprise the ``BART-
eligible source.''

        1. Step 1: Identify Emission Units in the BART Categories

    1. The BART requirement only applies to sources in specific 
categories listed in the CAA. The BART requirement does not apply to 
sources in other source categories, regardless of their emissions. The 
listed categories are:
    (1) Fossil-fuel fired steam electric plants of more than 250 million 
British thermal units (BTU) per hour heat input,
    (2) Coal cleaning plants (thermal dryers),
    (3) Kraft pulp mills,
    (4) Portland cement plants,
    (5) Primary zinc smelters,
    (6) Iron and steel mill plants,
    (7) Primary aluminum ore reduction plants,
    (8) Primary copper smelters,
    (9) Municipal incinerators capable of charging more than 250 tons of 
refuse per day,
    (10) Hydrofluoric, sulfuric, and nitric acid plants,
    (11) Petroleum refineries,
    (12) Lime plants,
    (13) Phosphate rock processing plants,
    (14) Coke oven batteries,
    (15) Sulfur recovery plants,
    (16) Carbon black plants (furnace process),
    (17) Primary lead smelters,
    (18) Fuel conversion plants,
    (19) Sintering plants,
    (20) Secondary metal production facilities,
    (21) Chemical process plants,
    (22) Fossil-fuel boilers of more than 250 million BTUs per hour heat 
input,
    (23) Petroleum storage and transfer facilities with a capacity 
exceeding 300,000 barrels,
    (24) Taconite ore processing facilities,
    (25) Glass fiber processing plants, and
    (26) Charcoal production facilities.
    2. Some plants may have emission units from more than one category, 
and some emitting equipment may fit into more than one category. 
Examples of this situation are sulfur recovery plants at petroleum 
refineries, coke oven batteries and sintering plants at steel mills, and 
chemical process plants at refineries. For Step 1, you identify all of 
the emissions units at the plant that fit into one or more of the listed 
categories. You do not identify emission units in other categories.

    Example: A mine is collocated with an electric steam generating 
plant and a coal cleaning plant. You would identify emission units 
associated with the electric steam generating plant and the coal 
cleaning plant, because they are listed categories, but not the mine, 
because coal mining is not a listed category.

    3. The category titles are generally clear in describing the types 
of equipment to be listed. Most of the category titles are very broad 
descriptions that encompass all emission units associated with a plant 
site (for example, ``petroleum refining'' and ``kraft pulp mills''). 
This same list of categories appears in the PSD regulations. States and 
source owners need not revisit any interpretations of the list made 
previously for purposes of the PSD program. We provide the following 
clarifications for a few of the category titles:
    (1) ``Steam electric plants of more than 250 million BTU/hr heat 
input.'' Because the category refers to ``plants,'' we interpret this 
category title to mean that boiler capacities should be aggregated to 
determine whether the 250 million BTU/hr threshold is reached. This 
definition includes only those plants that generate electricity for 
sale. Plants

[[Page 555]]

that cogenerate steam and electricity also fall within the definition of 
``steam electric plants''. Similarly, combined cycle turbines are also 
considered ``steam electric plants'' because such facilities incorporate 
heat recovery steam generators. Simple cycle turbines, in contrast, are 
not ``steam electric plants'' because these turbines typically do not 
generate steam.

    Example: A stationary source includes a steam electric plant with 
three 100 million BTU/hr boilers. Because the aggregate capacity exceeds 
250 million BTU/hr for the ``plant,'' these boilers would be identified 
in Step 2.

    (2) ``Fossil-fuel boilers of more than 250 million BTU/hr heat 
input.'' We interpret this category title to cover only those boilers 
that are individually greater than 250 million BTU/hr. However, an 
individual boiler smaller than 250 million BTU/hr should be subject to 
BART if it is an integral part of a process description at a plant that 
is in a different BART category--for example, a boiler at a Kraft pulp 
mill that, in addition to providing steam or mechanical power, uses the 
waste liquor from the process as a fuel. In general, if the process uses 
any by-product of the boiler and the boiler's function is to serve the 
process, then the boiler is integral to the process and should be 
considered to be part of the process description.
    Also, you should consider a multi-fuel boiler to be a ``fossil-fuel 
boiler'' if it burns any amount of fossil fuel. You may take federally 
and State enforceable operational limits into account in determining 
whether a multi-fuel boiler's fossil fuel capacity exceeds 250 million 
Btu/hr.
    (3) ``Petroleum storage and transfer facilities with a capacity 
exceeding 300,000 barrels.'' The 300,000 barrel cutoff refers to total 
facility-wide tank capacity for tanks that were put in place within the 
1962-1977 time period, and includes gasoline and other petroleum-derived 
liquids.
    (4) ``Phosphate rock processing plants.'' This category descriptor 
is broad, and includes all types of phosphate rock processing 
facilities, including elemental phosphorous plants as well as fertilizer 
production plants.
    (5) ``Charcoal production facilities.'' We interpret this category 
to include charcoal briquet manufacturing and activated carbon 
production.
    (6) ``Chemical process plants.'' and pharmaceutical manufacturing. 
Consistent with past policy, we interpret the category ``chemical 
process plants'' to include those facilities within the 2-digit Standard 
Industrial Classification (SIC) code 28. Accordingly, we interpret the 
term ``chemical process plants'' to include pharmaceutical manufacturing 
facilities.
    (7) ``Secondary metal production.'' We interpret this category to 
include nonferrous metal facilities included within SIC code 3341, and 
secondary ferrous metal facilities that we also consider to be included 
within the category ``iron and steel mill plants.''
    (8) ``Primary aluminum ore reduction.'' We interpret this category 
to include those facilities covered by 40 CFR 60.190, the new source 
performance standard (NSPS) for primary aluminum ore reduction plants. 
This definition is also consistent with the definition at 40 CFR 63.840.

      2. Step 2: Identify the Start-Up Dates of the Emission Units

    1. Emissions units listed under Step 1 are BART-eligible only if 
they were ``in existence'' on August 7, 1977 but were not ``in 
operation'' before August 7, 1962.

           What does ``in existence on August 7, 1977'' mean?

    2. The regional haze rule defines ``in existence'' to mean that:
    ``the owner or operator has obtained all necessary preconstruction 
approvals or permits required by Federal, State, or local air pollution 
emissions and air quality laws or regulations and either has (1) begun, 
or caused to begin, a continuous program of physical on-site 
construction of the facility or (2) entered into binding agreements or 
contractual obligations, which cannot be canceled or modified without 
substantial loss to the owner or operator, to undertake a program of 
construction of the facility to be completed in a reasonable time.'' 40 
CFR 51.301.
    As this definition is essentially identical to the definition of 
``commence construction'' as that term is used in the PSD regulations, 
the two terms mean the same thing. See 40 CFR 51.165(a)(1)(xvi) and 40 
CFR 52.21(b)(9). Under this definition, an emissions unit could be ``in 
existence'' even if it did not begin operating until several years after 
1977.

    Example: The owner of a source obtained all necessary permits in 
early 1977 and entered into binding construction agreements in June 
1977. Actual on-site construction began in late 1978, and construction 
was completed in mid-1979. The source began operating in September 1979. 
The emissions unit was ``in existence'' as of August 7, 1977.

    Major stationary sources which commenced construction AFTER August 
7, 1977 (i.e., major stationary sources which were not ``in existence'' 
on August 7, 1977) were subject to new source review (NSR) under the PSD 
program. Thus, the August 7, 1977 ``in existence'' test is essentially 
the same thing as the identification of emissions units that were 
grandfathered from the NSR review requirements of the 1977 CAA 
amendments.

[[Page 556]]

    3. Sources are not BART-eligible if the only change at the plant 
during the relevant time period was the addition of pollution controls. 
For example, if the only change at a copper smelter during the 1962 
through 1977 time period was the addition of acid plants for the 
reduction of SO2 emissions, these emission controls would not 
by themselves trigger a BART review.

         What does ``in operation before August 7, 1962'' mean?

    An emissions unit that meets the August 7, 1977 ``in existence'' 
test is not BART-eligible if it was in operation before August 7, 1962. 
``In operation'' is defined as ``engaged in activity related to the 
primary design function of the source.'' This means that a source must 
have begun actual operations by August 7, 1962 to satisfy this test.

    Example: The owner or operator entered into binding agreements in 
1960. Actual on-site construction began in 1961, and construction was 
complete in mid-1962. The source began operating in September 1962. The 
emissions unit was not ``in operation'' before August 7, 1962 and is 
therefore subject to BART.

                   What is a ``reconstructed source?'

    1. Under a number of CAA programs, an existing source which is 
completely or substantially rebuilt is treated as a new source. Such 
``reconstructed'' sources are treated as new sources as of the time of 
the reconstruction. Consistent with this overall approach to 
reconstructions, the definition of BART-eligible facility (reflected in 
detail in the definition of ``existing stationary facility'') includes 
consideration of sources that were in operation before August 7, 1962, 
but were reconstructed during the August 7, 1962 to August 7, 1977 time 
period.
    2. Under the regional haze regulations at 40 CFR 51.301, a 
reconstruction has taken place if ``the fixed capital cost of the new 
component exceeds 50 percent of the fixed capital cost of a comparable 
entirely new source.'' The rule also states that ``[a]ny final decision 
as to whether reconstruction has occurred must be made in accordance 
with the provisions of Sec. Sec. 60.15 (f)(1) through (3) of this 
title.'' ``[T]he provisions of Sec. Sec. 60.15(f)(1) through (3)'' 
refers to the general provisions for New Source Performance Standards 
(NSPS). Thus, the same policies and procedures for identifying 
reconstructed ``affected facilities'' under the NSPS program must also 
be used to identify reconstructed ``stationary sources'' for purposes of 
the BART requirement.
    3. You should identify reconstructions on an emissions unit basis, 
rather than on a plantwide basis. That is, you need to identify only the 
reconstructed emission units meeting the 50 percent cost criterion. You 
should include reconstructed emission units in the list of emission 
units you identified in Step 1. You need consider as possible 
reconstructions only those emissions units with the potential to emit 
more than 250 tons per year of any visibility-impairing pollutant.
    4. The ``in operation'' and ``in existence'' tests apply to 
reconstructed sources. If an emissions unit was reconstructed and began 
actual operation before August 7, 1962, it is not BART-eligible. 
Similarly, any emissions unit for which a reconstruction ``commenced'' 
after August 7, 1977, is not BART-eligible.

         How are modifications treated under the BART provision?

    1. The NSPS program and the major source NSR program both contain 
the concept of modifications. In general, the term ``modification'' 
refers to any physical change or change in the method of operation of an 
emissions unit that results in an increase in emissions.
    2. The BART provision in the regional haze rule contains no explicit 
treatment of modifications or how modified emissions units, previously 
subject to the requirement to install best available control technology 
(BACT), lowest achievable emission rate (LAER) controls, and/or NSPS are 
treated under the rule. As the BART requirements in the CAA do not 
appear to provide any exemption for sources which have been modified 
since 1977, the best interpretation of the CAA visibility provisions is 
that a subsequent modification does not change a unit's construction 
date for the purpose of BART applicability. Accordingly, if an emissions 
unit began operation before 1962, it is not BART-eligible if it was 
modified between 1962 and 1977, so long as the modification is not also 
a ``reconstruction.'' On the other hand, an emissions unit which began 
operation within the 1962-1977 time window, but was modified after 
August 7, 1977, is BART-eligible. We note, however, that if such a 
modification was a major modification that resulted in the installation 
of controls, the State will take this into account during the review 
process and may find that the level of controls already in place are 
consistent with BART.

   3. Step 3: Compare the Potential Emissions to the 250 Ton/Yr Cutoff

    The result of Steps 1 and 2 will be a list of emissions units at a 
given plant site, including reconstructed emissions units, that are 
within one or more of the BART categories and that were placed into 
operation within the 1962-1977 time window. The third step is to 
determine whether the total emissions represent a current potential to 
emit that is greater than 250 tons per year of any single visibility 
impairing pollutant. Fugitive

[[Page 557]]

emissions, to the extent quantifiable, must be counted. In most cases, 
you will add the potential emissions from all emission units on the list 
resulting from Steps 1 and 2. In a few cases, you may need to determine 
whether the plant contains more than one ``stationary source'' as the 
regional haze rule defines that term, and as we explain further below.

                    What pollutants should I address?

    Visibility-impairing pollutants include the following:
    (1) Sulfur dioxide (SO2),
    (2) Nitrogen oxides (NOX), and
    (3) Particulate matter.
    You may use PM10 as an indicator for particulate matter 
in this intial step. [Note that we do not recommend use of total 
suspended particulates (TSP) as in indicator for particulate matter.] As 
emissions of PM10 include the components of PM2.5 
as a subset, there is no need to have separate 250 ton thresholds for 
PM10 and PM2.5; 250 tons of PM10 
represents at most 250 tons of PM2.5, and at most 250 tons of 
any individual particulate species such as elemental carbon, crustal 
material, etc.
    However, if you determine that a source of particulate matter is 
BART-eligible, it will be important to distinguish between the fine and 
coarse particle components of direct particulate emissions in the 
remainder of the BART analysis, including for the purpose of modeling 
the source's impact on visibility. This is because although both fine 
and coarse particulate matter contribute to visibility impairment, the 
long-range transport of fine particles is of particular concern in the 
formation of regional haze. Thus, for example, air quality modeling 
results used in the BART determination will provide a more accurate 
prediction of a source's impact on visibility if the inputs into the 
model account for the relative particle size of any directly emitted 
particulate matter (i.e. PM10 vs. PM2.5).
    You should exercise judgment in deciding whether the following 
pollutants impair visibility in an area:
    (4) Volatile organic compounds (VOC), and
    (5) Ammonia and ammonia compounds.
    You should use your best judgment in deciding whether VOC or ammonia 
emissions from a source are likely to have an impact on visibility in an 
area. Certain types of VOC emissions, for example, are more likely to 
form secondary organic aerosols than others.\1\ Similarly, controlling 
ammonia emissions in some areas may not have a significant impact on 
visibility. You need not provide a formal showing of an individual 
decision that a source of VOC or ammonia emissions is not subject to 
BART review. Because air quality modeling may not be feasible for 
individual sources of VOC or ammonia, you should also exercise your 
judgement in assessing the degree of visibility impacts due to emissions 
of VOC and emissions of ammonia or ammonia compounds. You should fully 
document the basis for judging that a VOC or ammonia source merits BART 
review, including your assessment of the source's contribution to 
visibility impairment.
---------------------------------------------------------------------------

    \1\ Fine particles: Overview of Atmospheric Chemistry, Sources of 
Emissions, and Ambient Monitoring Data, Memorandum to Docket OAR 2002-
006, April 1, 2005.
---------------------------------------------------------------------------

            What does the term ``potential'' emissions mean?

    The regional haze rule defines potential to emit as follows:

    ``Potential to emit'' means the maximum capacity of a stationary 
source to emit a pollutant under its physical and operational design. 
Any physical or operational limitation on the capacity of the source to 
emit a pollutant including air pollution control equipment and 
restrictions on hours of operation or on the type or amount of material 
combusted, stored, or processed, shall be treated as part of its design 
if the limitation or the effect it would have on emissions is federally 
enforceable. Secondary emissions do not count in determining the 
potential to emit of a stationary source.

The definition of ``potential to emit'' means that a source which 
actually emits less than 250 tons per year of a visibility-impairing 
pollutant is BART-eligible if its emissions would exceed 250 tons per 
year when operating at its maximum capacity given its physical and 
operational design (and considering all federally enforceable and State 
enforceable permit limits.)

    Example: A source, while operating at one-fourth of its capacity, 
emits 75 tons per year of SO2. If it were operating at 100 
percent of its maximum capacity, the source would emit 300 tons per 
year. Because under the above definition such a source would have 
``potential'' emissions that exceed 250 tons per year, the source (if in 
a listed category and built during the 1962-1977 time window) would be 
BART-eligible.

    How do I identify whether a plant has more than one ``stationary 
                                source?''

    1. The regional haze rule, in 40 CFR 51.301, defines a stationary 
source as a ``building, structure, facility or installation which emits 
or may emit any air pollutant.'' \2\ The

[[Page 558]]

rule further defines ``building, structure or facility'' as:
---------------------------------------------------------------------------

    \2\ Note: Most of these terms and definitions are the same for 
regional haze and the 1980 visibility regulations. For the regional haze 
rule we use the term ``BART-eligible source'' rather than ``existing 
stationary facility'' to clarify that only a limited subset of existing 
stationary sources are subject to BART.

all of the pollutant-emitting activities which belong to the same 
industrial grouping, are located on one or more contiguous or adjacent 
properties, and are under the control of the same person (or persons 
under common control). Pollutant-emitting activities must be considered 
as part of the same industrial grouping if they belong to the same Major 
Group (i.e., which have the same two-digit code) as described in the 
Standard Industrial Classification Manual, 1972 as amended by the 1977 
Supplement (U.S. Government Printing Office stock numbers 4101-0066 and 
003-005-00176-0, respectively).

    2. In applying this definition, it is necessary to determine which 
facilities are located on ``contiguous or adjacent properties.'' Within 
this contiguous and adjacent area, it is also necessary to group those 
emission units that are under ``common control.'' We note that these 
plant boundary issues and ``common control'' issues are very similar to 
those already addressed in implementation of the title V operating 
permits program and in NSR.
    3. For emission units within the ``contiguous or adjacent'' boundary 
and under common control, you must group emission units that are within 
the same industrial grouping (that is, associated with the same 2-digit 
SIC code) in order to define the stationary source.\3\ For most plants 
on the BART source category list, there will only be one 2-digit SIC 
that applies to the entire plant. For example, all emission units 
associated with kraft pulp mills are within SIC code 26, and chemical 
process plants will generally include emission units that are all within 
SIC code 28. The ``2-digit SIC test'' applies in the same way as the 
test is applied in the major source NSR programs.\4\
---------------------------------------------------------------------------

    \3\ We recognize that we are in a transition period from the use of 
the SIC system to a new system called the North American Industry 
Classification System (NAICS). For purposes of identifying BART-eligible 
sources, you may use either 2-digit SICS or the equivalent in the NAICS 
system.
    \4\ Note: The concept of support facility used for the NSR program 
applies here as well. Support facilities, that is facilities that 
convey, store or otherwise assist in the production of the principal 
product, must be grouped with primary facilities even when the 
facilities fall wihin separate SIC codes. For purposes of BART reviews, 
however, such support facilities (a) must be within one of the 26 listed 
source categories and (b) must have been in existence as of August 7, 
1977, and (c) must not have been in operation as of August 7, 1962.
---------------------------------------------------------------------------

    4. For purposes of the regional haze rule, you must group emissions 
from all emission units put in place within the 1962-1977 time period 
that are within the 2-digit SIC code, even if those emission units are 
in different categories on the BART category list.

    Examples: A chemical plant which started operations within the 1962 
to 1977 time period manufactures hydrochloric acid (within the category 
title ``Hydrochloric, sulfuric, and nitric acid plants'') and various 
organic chemicals (within the category title ``chemical process 
plants''). All of the emission units are within SIC code 28 and, 
therefore, all the emission units are considered in determining BART 
eligibility of the plant. You sum the emissions over all of these 
emission units to see whether there are more than 250 tons per year of 
potential emissions.
    A steel mill which started operations within the 1962 to 1977 time 
period includes a sintering plant, a coke oven battery, and various 
other emission units. All of the emission units are within SIC code 33. 
You sum the emissions over all of these emission units to see whether 
there are more than 250 tons per year of potential emissions.

    4. Final Step: Identify the Emissions Units and Pollutants That 
                   Constitute the BART-Eligible Source

    If the emissions from the list of emissions units at a stationary 
source exceed a potential to emit of 250 tons per year for any 
visibility-impairing pollutant, then that collection of emissions units 
is a BART-eligible source.

    Example: A stationary source comprises the following two emissions 
units, with the following potential emissions:
Emissions unit A
200 tons/yr SO2
150 tons/yr NOX
25 tons/yr PM
Emissions unit B
100 tons/yr SO2
75 tons/yr NOX
10 tons/yr PM

For this example, potential emissions of SO2 are 300 tons/yr, 
which exceeds the 250 tons/yr threshold. Accordingly, the entire 
``stationary source'', that is, emissions units A and B, may be subject 
to a BART review for SO2, NOX, and PM, even though 
the potential emissions of PM and NOX at each emissions unit 
are less than 250 tons/yr each.
    Example: The total potential emissions, obtained by adding the 
potential emissions of all emission units in a listed category at a 
plant site, are as follows:

200 tons/yr SO2
150 tons/yr NOX
25 tons/yr PM


[[Page 559]]


    Even though total emissions exceed 250 tons/yr, no individual 
regulated pollutant exceeds 250 tons/yr and this source is not BART-
eligible.

 Can States establish de minimis levels of emissions for pollutants at 
                         BART-eligible sources?

    In order to simplify BART determinations, States may choose to 
identify de minimis levels of pollutants at BART-eligible sources (but 
are not required to do so). De minimis values should be identified with 
the purpose of excluding only those emissions so minimal that they are 
unlikely to contribute to regional haze. Any de minimis values that you 
adopt must not be higher than the PSD applicability levels: 40 tons/yr 
for SO2 and NOX and 15 tons/yr for 
PM10. These de minimis levels may only be applied on a plant-
wide basis.

            III. How To Identify Sources ``Subject to BART''

    Once you have compiled your list of BART-eligible sources, you need 
to determine whether (1) to make BART determinations for all of them or 
(2) to consider exempting some of them from BART because they may not 
reasonably be anticipated to cause or contribute to any visibility 
impairment in a Class I area. If you decide to make BART determinations 
for all the BART-eligible sources on your list, you should work with 
your regional planning organization (RPO) to show that, collectively, 
they cause or contribute to visibility impairment in at least one Class 
I area. You should then make individual BART determinations by applying 
the five statutory factors discussed in Section IV below.
    On the other hand, you also may choose to perform an initial 
examination to determine whether a particular BART-eligible source or 
group of sources causes or contributes to visibility impairment in 
nearby Class I areas. If your analysis, or information submitted by the 
source, shows that an individual source or group of sources (or certain 
pollutants from those sources) is not reasonably anticipated to cause or 
contribute to any visibility impairment in a Class I area, then you do 
not need to make BART determinations for that source or group of sources 
(or for certain pollutants from those sources). In such a case, the 
source is not ``subject to BART'' and you do not need to apply the five 
statutory factors to make a BART determination. This section of the 
Guideline discusses several approaches that you can use to exempt 
sources from the BART determination process.

  A. What Steps Do I Follow To Determine Whether a Source or Group of 
  Sources Cause or Contribute to Visibility Impairment for Purposes of 
                                  BART?

                   1. How Do I Establish a Threshold?

    One of the first steps in determining whether sources cause or 
contribute to visibility impairment for purposes of BART is to establish 
a threshold (measured in deciviews) against which to measure the 
visibility impact of one or more sources. A single source that is 
responsible for a 1.0 deciview change or more should be considered to 
``cause'' visibility impairment; a source that causes less than a 1.0 
deciview change may still contribute to visibility impairment and thus 
be subject to BART.
    Because of varying circumstances affecting different Class I areas, 
the appropriate threshold for determining whether a source ``contributes 
to any visibility impairment'' for the purposes of BART may reasonably 
differ across States. As a general matter, any threshold that you use 
for determining whether a source ``contributes'' to visibility 
impairment should not be higher than 0.5 deciviews.
    In setting a threshold for ``contribution,'' you should consider the 
number of emissions sources affecting the Class I areas at issue and the 
magnitude of the individual sources' impacts.\5\ In general, a larger 
number of sources causing impacts in a Class I area may warrant a lower 
contribution threshold. States remain free to use a threshold lower than 
0.5 deciviews if they conclude that the location of a large number of 
BART-eligible sources within the State and in proximity to a Class I 
area justify this approach.\6\
---------------------------------------------------------------------------

    \5\ We expect that regional planning organizations will have 
modeling information that identifies sources affecting visibility in 
individual class I areas.
    \6\ Note that the contribution threshold should be used to determine 
whether an individual source is reasonably anticipated to contribute to 
visibility impairment. You should not aggregate the visibility effects 
of multiple sources and compare their collective effects against your 
contribution threshold because this would inappropriately create a 
``contribute to contribution'' test.
---------------------------------------------------------------------------

                2. What Pollutants Do I Need To Consider?

    You must look at SO2, NOX, and direct 
particulate matter (PM) emissions in determining whether sources cause 
or contribute to visibility impairment, including both PM10 
and PM2.5. Consistent with the approach for identifying your 
BART-eligible sources, you do not need to consider less than de minimis 
emissions of these pollutants from a source.

[[Page 560]]

    As explained in section II, you must use your best judgement to 
determine whether VOC or ammonia emissions are likely to have an impact 
on visibility in an area. In addition, although as explained in Section 
II, you may use PM10 an indicator for particulate matter in 
determining whether a source is BART-eligible, in determining whether a 
source contributes to visibility impairment, you should distinguish 
between the fine and coarse particle components of direct particulate 
emissions. Although both fine and coarse particulate matter contribute 
to visibility impairment, the long-range transport of fine particles is 
of particular concern in the formation of regional haze. Air quality 
modeling results used in the BART determination will provide a more 
accurate prediction of a source's impact on visibility if the inputs 
into the model account for the relative particle size of any directly 
emitted particulate matter (i.e. PM10 vs. PM2.5).

  3. What Kind of Modeling Should I Use To Determine Which Sources and 
                 Pollutants Need Not Be Subject to BART?

    This section presents several options for determining that certain 
sources need not be subject to BART. These options rely on different 
modeling and/or emissions analysis approaches. They are provided for 
your guidance. You may also use other reasonable approaches for 
analyzing the visibility impacts of an individual source or group of 
sources.

 Option 1: Individual Source Attribution Approach (Dispersion Modeling)

    You can use dispersion modeling to determine that an individual 
source cannot reasonably be anticipated to cause or contribute to 
visibility impairment in a Class I area and thus is not subject to BART. 
Under this option, you can analyze an individual source's impact on 
visibility as a result of its emissions of SO2, 
NOX and direct PM emissions. Dispersion modeling cannot 
currently be used to estimate the predicted impacts on visibility from 
an individual source's emissions of VOC or ammonia. You may use a more 
qualitative assessment to determine on a case-by-case basis which 
sources of VOC or ammonia emissions may be likely to impair visibility 
and should therefore be subject to BART review, as explained in section 
II.A.3. above.
    You can use CALPUFF \7\ or other appropriate model to predict the 
visibility impacts from a single source at a Class I area. CALPUFF is 
the best regulatory modeling application currently available for 
predicting a single source's contribution to visibility impairment and 
is currently the only EPA-approved model for use in estimating single 
source pollutant concentrations resulting from the long range transport 
of primary pollutants.\8\ It can also be used for some other purposes, 
such as the visibility assessments addressed in today's rule, to account 
for the chemical transformation of SO2 and NOX.
---------------------------------------------------------------------------

    \7\ The model code and its documentation are available at no cost 
for download from http://www.epa.gov/scram001/tt22.htm#calpuff.
    \8\ The Guideline on Air Quality Models, 40 CFR part 51, appendix W, 
addresses the regulatory application of air quality models for assessing 
criteria pollutants under the CAA, and describes further the procedures 
for using the CALPUFF model, as well as for obtaining approval for the 
use of other, nonguideline models.
---------------------------------------------------------------------------

    There are several steps for making an individual source attribution 
using a dispersion model:
    1. Develop a modeling protocol. Some critical items to include in 
the protocol are the meteorological and terrain data that will be used, 
as well as the source-specific information (stack height, temperature, 
exit velocity, elevation, and emission rates of applicable pollutants) 
and receptor data from appropriate Class I areas. We recommend following 
EPA's Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 
Summary Report and Recommendations for Modeling Long Range Transport 
Impacts \9\ for parameter settings and meteorological data inputs. You 
may use other settings from those in IWAQM, but you should identify 
these settings and explain your selection of these settings.
---------------------------------------------------------------------------

    \9\ Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 
Summary Report and Recommendations for Modeling Long Range Transport 
Impacts, U.S. Environmental Protection Agency, EPA-454/R-98-019, 
December 1998.
---------------------------------------------------------------------------

    One important element of the protocol is in establishing the 
receptors that will be used in the model. The receptors that you use 
should be located in the nearest Class I area with sufficient density to 
identify the likely visibility effects of the source. For other Class I 
areas in relatively close proximity to a BART-eligible source, you may 
model a few strategic receptors to determine whether effects at those 
areas may be greater than at the nearest Class I area. For example, you 
might chose to locate receptors at these areas at the closest point to 
the source, at the highest and lowest elevation in the Class I area, at 
the IMPROVE monitor, and at the approximate expected plume release 
height. If the highest modeled effects are observed at the nearest Class 
I area, you may choose not to analyze the other Class I areas any 
further as additional analyses might be unwarranted.
    You should bear in mind that some receptors within the relevant 
Class I area may be

[[Page 561]]

less than 50 km from the source while other receptors within that same 
Class I area may be greater than 50 km from the same source. As 
indicated by the Guideline on Air Quality Models, 40 CFR part 51, 
appendix W, this situation may call for the use of two different 
modeling approaches for the same Class I area and source, depending upon 
the State's chosen method for modeling sources less than 50 km. In 
situations where you are assessing visibility impacts for source-
receptor distances less than 50 km, you should use expert modeling 
judgment in determining visibility impacts, giving consideration to both 
CALPUFF and other appropriate methods.
    In developing your modeling protocol, you may want to consult with 
EPA and your regional planning organization (RPO). Up-front consultation 
will ensure that key technical issues are addressed before you conduct 
your modeling.
    2. With the accepted protocol and compare the predicted visibility 
impacts with your threshold for ``contribution.'' You should calculate 
daily visibility values for each receptor as the change in deciviews 
compared against natural visibility conditions. You can use EPA's 
``Guidance for Estimating Natural Visibility Conditions Under the 
Regional Haze Rule,'' EPA-454/B-03-005 (September 2003) in making this 
calculation. To determine whether a source may reasonably be anticipated 
to cause or contribute to visibility impairment at Class I area, you 
then compare the impacts predicted by the model against the threshold 
that you have selected.
    The emissions estimates used in the models are intended to reflect 
steady-state operating conditions during periods of high capacity 
utilization. We do not generally recommend that emissions reflecting 
periods of start-up, shutdown, and malfunction be used, as such emission 
rates could produce higher than normal effects than would be typical of 
most facilities. We recommend that States use the 24 hour average actual 
emission rate from the highest emitting day of the meteorological period 
modeled, unless this rate reflects periods start-up, shutdown, or 
malfunction. In addition, the monthly average relative humidity is used, 
rather than the daily average humidity--an approach that effectively 
lowers the peak values in daily model averages.
    For these reasons, if you use the modeling approach we recommend, 
you should compare your ``contribution'' threshold against the 98th 
percentile of values. If the 98th percentile value from your modeling is 
less than your contribution threshold, then you may conclude that the 
source does not contribute to visibility impairment and is not subject 
to BART.

 Option 2: Use of Model Plants To Exempt Individual Sources With Common 
                             Characteristics

    Under this option, analyses of model plants could be used to exempt 
certain BART-eligible sources that share specific characteristics. It 
may be most useful to use this type of analysis to identify the types of 
small sources that do not cause or contribute to visibility impairment 
for purposes of BART, and thus should not be subject to a BART review. 
Different Class I areas may have different characteristics, however, so 
you should use care to ensure that the criteria you develop are 
appropriate for the applicable cases.
    In carrying out this approach, you could use modeling analyses of 
representative plants to reflect groupings of specific sources with 
important common characteristics. Based on these analyses, you may find 
that certain types of sources are clearly anticipated to cause or 
contribute to visibility impairment. You could then choose to 
categorically require those types of sources to undergo a BART 
determination. Conversely, you may find based on representative plant 
analyses that certain types of sources are not reasonably anticipated to 
cause or contribute to visibility impairment. To do this, you may 
conduct your own modeling to establish emission levels and distances 
from Class I areas on which you can rely to exempt sources with those 
characteristics. For example, based on your modeling you might choose to 
exempt all NOX-only sources that emit less than a certain 
amount per year and are located a certain distance from a Class I area. 
You could then choose to categorically exempt such sources from the BART 
determination process.
    Our analyses of visibility impacts from model plants provide a 
useful example of the type of analyses that can be used to exempt 
categories of sources from BART. \10\ In our analyses, we developed 
model plants (EGUs and non-EGUs), with representative plume and stack 
characteristics, for use in considering the visibility impact from 
emission sources of different sizes and compositions at distances of 50, 
100 and 200 kilometers from two hypothetical Class I areas (one in the 
East and one in the West). As the plume and stack characteristics of 
these model plants were developed considering the broad range of sources 
within the EGU and non-EGU categories, they do not necessarily represent 
any specific plant. However, the results of these analyses are 
instructive in the development of an exemption process for any Class I 
area.
---------------------------------------------------------------------------

    \10\ CALPUFF Analysis in Support of the June 2005 Changes to the 
Regional Haze Rule, U.S. Environmental Protection Agency, June 15, 2005, 
Docket No. OAR-2002-0076.

---------------------------------------------------------------------------

[[Page 562]]

    In preparing our analyses, we have made a number of assumptions and 
exercised certain modeling choices; some of these have a tendency to 
lend conservatism to the results, overstating the likely effects, while 
others may understate the likely effects. On balance, when all of these 
factors are considered, we believe that our examples reflect realistic 
treatments of the situations being modeled. Based on our analyses, we 
believe that a State that has established 0.5 deciviews as a 
contribution threshold could reasonably exempt from the BART review 
process sources that emit less than 500 tons per year of NOX 
or SO2 (or combined NOX and SO2), as 
long as these sources are located more than 50 kilometers from any Class 
I area; and sources that emit less than 1000 tons per year of 
NOX or SO2 (or combined NOX and 
SO2) that are located more than 100 kilometers from any Class 
I area. You do, however, have the option of showing other thresholds 
might also be appropriate given your specific circumstances.

  Option 3: Cumulative Modeling To Show That No Sources in a State Are 
                             Subject to BART

    You may also submit to EPA a demonstration based on an analysis of 
overall visibility impacts that emissions from BART-eligible sources in 
your State, considered together, are not reasonably anticipated to cause 
or contribute to any visibility impairment in a Class I area, and thus 
no source should be subject to BART. You may do this on a pollutant by 
pollutant basis or for all visibility-impairing pollutants to determine 
if emissions from these sources contribute to visibility impairment.
    For example, emissions of SO2 from your BART-eligible 
sources may clearly cause or contribute to visibility impairment while 
direct emissions of PM2.5 from these sources may not 
contribute to impairment. If you can make such a demonstration, then you 
may reasonably conclude that none of your BART-eligible sources are 
subject to BART for a particular pollutant or pollutants. As noted 
above, your demonstration should take into account the interactions 
among pollutants and their resulting impacts on visibility before making 
any pollutant-specific determinations.
    Analyses may be conducted using several alternative modeling 
approaches. First, you may use the CALPUFF or other appropriate model as 
described in Option 1 to evaluate the impacts of individual sources on 
downwind Class I areas, aggregating those impacts to determine the 
collective contribution of all BART-eligible sources to visibility 
impairment. You may also use a photochemical grid model. As a general 
matter, the larger the number of sources being modeled, the more 
appropriate it may be to use a photochemical grid model. However, 
because such models are significantly less sensitive than dispersion 
models to the contributions of one or a few sources, as well as to the 
interactions among sources that are widely distributed geographically, 
if you wish to use a grid model, you should consult with the appropriate 
EPA Regional Office to develop an appropriate modeling protocol.

          IV. The BART Determination: Analysis of BART Options

    This section describes the process for the analysis of control 
options for sources subject to BART.

           A. What factors must I address in the BART review?

    The visibility regulations define BART as follows:
    Best Available Retrofit Technology (BART) means an emission 
limitation based on the degree of reduction achievable through the 
application of the best system of continuous emission reduction for each 
pollutant which is emitted by . . . [a BART-eligible source]. The 
emission limitation must be established, on a case-by-case basis, taking 
into consideration the technology available, the costs of compliance, 
the energy and non-air quality environmental impacts of compliance, any 
pollution control equipment in use or in existence at the source, the 
remaining useful life of the source, and the degree of improvement in 
visibility which may reasonably be anticipated to result from the use of 
such technology.
    The BART analysis identifies the best system of continuous emission 
reduction taking into account:
    (1) The available retrofit control options,
    (2) Any pollution control equipment in use at the source (which 
affects the availability of options and their impacts),
    (3) The costs of compliance with control options,
    (4) The remaining useful life of the facility,
    (5) The energy and non-air quality environmental impacts of control 
options
    (6) The visibility impacts analysis.

                B. What is the scope of the BART review?

    Once you determine that a source is subject to BART for a particular 
pollutant, then for each affected emission unit, you must establish BART 
for that pollutant. The BART determination must address air pollution 
control measures for each emissions unit or pollutant emitting activity 
subject to review.

    Example: Plantwide emissions from emission units within the listed 
categories that began operation within the ``time window''

[[Page 563]]

for BART \11\ are 300 tons/yr of NOX, 200 tons/yr of 
SO2, and 150 tons/yr of primary particulate. Emissions unit A 
emits 200 tons/yr of NOX, 100 tons/yr of SO2, and 
100 tons/yr of primary particulate. Other emission units, units B 
through H, which began operating in 1966, contribute lesser amounts of 
each pollutant. For this example, a BART review is required for 
NOX, SO2, and primary particulate, and control 
options must be analyzed for units B through H as well as unit A.
---------------------------------------------------------------------------

    \11\ That is, emission units that were in existence on August 7, 
1977 and which began actual operation on or after August 7, 1962.
---------------------------------------------------------------------------

     C. How does a BART review relate to Maximum Achievable Control 
Technology (MACT) Standards under CAA section 112, or to other emission 
                   limitations required under the CAA?

    For VOC and PM sources subject to MACT standards, States may 
streamline the analysis by including a discussion of the MACT controls 
and whether any major new technologies have been developed subsequent to 
the MACT standards. We believe that there are many VOC and PM sources 
that are well controlled because they are regulated by the MACT 
standards, which EPA developed under CAA section 112. For a few MACT 
standards, this may also be true for SO2. Any source subject 
to MACT standards must meet a level that is as stringent as the best-
controlled 12 percent of sources in the industry. Examples of these 
hazardous air pollutant sources which effectively control VOC and PM 
emissions include (among others) secondary lead facilities, organic 
chemical plants subject to the hazardous organic NESHAP (HON), 
pharmaceutical production facilities, and equipment leaks and wastewater 
operations at petroleum refineries. We believe that, in many cases, it 
will be unlikely that States will identify emission controls more 
stringent than the MACT standards without identifying control options 
that would cost many thousands of dollars per ton. Unless there are new 
technologies subsequent to the MACT standards which would lead to cost-
effective increases in the level of control, you may rely on the MACT 
standards for purposes of BART.
    We believe that the same rationale also holds true for emissions 
standards developed for municipal waste incinerators under CAA section 
111(d), and for many NSR/PSD determinations and NSR/PSD settlement 
agreements. However, we do not believe that technology determinations 
from the 1970s or early 1980s, including new source performance 
standards (NSPS), should be considered to represent best control for 
existing sources, as best control levels for recent plant retrofits are 
more stringent than these older levels.
    Where you are relying on these standards to represent a BART level 
of control, you should provide the public with a discussion of whether 
any new technologies have subsequently become available.

    D. What Are the Five Basic Steps of a Case-by-Case BART Analysis?

    The five steps are:
    STEP 1--Identify All \12\ Available Retrofit Control Technologies,
---------------------------------------------------------------------------

    \12\ In identifying ``all'' options, you must identify the most 
stringent option and a reasonable set of options for analysis that 
reflects a comprehensive list of available technologies. It is not 
necessary to list all permutations of available control levels that 
exist for a given technology--the list is complete if it includes the 
maximum level of control each technology is capable of achieving.
---------------------------------------------------------------------------

    STEP 2--Eliminate Technically Infeasible Options,
    STEP 3--Evaluate Control Effectiveness of Remaining Control 
Technologies,
    STEP 4--Evaluate Impacts and Document the Results, and
    STEP 5--Evaluate Visibility Impacts.

  1. STEP 1: How do I identify all available retrofit emission control 
                               techniques?

    1. Available retrofit control options are those air pollution 
control technologies with a practical potential for application to the 
emissions unit and the regulated pollutant under evaluation. Air 
pollution control technologies can include a wide variety of available 
methods, systems, and techniques for control of the affected pollutant. 
Technologies required as BACT or LAER are available for BART purposes 
and must be included as control alternatives. The control alternatives 
can include not only existing controls for the source category in 
question but also take into account technology transfer of controls that 
have been applied to similar source categories and gas streams. 
Technologies which have not yet been applied to (or permitted for) full 
scale operations need not be considered as available; we do not expect 
the source owner to purchase or construct a process or control device 
that has not already been demonstrated in practice.
    2. Where a NSPS exists for a source category (which is the case for 
most of the categories affected by BART), you should include a level of 
control equivalent to the NSPS as one of the control options.\13\ The

[[Page 564]]

NSPS standards are codified in 40 CFR part 60. We note that there are 
situations where NSPS standards do not require the most stringent level 
of available control for all sources within a category. For example, 
post-combustion NOX controls (the most stringent controls for 
stationary gas turbines) are not required under subpart GG of the NSPS 
for Stationary Gas Turbines. However, such controls must still be 
considered available technologies for the BART selection process.
---------------------------------------------------------------------------

    \13\ In EPA's 1980 BART guidelines for reasonably attributable 
visibility impairment, we concluded that NSPS standards generally, at 
that time, represented the best level sources could install as BART. In 
the 20 year period since this guidance was developed, there have been 
advances in SO2 control technologies as well as technologies 
for the control of other pollutants, confirmed by a number of recent 
retrofits at Western power plants. Accordingly, EPA no longer concludes 
that the NSPS level of controls automatically represents ``the best 
these sources can install.'' Analysis of the BART factors could result 
in the selection of a NSPS level of control, but you should reach this 
conclusion only after considering the full range of control options.
---------------------------------------------------------------------------

    3. Potentially applicable retrofit control alternatives can be 
categorized in three ways.
     Pollution prevention: use of inherently lower-
emitting processes/practices, including the use of control techniques 
(e.g. low-NOX burners) and work practices that prevent 
emissions and result in lower ``production-specific'' emissions (note 
that it is not our intent to direct States to switch fuel forms, e.g. 
from coal to gas),
     Use of (and where already in place, improvement 
in the performance of) add-on controls, such as scrubbers, fabric 
filters, thermal oxidizers and other devices that control and reduce 
emissions after they are produced, and
     Combinations of inherently lower-emitting 
processes and add-on controls.
    4. In the course of the BART review, one or more of the available 
control options may be eliminated from consideration because they are 
demonstrated to be technically infeasible or to have unacceptable 
energy, cost, or non-air quality environmental impacts on a case-by-case 
(or site-specific) basis. However, at the outset, you should initially 
identify all control options with potential application to the emissions 
unit under review.
    5. We do not consider BART as a requirement to redesign the source 
when considering available control alternatives. For example, where the 
source subject to BART is a coal-fired electric generator, we do not 
require the BART analysis to consider building a natural gas-fired 
electric turbine although the turbine may be inherently less polluting 
on a per unit basis.
    6. For emission units subject to a BART review, there will often be 
control measures or devices already in place. For such emission units, 
it is important to include control options that involve improvements to 
existing controls and not to limit the control options only to those 
measures that involve a complete replacement of control devices.

    Example: For a power plant with an existing wet scrubber, the 
current control efficiency is 66 percent. Part of the reason for the 
relatively low control efficiency is that 22 percent of the gas stream 
bypasses the scrubber. A BART review identifies options for improving 
the performance of the wet scrubber by redesigning the internal 
components of the scrubber and by eliminating or reducing the percentage 
of the gas stream that bypasses the scrubber. Four control options are 
identified: (1) 78 percent control based upon improved scrubber 
performance while maintaining the 22 percent bypass, (2) 83 percent 
control based upon improved scrubber performance while reducing the 
bypass to 15 percent, (3) 93 percent control based upon improving the 
scrubber performance while eliminating the bypass entirely, (this option 
results in a ``wet stack'' operation in which the gas leaving the stack 
is saturated with water) and (4) 93 percent as in option 3, with the 
addition of an indirect reheat system to reheat the stack gas above the 
saturation temperature. You must consider each of these four options in 
a BART analysis for this source.

    7. You are expected to identify potentially applicable retrofit 
control technologies that represent the full range of demonstrated 
alternatives. Examples of general information sources to consider 
include:
     The EPA's Clean Air Technology Center, which 
includes the RACT/BACT/LAER Clearinghouse (RBLC);
     State and Local Best Available Control Technology 
Guidelines--many agencies have online information--for example South 
Coast Air Quality Management District, Bay Area Air Quality Management 
District, and Texas Natural Resources Conservation Commission;
     Control technology vendors;
     Federal/State/Local NSR permits and associated 
inspection/performance test reports;
     Environmental consultants;
     Technical journals, reports and newsletters, air 
pollution control seminars; and
     The EPA's NSR bulletin board--http://www.epa.gov/
ttn/nsr;
     Department of Energy's Clean Coal Program--
technical reports;
     The NOX Control Technology ``Cost 
Tool''--Clean Air Markets Division Web page--http://www.epa.gov/
airmarkets/arp/nox/controltech.html;
     Performance of selective catalytic reduction on 
coal-fired steam generating units--

[[Page 565]]

final report. OAR/ARD, June 1997 (also available at http://www.epa.gov/
airmarkets/arp/nox/controltech.html);
     Cost estimates for selected applications of 
NOX control technologies on stationary combustion boilers. 
OAR/ARD June 1997. (Docket for NOX SIP Call, A-96-56, item 
II-A-03);
     Investigation of performance and cost of 
NOX controls as applied to group 2 boilers. OAR/ARD, August 
1996. (Docket for Phase II NOX rule, A-95-28, item IV-A-4);
     Controlling SO2 Emissions: A Review of 
Technologies. EPA-600/R-00-093, USEPA/ORD/NRMRL, October 2000; and
     The OAQPS Control Cost Manual.
    You are expected to compile appropriate information from these 
information sources.
    8. There may be situations where a specific set of units within a 
fenceline constitutes the logical set to which controls would apply and 
that set of units may or may not all be BART-eligible. (For example, 
some units in that set may not have been constructed between 1962 and 
1977.)
    9. If you find that a BART source has controls already in place 
which are the most stringent controls available (note that this means 
that all possible improvements to any control devices have been made), 
then it is not necessary to comprehensively complete each following step 
of the BART analysis in this section. As long these most stringent 
controls available are made federally enforceable for the purpose of 
implementing BART for that source, you may skip the remaining analyses 
in this section, including the visibility analysis in step 5. Likewise, 
if a source commits to a BART determination that consists of the most 
stringent controls available, then there is no need to complete the 
remaining analyses in this section.

 2. STEP 2: How do I determine whether the options identified in Step 1 
                        are technically feasible?

    In Step 2, you evaluate the technical feasibility of the control 
options you identified in Step 1. You should document a demonstration of 
technical infeasibility and should explain, based on physical, chemical, 
or engineering principles, why technical difficulties would preclude the 
successful use of the control option on the emissions unit under review. 
You may then eliminate such technically infeasible control options from 
further consideration in the BART analysis.

          In general, what do we mean by technical feasibility?

    Control technologies are technically feasible if either (1) they 
have been installed and operated successfully for the type of source 
under review under similar conditions, or (2) the technology could be 
applied to the source under review. Two key concepts are important in 
determining whether a technology could be applied: ``availability'' and 
``applicability.'' As explained in more detail below, a technology is 
considered ``available'' if the source owner may obtain it through 
commercial channels, or it is otherwise available within the common 
sense meaning of the term. An available technology is ``applicable'' if 
it can reasonably be installed and operated on the source type under 
consideration. A technology that is available and applicable is 
technically feasible.

              What do we mean by ``available'' technology?

    1. The typical stages for bringing a control technology concept to 
reality as a commercial product are:
     Concept stage;
     Research and patenting;
     Bench scale or laboratory testing;
     Pilot scale testing;
     Licensing and commercial demonstration; and
     Commercial sales.
    2. A control technique is considered available, within the context 
presented above, if it has reached the stage of licensing and commercial 
availability. Similarly, we do not expect a source owner to conduct 
extended trials to learn how to apply a technology on a totally new and 
dissimilar source type. Consequently, you would not consider 
technologies in the pilot scale testing stages of development as 
``available'' for purposes of BART review.
    3. Commercial availability by itself, however, is not necessarily a 
sufficient basis for concluding a technology to be applicable and 
therefore technically feasible. Technical feasibility, as determined in 
Step 2, also means a control option may reasonably be deployed on or 
``applicable'' to the source type under consideration.
    Because a new technology may become available at various points in 
time during the BART analysis process, we believe that guidelines are 
needed on when a technology must be considered. For example, a 
technology may become available during the public comment period on the 
State's rule development process. Likewise, it is possible that new 
technologies may become available after the close of the State's public 
comment period and before submittal of the SIP to EPA, or during EPA's 
review process on the SIP submittal. In order to provide certainty in 
the process, all technologies should be considered if available before 
the close of the State's public comment period. You need not consider 
technologies that become available after this date. As part of your 
analysis, you should consider any technologies brought to your attention 
in public comments. If you disagree with public comments asserting that 
the technology is available, you should

[[Page 566]]

provide an explanation for the public record as to the basis for your 
conclusion.

              What do we mean by ``applicable'' technology?

    You need to exercise technical judgment in determining whether a 
control alternative is applicable to the source type under 
consideration. In general, a commercially available control option will 
be presumed applicable if it has been used on the same or a similar 
source type. Absent a showing of this type, you evaluate technical 
feasibility by examining the physical and chemical characteristics of 
the pollutant-bearing gas stream, and comparing them to the gas stream 
characteristics of the source types to which the technology had been 
applied previously. Deployment of the control technology on a new or 
existing source with similar gas stream characteristics is generally a 
sufficient basis for concluding the technology is technically feasible 
barring a demonstration to the contrary as described below.

 What type of demonstration is required if I conclude that an option is 
                        not technically feasible?

    1. Where you conclude that a control option identified in Step 1 is 
technically infeasible, you should demonstrate that the option is either 
commercially unavailable, or that specific circumstances preclude its 
application to a particular emission unit. Generally, such a 
demonstration involves an evaluation of the characteristics of the 
pollutant-bearing gas stream and the capabilities of the technology. 
Alternatively, a demonstration of technical infeasibility may involve a 
showing that there are unresolvable technical difficulties with applying 
the control to the source (e.g., size of the unit, location of the 
proposed site, operating problems related to specific circumstances of 
the source, space constraints, reliability, and adverse side effects on 
the rest of the facility). Where the resolution of technical 
difficulties is merely a matter of increased cost, you should consider 
the technology to be technically feasible. The cost of a control 
alternative is considered later in the process.
    2. The determination of technical feasibility is sometimes 
influenced by recent air quality permits. In some cases, an air quality 
permit may require a certain level of control, but the level of control 
in a permit is not expected to be achieved in practice (e.g., a source 
has received a permit but the project was canceled, or every operating 
source at that permitted level has been physically unable to achieve 
compliance with the limit). Where this is the case, you should provide 
supporting documentation showing why such limits are not technically 
feasible, and, therefore, why the level of control (but not necessarily 
the technology) may be eliminated from further consideration. However, 
if there is a permit requiring the application of a certain technology 
or emission limit to be achieved for such technology, this usually is 
sufficient justification for you to assume the technical feasibility of 
that technology or emission limit.
    3. Physical modifications needed to resolve technical obstacles do 
not, in and of themselves, provide a justification for eliminating the 
control technique on the basis of technical infeasibility. However, you 
may consider the cost of such modifications in estimating costs. This, 
in turn, may form the basis for eliminating a control technology (see 
later discussion).
    4. Vendor guarantees may provide an indication of commercial 
availability and the technical feasibility of a control technique and 
could contribute to a determination of technical feasibility or 
technical infeasibility, depending on circumstances. However, we do not 
consider a vendor guarantee alone to be sufficient justification that a 
control option will work. Conversely, lack of a vendor guarantee by 
itself does not present sufficient justification that a control option 
or an emissions limit is technically infeasible. Generally, you should 
make decisions about technical feasibility based on chemical, and 
engineering analyses (as discussed above), in conjunction with 
information about vendor guarantees.
    5. A possible outcome of the BART procedures discussed in these 
guidelines is the evaluation of multiple control technology alternatives 
which result in essentially equivalent emissions. It is not our intent 
to encourage evaluation of unnecessarily large numbers of control 
alternatives for every emissions unit. Consequently, you should use 
judgment in deciding on those alternatives for which you will conduct 
the detailed impacts analysis (Step 4 below). For example, if two or 
more control techniques result in control levels that are essentially 
identical, considering the uncertainties of emissions factors and other 
parameters pertinent to estimating performance, you may evaluate only 
the less costly of these options. You should narrow the scope of the 
BART analysis in this way only if there is a negligible difference in 
emissions and energy and non-air quality environmental impacts between 
control alternatives.

     3. STEP 3: How do I evaluate technically feasible alternatives?

    Step 3 involves evaluating the control effectiveness of all the 
technically feasible control alternatives identified in Step 2 for the 
pollutant and emissions unit under review.
    Two key issues in this process include:
    (1) Making sure that you express the degree of control using a 
metric that ensures

[[Page 567]]

an ``apples to apples'' comparison of emissions performance levels among 
options, and
    (2) Giving appropriate treatment and consideration of control 
techniques that can operate over a wide range of emission performance 
levels.

            What are the appropriate metrics for comparison?

    This issue is especially important when you compare inherently 
lower-polluting processes to one another or to add-on controls. In such 
cases, it is generally most effective to express emissions performance 
as an average steady state emissions level per unit of product produced 
or processed.
    Examples of common metrics:
     Pounds of SO2 emissions per million 
Btu heat input, and
     Pounds of NOX emissions per ton of 
cement produced.

   How do I evaluate control techniques with a wide range of emission 
                           performance levels?

    1. Many control techniques, including both add-on controls and 
inherently lower polluting processes, can perform at a wide range of 
levels. Scrubbers and high and low efficiency electrostatic 
precipitators (ESPs) are two of the many examples of such control 
techniques that can perform at a wide range of levels. It is not our 
intent to require analysis of each possible level of efficiency for a 
control technique as such an analysis would result in a large number of 
options. It is important, however, that in analyzing the technology you 
take into account the most stringent emission control level that the 
technology is capable of achieving. You should consider recent 
regulatory decisions and performance data (e.g., manufacturer's data, 
engineering estimates and the experience of other sources) when 
identifying an emissions performance level or levels to evaluate.
    2. In assessing the capability of the control alternative, latitude 
exists to consider special circumstances pertinent to the specific 
source under review, or regarding the prior application of the control 
alternative. However, you should explain the basis for choosing the 
alternate level (or range) of control in the BART analysis. Without a 
showing of differences between the source and other sources that have 
achieved more stringent emissions limits, you should conclude that the 
level being achieved by those other sources is representative of the 
achievable level for the source being analyzed.
    3. You may encounter cases where you may wish to evaluate other 
levels of control in addition to the most stringent level for a given 
device. While you must consider the most stringent level as one of the 
control options, you may consider less stringent levels of control as 
additional options. This would be useful, particularly in cases where 
the selection of additional options would have widely varying costs and 
other impacts.
    4. Finally, we note that for retrofitting existing sources in 
addressing BART, you should consider ways to improve the performance of 
existing control devices, particularly when a control device is not 
achieving the level of control that other similar sources are achieving 
in practice with the same device. For example, you should consider 
requiring those sources with electrostatic precipitators (ESPs) 
performing below currently achievable levels to improve their 
performance.

 4. STEP 4: For a BART review, what impacts am I expected to calculate 
  and report? What methods does EPA recommend for the impacts analysis?

    After you identify the available and technically feasible control 
technology options, you are expected to conduct the following analyses 
when you make a BART determination:

    Impact analysis part 1: Costs of compliance,
    Impact analysis part 2: Energy impacts, and
    Impact analysis part 3: Non-air quality environmental impacts.
    Impact analysis part 4: Remaining useful life.

In this section, we describe how to conduct each of these three 
analyses. You are responsible for presenting an evaluation of each 
impact along with appropriate supporting information. You should discuss 
and, where possible, quantify both beneficial and adverse impacts. In 
general, the analysis should focus on the direct impact of the control 
alternative.

   a. Impact analysis part 1: how do I estimate the costs of control?

    1. To conduct a cost analysis, you:
    (1) Identify the emissions units being controlled,
    (2) Identify design parameters for emission controls, and
    (3) Develop cost estimates based upon those design parameters.
    2. It is important to identify clearly the emission units being 
controlled, that is, to specify a well-defined area or process segment 
within the plant. In some cases, multiple emission units can be 
controlled jointly. However, in other cases, it may be appropriate in 
the cost analysis to consider whether multiple units will be required to 
install separate and/or different control devices. The analysis should 
provide a clear summary list of equipment and the associated control 
costs. Inadequate documentation of the equipment whose emissions are 
being controlled is a potential cause for confusion in

[[Page 568]]

comparison of costs of the same controls applied to similar sources.
    3. You then specify the control system design parameters. Potential 
sources of these design parameters include equipment vendors, background 
information documents used to support NSPS development, control 
technique guidelines documents, cost manuals developed by EPA, control 
data in trade publications, and engineering and performance test data. 
The following are a few examples of design parameters for two example 
control measures:

------------------------------------------------------------------------
            Control device               Examples of design  parameters
------------------------------------------------------------------------
Wet Scrubbers.........................  Type of sorbent used (lime,
                                         limestone, etc.).
                                        Gas pressure drop.
                                        Liquid/gas ratio.
Selective Catalytic Reduction.........  Ammonia to NOX molar ratio.
                                        Pressure drop.
                                        Catalyst life.
------------------------------------------------------------------------

    4. The value selected for the design parameter should ensure that 
the control option will achieve the level of emission control being 
evaluated. You should include in your analysis documentation of your 
assumptions regarding design parameters. Examples of supporting 
references would include the EPA OAQPS Control Cost Manual (see below) 
and background information documents used for NSPS and hazardous 
pollutant emission standards. If the design parameters you specified 
differ from typical designs, you should document the difference by 
supplying performance test data for the control technology in question 
applied to the same source or a similar source.
    5. Once the control technology alternatives and achievable emissions 
performance levels have been identified, you then develop estimates of 
capital and annual costs. The basis for equipment cost estimates also 
should be documented, either with data supplied by an equipment vendor 
(i.e., budget estimates or bids) or by a referenced source (such as the 
OAQPS Control Cost Manual, Fifth Edition, February 1996, EPA 453/B-96-
001).\14\ In order to maintain and improve consistency, cost estimates 
should be based on the OAQPS Control Cost Manual, where possible.\15\ 
The Control Cost Manual addresses most control technologies in 
sufficient detail for a BART analysis. The cost analysis should also 
take into account any site-specific design or other conditions 
identified above that affect the cost of a particular BART technology 
option.
---------------------------------------------------------------------------

    \14\ The OAQPS Control Cost Manual is updated periodically. While 
this citation refers to the latest version at the time this guidance was 
written, you should use the version that is current as of when you 
conduct your impact analysis. This document is available at the 
following Web site: http://www.epa.gov/ttn/catc/dir1/cs1ch2.pdf.
    \15\ You should include documentation for any additional information 
you used for the cost calculations, including any information supplied 
by vendors that affects your assumptions regarding purchased equipment 
costs, equipment life, replacement of major components, and any other 
element of the calculation that differs from the Control Cost Manual.
---------------------------------------------------------------------------

                b. What do we mean by cost effectiveness?

    Cost effectiveness, in general, is a criterion used to assess the 
potential for achieving an objective in the most economical way. For 
purposes of air pollutant analysis, ``effectiveness'' is measured in 
terms of tons of pollutant emissions removed, and ``cost'' is measured 
in terms of annualized control costs. We recommend two types of cost-
effectiveness calculations--average cost effectiveness, and incremental 
cost effectiveness.

            c. How do I calculate average cost effectiveness?

    Average cost effectiveness means the total annualized costs of 
control divided by annual emissions reductions (the difference between 
baseline annual emissions and the estimate of emissions after controls), 
using the following formula:

Average cost effectiveness (dollars per ton removed) = Control option 
          annualized cost \16\
---------------------------------------------------------------------------

    \16\ Whenever you calculate or report annual costs, you should 
indicate the year for which the costs are estimated. For example, if you 
use the year 2000 as the basis for cost comparisons, you would report 
that an annualized cost of $20 million would be: $20 million (year 2000 
dollars).

Baseline annual emissions--Annual emissions with Control option
    Because you calculate costs in (annualized) dollars per year ($/yr) 
and because you calculate emissions rates in tons per year (tons/yr), 
the result is an average cost-effectiveness number in (annualized) 
dollars per ton ($/ton) of pollutant removed.

                d. How do I calculate baseline emissions?

    1. The baseline emissions rate should represent a realistic 
depiction of anticipated annual emissions for the source. In general, 
for the existing sources subject to BART, you will estimate the 
anticipated annual emissions based upon actual emissions from a baseline 
period.
    2. When you project that future operating parameters (e.g., limited 
hours of operation or capacity utilization, type of fuel, raw materials 
or product mix or type) will differ from past practice, and if this 
projection has a deciding effect in the BART determination,

[[Page 569]]

then you must make these parameters or assumptions into enforceable 
limitations. In the absence of enforceable limitations, you calculate 
baseline emissions based upon continuation of past practice.
    3. For example, the baseline emissions calculation for an emergency 
standby generator may consider the fact that the source owner would not 
operate more than past practice of 2 weeks a year. On the other hand, 
baseline emissions associated with a base-loaded turbine should be based 
on its past practice which would indicate a large number of hours of 
operation. This produces a significantly higher level of baseline 
emissions than in the case of the emergency/standby unit and results in 
more cost-effective controls. As a consequence of the dissimilar 
baseline emissions, BART for the two cases could be very different.

          e. How do I calculate incremental cost effectiveness?

    1. In addition to the average cost effectiveness of a control 
option, you should also calculate incremental cost effectiveness. You 
should consider the incremental cost effectiveness in combination with 
the average cost effectiveness when considering whether to eliminate a 
control option. The incremental cost effectiveness calculation compares 
the costs and performance level of a control option to those of the next 
most stringent option, as shown in the following formula (with respect 
to cost per emissions reduction):

Incremental Cost Effectiveness (dollars per incremental ton removed) = 
          (Total annualized costs of control option) - (Total annualized 
          costs of next control option) / (Control option annual 
          emissions) - (Next control option annual emissions)

    Example 1: Assume that Option F on Figure 2 has total annualized 
costs of $1 million to reduce 2000 tons of a pollutant, and that Option 
D on Figure 2 has total annualized costs of $500,000 to reduce 1000 tons 
of the same pollutant. The incremental cost effectiveness of Option F 
relative to Option D is ($1 million - $500,000) divided by (2000 tons - 
1000 tons), or $500,000 divided by 1000 tons, which is $500/ton.
    Example 2: Assume that two control options exist: Option 1 and 
Option 2. Option 1 achieves a 1,000 ton/yr reduction at an annualized 
cost of $1,900,000. This represents an average cost of ($1,900,000/1,000 
tons) = $1,900/ton. Option 2 achieves a 980 tons/yr reduction at an 
annualized cost of $1,500,000. This represents an average cost of 
($1,500,000/980 tons) = $1,531/ton. The incremental cost effectiveness 
of Option 1 relative to Option 2 is ($1,900,000 - $1,500,000) divided by 
(1,000 tons - 980 tons). The adoption of Option 1 instead of Option 2 
results in an incremental emission reduction of 20 tons per year at an 
additional cost of $400,000 per year. The incremental cost of Option 1, 
then, is $20,000 per ton - 11 times the average cost of $1,900 per ton. 
While $1,900 per ton may still be deemed reasonable, it is useful to 
consider both the average and incremental cost in making an overall 
cost-effectiveness finding. Of course, there may be other differences 
between these options, such as, energy or water use, or non-air 
environmental effects, which also should be considered in selecting a 
BART technology.

    2. You should exercise care in deriving incremental costs of 
candidate control options. Incremental cost-effectiveness comparisons 
should focus on annualized cost and emission reduction differences 
between ``dominant'' alternatives. To identify dominant alternatives, 
you generate a graphical plot of total annualized costs for total 
emissions reductions for all control alternatives identified in the BART 
analysis, and by identifying a ``least-cost envelope'' as shown in 
Figure 2. (A ``least-cost envelope'' represents the set of options that 
should be dominant in the choice of a specific option.)

[[Page 570]]

[GRAPHIC] [TIFF OMITTED] TR06JY05.000

    Example: Eight technically feasible control options for analysis are 
listed. These are represented as A through H in Figure 2. The dominant 
set of control options, B, D, F, G, and H, represent the least-cost 
envelope, as we depict by the cost curve connecting them. Points A, C 
and E are inferior options, and you should not use them in calculating 
incremental cost effectiveness. Points A, C and E represent inferior 
controls because B will buy more emissions reductions for less money 
than A; and similarly, D and F will buy more reductions for less money 
than C and E, respectively.

    3. In calculating incremental costs, you:
    (1) Array the control options in ascending order of annualized total 
costs,
    (2) Develop a graph of the most reasonable smooth curve of the 
control options, as shown in Figure 2. This is to show the ``least-cost 
envelope'' discussed above; and
    (3) Calculate the incremental cost effectiveness for each dominant 
option, which is the difference in total annual costs between that 
option and the next most stringent option, divided by the difference in 
emissions, after controls have been applied, between those two control 
options. For example, using Figure 2, you would calculate incremental 
cost effectiveness for the difference between options B and D, options D 
and F, options F and G, and options G and H.
    4. A comparison of incremental costs can also be useful in 
evaluating the viability of a specific control option over a range of 
efficiencies. For example, depending on the capital and operational cost 
of a control device, total and incremental cost may vary significantly 
(either increasing or decreasing) over the operational range of a 
control device. Also, the greater the number of possible control options 
that exist, the more weight should be given to the incremental costs vs. 
average costs. It should be noted that average and incremental cost 
effectiveness are identical when only one candidate control option is 
known to exist.
    5. You should exercise caution not to misuse these techniques. For 
example, you may be faced with a choice between two available control 
devices at a source, control A and control B, where control B achieves 
slightly

[[Page 571]]

greater emission reductions. The average cost (total annual cost/total 
annual emission reductions) for each may be deemed to be reasonable. 
However, the incremental cost (total annual costA - B/total 
annual emission reductionsA - B) of the additional emission 
reductions to be achieved by control B may be very great. In such an 
instance, it may be inappropriate to choose control B, based on its high 
incremental costs, even though its average cost may be considered 
reasonable.
    6. In addition, when you evaluate the average or incremental cost 
effectiveness of a control alternative, you should make reasonable and 
supportable assumptions regarding control efficiencies. An 
unrealistically low assessment of the emission reduction potential of a 
certain technology could result in inflated cost-effectiveness figures.

f. What other information should I provide in the cost impacts analysis?

    You should provide documentation of any unusual circumstances that 
exist for the source that would lead to cost-effectiveness estimates 
that would exceed that for recent retrofits. This is especially 
important in cases where recent retrofits have cost-effectiveness values 
that are within what has been considered a reasonable range, but your 
analysis concludes that costs for the source being analyzed are not 
considered reasonable. (A reasonable range would be a range that is 
consistent with the range of cost effectiveness values used in other 
similar permit decisions over a period of time.)

    Example: In an arid region, large amounts of water are needed for a 
scrubbing system. Acquiring water from a distant location could greatly 
increase the cost per ton of emissions reduced of wet scrubbing as a 
control option.

   g. What other things are important to consider in the cost impacts 
                                analysis?

    In the cost analysis, you should take care not to focus on 
incomplete results or partial calculations. For example, large capital 
costs for a control option alone would not preclude selection of a 
control measure if large emissions reductions are projected. In such a 
case, low or reasonable cost effectiveness numbers may validate the 
option as an appropriate BART alternative irrespective of the large 
capital costs. Similarly, projects with relatively low capital costs may 
not be cost effective if there are few emissions reduced.

   h. Impact analysis part 2: How should I analyze and report energy 
                                impacts?

    1. You should examine the energy requirements of the control 
technology and determine whether the use of that technology results in 
energy penalties or benefits. A source owner may, for example, benefit 
from the combustion of a concentrated gas stream rich in volatile 
organic compounds; on the other hand, more often extra fuel or 
electricity is required to power a control device or incinerate a dilute 
gas stream. If such benefits or penalties exist, they should be 
quantified to the extent practicable. Because energy penalties or 
benefits can usually be quantified in terms of additional cost or income 
to the source, the energy impacts analysis can, in most cases, simply be 
factored into the cost impacts analysis. The fact of energy use in and 
of itself does not disqualify a technology.
    2. Your energy impact analysis should consider only direct energy 
consumption and not indirect energy impacts. For example, you could 
estimate the direct energy impacts of the control alternative in units 
of energy consumption at the source (e.g., BTU, kWh, barrels of oil, 
tons of coal). The energy requirements of the control options should be 
shown in terms of total (and in certain cases, also incremental) energy 
costs per ton of pollutant removed. You can then convert these units 
into dollar costs and, where appropriate, factor these costs into the 
control cost analysis.
    3. You generally do not consider indirect energy impacts (such as 
energy to produce raw materials for construction of control equipment). 
However, if you determine, either independently or based on a showing by 
the source owner, that the indirect energy impact is unusual or 
significant and that the impact can be well quantified, you may consider 
the indirect impact.
    4. The energy impact analysis may also address concerns over the use 
of locally scarce fuels. The designation of a scarce fuel may vary from 
region to region. However, in general, a scarce fuel is one which is in 
short supply locally and can be better used for alternative purposes, or 
one which may not be reasonably available to the source either at the 
present time or in the near future.
    5. Finally, the energy impacts analysis may consider whether there 
are relative differences between alternatives regarding the use of 
locally or regionally available coal, and whether a given alternative 
would result in significant economic disruption or unemployment. For 
example, where two options are equally cost effective and achieve 
equivalent or similar emissions reductions, one option may be preferred 
if the other alternative results in significant disruption or 
unemployment.

     i. Impact analysis part 3: How do I analyze ``non-air quality 
                        environmental impacts?''

    1. In the non-air quality related environmental impacts portion of 
the BART analysis, you address environmental impacts other than air 
quality due to emissions of the pollutant in question. Such 
environmental impacts include solid or hazardous

[[Page 572]]

waste generation and discharges of polluted water from a control device.
    2. You should identify any significant or unusual environmental 
impacts associated with a control alternative that have the potential to 
affect the selection or elimination of a control alternative. Some 
control technologies may have potentially significant secondary 
environmental impacts. Scrubber effluent, for example, may affect water 
quality and land use. Alternatively, water availability may affect the 
feasibility and costs of wet scrubbers. Other examples of secondary 
environmental impacts could include hazardous waste discharges, such as 
spent catalysts or contaminated carbon. Generally, these types of 
environmental concerns become important when sensitive site-specific 
receptors exist or when the incremental emissions reductions potential 
of the more stringent control is only marginally greater than the next 
most-effective option. However, the fact that a control device creates 
liquid and solid waste that must be disposed of does not necessarily 
argue against selection of that technology as BART, particularly if the 
control device has been applied to similar facilities elsewhere and the 
solid or liquid waste is similar to those other applications. On the 
other hand, where you or the source owner can show that unusual 
circumstances at the proposed facility create greater problems than 
experienced elsewhere, this may provide a basis for the elimination of 
that control alternative as BART.
    3. The procedure for conducting an analysis of non-air quality 
environmental impacts should be made based on a consideration of site-
specific circumstances. If you propose to adopt the most stringent 
alternative, then it is not necessary to perform this analysis of 
environmental impacts for the entire list of technologies you ranked in 
Step 3. In general, the analysis need only address those control 
alternatives with any significant or unusual environmental impacts that 
have the potential to affect the selection of a control alternative, or 
elimination of a more stringent control alternative. Thus, any important 
relative environmental impacts (both positive and negative) of 
alternatives can be compared with each other.
    4. In general, the analysis of impacts starts with the 
identification and quantification of the solid, liquid, and gaseous 
discharges from the control device or devices under review. Initially, 
you should perform a qualitative or semi-quantitative screening to 
narrow the analysis to discharges with potential for causing adverse 
environmental effects. Next, you should assess the mass and composition 
of any such discharges and quantify them to the extent possible, based 
on readily available information. You should also assemble pertinent 
information about the public or environmental consequences of releasing 
these materials.

    j. Impact analysis part 4: What are examples of non-air quality 
                         environmental impacts?

    The following are examples of how to conduct non-air quality 
environmental impacts:
    (1) Water Impact
    You should identify the relative quantities of water used and water 
pollutants produced and discharged as a result of the use of each 
alternative emission control system. Where possible, you should assess 
the effect on ground water and such local surface water quality 
parameters as ph, turbidity, dissolved oxygen, salinity, toxic chemical 
levels, temperature, and any other important considerations. The 
analysis could consider whether applicable water quality standards will 
be met and the availability and effectiveness of various techniques to 
reduce potential adverse effects.
    (2) Solid Waste Disposal Impact
    You could also compare the quality and quantity of solid waste 
(e.g., sludges, solids) that must be stored and disposed of or recycled 
as a result of the application of each alternative emission control 
system. You should consider the composition and various other 
characteristics of the solid waste (such as permeability, water 
retention, rewatering of dried material, compression strength, 
leachability of dissolved ions, bulk density, ability to support 
vegetation growth and hazardous characteristics) which are significant 
with regard to potential surface water pollution or transport into and 
contamination of subsurface waters or aquifers.
    (3) Irreversible or Irretrievable Commitment of Resources
    You may consider the extent to which the alternative emission 
control systems may involve a trade-off between short-term environmental 
gains at the expense of long-term environmental losses and the extent to 
which the alternative systems may result in irreversible or 
irretrievable commitment of resources (for example, use of scarce water 
resources).
    (4) Other Adverse Environmental Impacts
    You may consider significant differences in noise levels, radiant 
heat, or dissipated static electrical energy of pollution control 
alternatives. Other examples of non-air quality environmental impacts 
would include hazardous waste discharges such as spent catalysts or 
contaminated carbon.

 k. How do I take into account a project's ``remaining useful life'' in 
                       calculating control costs?

    1. You may decide to treat the requirement to consider the source's 
``remaining useful life'' of the source for BART determinations as one 
element of the overall cost analysis. The ``remaining useful life'' of a 
source, if it

[[Page 573]]

represents a relatively short time period, may affect the annualized 
costs of retrofit controls. For example, the methods for calculating 
annualized costs in EPA's OAQPS Control Cost Manual require the use of a 
specified time period for amortization that varies based upon the type 
of control. If the remaining useful life will clearly exceed this time 
period, the remaining useful life has essentially no effect on control 
costs and on the BART determination process. Where the remaining useful 
life is less than the time period for amortizing costs, you should use 
this shorter time period in your cost calculations.
    2. For purposes of these guidelines, the remaining useful life is 
the difference between:
    (1) The date that controls will be put in place (capital and other 
construction costs incurred before controls are put in place can be 
rolled into the first year, as suggested in EPA's OAQPS Control Cost 
Manual); you are conducting the BART analysis; and
    (2) The date the facility permanently stops operations. Where this 
affects the BART determination, this date should be assured by a 
federally- or State-enforceable restriction preventing further 
operation.
    3. We recognize that there may be situations where a source operator 
intends to shut down a source by a given date, but wishes to retain the 
flexibility to continue operating beyond that date in the event, for 
example, that market conditions change. Where this is the case, your 
BART analysis may account for this, but it must maintain consistency 
with the statutory requirement to install BART within 5 years. Where the 
source chooses not to accept a federally enforceable condition requiring 
the source to shut down by a given date, it is necessary to determine 
whether a reduced time period for the remaining useful life changes the 
level of controls that would have been required as BART.
    If the reduced time period does change the level of BART controls, 
you may identify, and include as part of the BART emission limitation, 
the more stringent level of control that would be required as BART if 
there were no assumption that reduced the remaining useful life. You may 
incorporate into the BART emission limit this more stringent level, 
which would serve as a contingency should the source continue operating 
more than 5 years after the date EPA approves the relevant SIP. The 
source would not be allowed to operate after the 5-year mark without 
such controls. If a source does operate after the 5-year mark without 
BART in place, the source is considered to be in violation of the BART 
emissions limit for each day of operation.

    5. Step 5: How should I determine visibility impacts in the BART 
                             determination?

    The following is an approach you may use to determine visibility 
impacts (the degree of visibility improvement for each source subject to 
BART) for the BART determination. Once you have determined that your 
source or sources are subject to BART, you must conduct a visibility 
improvement determination for the source(s) as part of the BART 
determination. When making this determination, we believe you have 
flexibility in setting absolute thresholds, target levels of 
improvement, or de minimis levels since the deciview improvement must be 
weighed among the five factors, and you are free to determine the weight 
and significance to be assigned to each factor. For example, a 0.3 
deciview improvement may merit a stronger weighting in one case versus 
another, so one ``bright line'' may not be appropriate. [Note that if 
sources have elected to apply the most stringent controls available, 
consistent with the discussion in section E. step 1. below, you need not 
conduct, or require the source to conduct, an air quality modeling 
analysis for the purpose of determining its visibility impacts.]
    Use CALPUFF,\17\ or other appropriate dispersion model to determine 
the visibility improvement expected at a Class I area from the potential 
BART control technology applied to the source. Modeling should be 
conducted for SO2, NOX, and direct PM emissions 
(PM2.5 and/or PM10). If the source is making the 
visibility determination, you should review and approve or disapprove of 
the source's analysis before making the expected improvement 
determination. There are several steps for determining the visibility 
impacts from an individual source using a dispersion model:
---------------------------------------------------------------------------

    \17\ The model code and its documentation are available at no cost 
for download from http://www.epa.gov/scram001/tt22.htm#calpuff.
---------------------------------------------------------------------------

     Develop a modeling protocol.
    Some critical items to include in a modeling protocol are 
meteorological and terrain data, as well as source-specific information 
(stack height, temperature, exit velocity, elevation, and allowable and 
actual emission rates of applicable pollutants), and receptor data from 
appropriate Class I areas. We recommend following EPA's Interagency 
Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and 
Recommendations for Modeling Long Range Transport Impacts \18\ for 
parameter settings and meteorological data inputs; the use of other 
settings from

[[Page 574]]

those in IWAQM should be identified and explained in the protocol.
---------------------------------------------------------------------------

    \18\ Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 
Summary Report and Recommendations for Modeling Long Range Transport 
Impacts, U.S. Environmental Protection Agency, EPA-454/R-98-019, 
December 1998.
---------------------------------------------------------------------------

    One important element of the protocol is in establishing the 
receptors that will be used in the model. The receptors that you use 
should be located in the nearest Class I area with sufficient density to 
identify the likely visibility effects of the source. For other Class I 
areas in relatively close proximity to a BART-eligible source, you may 
model a few strategic receptors to determine whether effects at those 
areas may be greater than at the nearest Class I area. For example, you 
might chose to locate receptors at these areas at the closest point to 
the source, at the highest and lowest elevation in the Class I area, at 
the IMPROVE monitor, and at the approximate expected plume release 
height. If the highest modeled effects are observed at the nearest Class 
I area, you may choose not to analyze the other Class I areas any 
further as additional analyses might be unwarranted.
    You should bear in mind that some receptors within the relevant 
Class I area may be less than 50 km from the source while other 
receptors within that same Class I area may be greater than 50 km from 
the same source. As indicated by the Guideline on Air Quality Models, 
this situation may call for the use of two different modeling approaches 
for the same Class I area and source, depending upon the State's chosen 
method for modeling sources less than 50 km. In situations where you are 
assessing visibility impacts for source-receptor distances less than 50 
km, you should use expert modeling judgment in determining visibility 
impacts, giving consideration to both CALPUFF and other EPA-approved 
methods.
    In developing your modeling protocol, you may want to consult with 
EPA and your regional planning organization (RPO). Up-front consultation 
will ensure that key technical issues are addressed before you conduct 
your modeling.
     For each source, run the model, at pre-control 
and post-control emission rates according to the accepted methodology in 
the protocol.
    Use the 24-hour average actual emission rate from the highest 
emitting day of the meteorological period modeled (for the pre-control 
scenario). Calculate the model results for each receptor as the change 
in deciviews compared against natural visibility conditions. Post-
control emission rates are calculated as a percentage of pre-control 
emission rates. For example, if the 24-hr pre-control emission rate is 
100 lb/hr of SO2, then the post control rate is 5 lb/hr if 
the control efficiency being evaluated is 95 percent.
     Make the net visibility improvement 
determination.
    Assess the visibility improvement based on the modeled change in 
visibility impacts for the pre-control and post-control emission 
scenarios. You have flexibility to assess visibility improvements due to 
BART controls by one or more methods. You may consider the frequency, 
magnitude, and duration components of impairment. Suggestions for making 
the determination are:
     Use of a comparison threshold, as is done for 
determining if BART-eligible sources should be subject to a BART 
determination. Comparison thresholds can be used in a number of ways in 
evaluating visibility improvement (e.g. the number of days or hours that 
the threshold was exceeded, a single threshold for determining whether a 
change in impacts is significant, or a threshold representing an x 
percent change in improvement).
     Compare the 98th percent days for the pre- and 
post-control runs.
    Note that each of the modeling options may be supplemented with 
source apportionment data or source apportionment modeling.

E. How do I select the ``best'' alternative, using the results of Steps 
                              1 through 5?

                   1. Summary of the Impacts Analysis

    From the alternatives you evaluated in Step 3, we recommend you 
develop a chart (or charts) displaying for each of the alternatives:
    (1) Expected emission rate (tons per year, pounds per hour);
    (2) Emissions performance level (e.g., percent pollutant removed, 
emissions per unit product, lb/MMBtu, ppm);
    (3) Expected emissions reductions (tons per year);
    (4) Costs of compliance--total annualized costs ($), cost 
effectiveness ($/ton), and incremental cost effectiveness ($/ton), and/
or any other cost-effectiveness measures (such as $/deciview);
    (5) Energy impacts;
    (6) Non-air quality environmental impacts; and
    (7) Modeled visibility impacts.

                   2. Selecting a ``best'' alternative

    1. You have discretion to determine the order in which you should 
evaluate control options for BART. Whatever the order in which you 
choose to evaluate options, you should always (1) display the options 
evaluated; (2) identify the average and incremental costs of each 
option; (3) consider the energy and non-air quality environmental 
impacts of each option; (4) consider the remaining useful life; and (5) 
consider the modeled visibility impacts. You should provide a 
justification for adopting the technology that you select as the 
``best'' level of control, including an explanation of the CAA factors 
that led you to choose that option over other control levels.

[[Page 575]]

    2. In the case where you are conducting a BART determination for two 
regulated pollutants on the same source, if the result is two different 
BART technologies that do not work well together, you could then 
substitute a different technology or combination of technologies.

     3. In selecting a ``best'' alternative, should I consider the 
                       affordability of controls?

    1. Even if the control technology is cost effective, there may be 
cases where the installation of controls would affect the viability of 
continued plant operations.
    2. There may be unusual circumstances that justify taking into 
consideration the conditions of the plant and the economic effects of 
requiring the use of a given control technology. These effects would 
include effects on product prices, the market share, and profitability 
of the source. Where there are such unusual circumstances that are 
judged to affect plant operations, you may take into consideration the 
conditions of the plant and the economic effects of requiring the use of 
a control technology. Where these effects are judged to have a severe 
impact on plant operations you may consider them in the selection 
process, but you may wish to provide an economic analysis that 
demonstrates, in sufficient detail for public review, the specific 
economic effects, parameters, and reasoning. (We recognize that this 
review process must preserve the confidentiality of sensitive business 
information). Any analysis may also consider whether other competing 
plants in the same industry have been required to install BART controls 
if this information is available.

              4. Sulfur dioxide limits for utility boilers

    You must require 750 MW power plants to meet specific control levels 
for SO2 of either 95 percent control or 0.15 lbs/MMBtu, for 
each EGU greater than 200 MW that is currently uncontrolled unless you 
determine that an alternative control level is justified based on a 
careful consideration of the statutory factors. Thus, for example, if 
the source demonstrates circumstances affecting its ability to cost-
effectively reduce its emissions, you should take that into account in 
determining whether the presumptive levels of control are appropriate 
for that facility. For a currently uncontrolled EGU greater than 200 MW 
in size, but located at a power plant smaller than 750 MW in size, such 
controls are generally cost-effective and could be used in your BART 
determination considering the five factors specified in CAA section 
169A(g)(2). While these levels may represent current control 
capabilities, we expect that scrubber technology will continue to 
improve and control costs continue to decline. You should be sure to 
consider the level of control that is currently best achievable at the 
time that you are conducting your BART analysis.
    For coal-fired EGUs with existing post-combustion SO2 
controls achieving less than 50 percent removal efficiencies, we 
recommend that you evaluate constructing a new FGD system to meet the 
same emission limits as above (95 percent removal or 0.15 lb/mmBtu), in 
addition to the evaluation of scrubber upgrades discussed below. For 
oil-fired units, regardless of size, you should evaluate limiting the 
sulfur content of the fuel oil burned to 1 percent or less by weight.
    For those BART-eligible EGUs with pre-existing post-combustion 
SO2 controls achieving removal efficiencies of at least 50 
percent, your BART determination should consider cost effective scrubber 
upgrades designed to improve the system's overall SO2 removal 
efficiency. There are numerous scrubber enhancements available to 
upgrade the average removal efficiencies of all types of existing 
scrubber systems. We recommend that as you evaluate the definition of 
``upgrade,'' you evaluate options that not only improve the design 
removal efficiency of the scrubber vessel itself, but also consider 
upgrades that can improve the overall SO2 removal efficiency 
of the scrubber system. Increasing a scrubber system's reliability, and 
conversely decreasing its downtime, by way of optimizing operation 
procedures, improving maintenance practices, adjusting scrubber 
chemistry, and increasing auxiliary equipment redundancy, are all ways 
to improve average SO2 removal efficiencies.
    We recommend that as you evaluate the performance of existing wet 
scrubber systems, you consider some of the following upgrades, in no 
particular order, as potential scrubber upgrades that have been proven 
in the industry as cost effective means to increase overall 
SO2 removal of wet systems:
    (a) Elimination of Bypass Reheat;
    (b) Installation of Liquid Distribution Rings;
    (c) Installation of Perforated Trays;
    (d) Use of Organic Acid Additives;
    (e) Improve or Upgrade Scrubber Auxiliary System Equipment;
    (f) Redesign Spray Header or Nozzle Configuration.
    We recommend that as you evaluate upgrade options for dry scrubber 
systems, you should consider the following cost effective upgrades, in 
no particular order:
    (a) Use of Performance Additives;
    (b) Use of more Reactive Sorbent;
    (c) Increase the Pulverization Level of Sorbent;
    (d) Engineering redesign of atomizer or slurry injection system.
    You should evaluate scrubber upgrade options based on the 5 step 
BART analysis process.

[[Page 576]]

              5. Nitrogen oxide limits for utility boilers

    You should establish specific numerical limits for NOX 
control for each BART determination. For power plants with a generating 
capacity in excess of 750 MW currently using selective catalytic 
reduction (SCR) or selective non-catalytic reduction (SNCR) for part of 
the year, you should presume that use of those same controls year-round 
is BART. For other sources currently using SCR or SNCR to reduce 
NOX emissions during part of the year, you should carefully 
consider requiring the use of these controls year-round as the 
additional costs of operating the equipment throughout the year would be 
relatively modest.
    For coal-fired EGUs greater than 200 MW located at greater than 750 
MW power plants and operating without post-combustion controls (i.e. SCR 
or SNCR), we have provided presumptive NOX limits, 
differentiated by boiler design and type of coal burned. You may 
determine that an alternative control level is appropriate based on a 
careful consideration of the statutory factors. For coal-fired EGUs 
greater than 200 MW located at power plants 750 MW or less in size and 
operating without post-combustion controls, you should likewise presume 
that these same levels are cost-effective. You should require such 
utility boilers to meet the following NOX emission limits, 
unless you determine that an alternative control level is justified 
based on consideration of the statutory factors. The following 
NOX emission rates were determined based on a number of 
assumptions, including that the EGU boiler has enough volume to allow 
for installation and effective operation of separated overfire air 
ports. For boilers where these assumptions are incorrect, these emission 
limits may not be cost-effective.

  Table 1--Presumptive NOX Emission Limits for BART-Eligible Coal-Fired
                               Units. \19\
------------------------------------------------------------------------
                                                         NOX presumptive
           Unit type                   Coal type           limit  (lb/
                                                           mmbtu) \20\
------------------------------------------------------------------------
Dry-bottom wall-fired.........  Bituminous............              0.39
                                Sub-bituminous........              0.23
                                Lignite...............              0.29
Tangential-fired..............  Bituminous............              0.28
                                Sub-bituminous........              0.15
                                Lignite...............              0.17
Cell Burners..................  Bituminous............              0.40
                                Sub-bituminous........              0.45
Dry-turbo-fired...............  Bituminous............              0.32
                                Sub-bituminous........              0.23
Wet-bottom tangential-fired...  Bituminous............              0.62
------------------------------------------------------------------------
\19\ No Cell burners, dry-turbo-fired units, nor wet-bottom tangential-
  fired units burning lignite were identified as BART-eligible, thus no
  presumptive limit was determined. Similarly, no wet-bottom tangential-
  fired units burning sub-bituminous were identified as BART-eligible.
\20\ These limits reflect the design and technological assumptions
  discussed in the technical support document for NOX limits for these
  guidelines. See Technical Support Document for BART NOX Limits for
  Electric Generating Units and Technical Support Document for BART NOX
  Limits for Electric Generating Units Excel Spreadsheet, Memorandum to
  Docket OAR 2002-0076, April 15, 2005.

    Most EGUs can meet these presumptive NOX limits through 
the use of current combustion control technology, i.e. the careful 
control of combustion air and low-NOX burners. For units that 
cannot meet these limits using such technologies, you should consider 
whether advanced combustion control technologies such as rotating 
opposed fire air should be used to meet these limits.
    Because of the relatively high NOX emission rates of 
cyclone units, SCR is more cost-effective than the use of current 
combustion control technology for these units. The use of SCRs at 
cyclone units burning bituminous coal, sub-bituminous coal, and lignite 
should enable the units to cost-effectively meet NOX rates of 
0.10 lbs/mmbtu. As a result, we are establishing a presumptive 
NOX limit of 0.10 lbs/mmbtu based on the use of SCR for coal-
fired cyclone units greater than 200 MW located at 750 MW power plants. 
As with the other presumptive limits established in this guideline, you 
may determine that an alternative level of control is appropriate based 
on your consideration of the relevant statutory factors. For other 
cyclone units, you should review the use of SCR and consider whether 
these post-combustion controls should be required as BART.
    For oil-fired and gas-fired EGUs larger than 200MW, we believe that 
installation of current combustion control technology to control 
NOX is generally highly cost-effective and should be 
considered in your determination of BART for these sources. Many such 
units can make significant reductions in NOX emissions which 
are highly cost-effective through the application of current combustion 
control technology.\21\
---------------------------------------------------------------------------

    \21\ See Technical Support Document for BART NOX Limits for Electric 
Generating Units and Technical Support Document for BART NOX Limits for 
Electric Generating Units Excel Spreadsheet, Memorandum to Docket OAR 
2002-0076, April 15, 2005.

---------------------------------------------------------------------------

[[Page 577]]

                  V. Enforceable Limits/Compliance Date

    To complete the BART process, you must establish enforceable 
emission limits that reflect the BART requirements and require 
compliance within a given period of time. In particular, you must 
establish an enforceable emission limit for each subject emission unit 
at the source and for each pollutant subject to review that is emitted 
from the source. In addition, you must require compliance with the BART 
emission limitations no later than 5 years after EPA approves your 
regional haze SIP. If technological or economic limitations in the 
application of a measurement methodology to a particular emission unit 
make a conventional emissions limit infeasible, you may instead 
prescribe a design, equipment, work practice, operation standard, or 
combination of these types of standards. You should consider allowing 
sources to ``average'' emissions across any set of BART-eligible 
emission units within a fenceline, so long as the emission reductions 
from each pollutant being controlled for BART would be equal to those 
reductions that would be obtained by simply controlling each of the 
BART-eligible units that constitute BART-eligible source.
    You should ensure that any BART requirements are written in a way 
that clearly specifies the individual emission unit(s) subject to BART 
regulation. Because the BART requirements themselves are ``applicable'' 
requirements of the CAA, they must be included as title V permit 
conditions according to the procedures established in 40 CFR part 70 or 
40 CFR part 71.
    Section 302(k) of the CAA requires emissions limits such as BART to 
be met on a continuous basis. Although this provision does not 
necessarily require the use of continuous emissions monitoring (CEMs), 
it is important that sources employ techniques that ensure compliance on 
a continuous basis. Monitoring requirements generally applicable to 
sources, including those that are subject to BART, are governed by other 
regulations. See, e.g., 40 CFR part 64 (compliance assurance 
monitoring); 40 CFR 70.6(a)(3) (periodic monitoring); 40 CFR 70.6(c)(1) 
(sufficiency monitoring). Note also that while we do not believe that 
CEMs would necessarily be required for all BART sources, the vast 
majority of electric generating units potentially subject to BART 
already employ CEM technology for other programs, such as the acid rain 
program. In addition, emissions limits must be enforceable as a 
practical matter (contain appropriate averaging times, compliance 
verification procedures and recordkeeping requirements). In light of the 
above, the permit must:
     Be sufficient to show compliance or noncompliance 
(i.e., through monitoring times of operation, fuel input, or other 
indices of operating conditions and practices); and
     Specify a reasonable averaging time consistent 
with established reference methods, contain reference methods for 
determining compliance, and provide for adequate reporting and 
recordkeeping so that air quality agency personnel can determine the 
compliance status of the source; and
     For EGUS, specify an averaging time of a 30-day 
rolling average, and contain a definition of ``boiler operating day'' 
that is consistent with the definition in the proposed revisions to the 
NSPS for utility boilers in 40 CFR Part 60, subpart Da. \22\ You should 
consider a boiler operating day to be any 24-hour period between 12:00 
midnight and the following midnight during which any fuel is combusted 
at any time at the steam generating unit. This would allow 30-day 
rolling average emission rates to be calculated consistently across 
sources.
---------------------------------------------------------------------------

    \22\ 70 FR 9705, February 28, 2005.

[70 FR 39156, July 6, 2005]

[[Page 579]]



                              FINDING AIDS




  --------------------------------------------------------------------

  A list of CFR titles, subtitles, chapters, subchapters and parts and 
an alphabetical list of agencies publishing in the CFR are included in 
the CFR Index and Finding Aids volume to the Code of Federal Regulations 
which is published separately and revised annually.

  Material Approved for Incorporation by Reference
  Table of CFR Titles and Chapters
  Alphabetical List of Agencies Appearing in the CFR
  List of CFR Sections Affected

[[Page 581]]

            Material Approved for Incorporation by Reference

                      (Revised as of July 1, 2006)

  The Director of the Federal Register has approved under 5 U.S.C. 
552(a) and 1 CFR Part 51 the incorporation by reference of the following 
publications. This list contains only those incorporations by reference 
effective as of the revision date of this volume. Incorporations by 
reference found within a regulation are effective upon the effective 
date of that regulation. For more information on incorporation by 
reference, see the preliminary pages of this volume.


40 CFR (PARTS 50 TO 51)

ENVIRONMENTAL PROTECTION AGENCY
                                                                  40 CFR


Environmental Protection Agency

  Office of Air Quality Planning and Standards, 
  Research Triangle Park, NC 27711
``Guidelines for Determining Best Available                    51.302(c)
  Retrofit Technology for Coal-Fired Power Plants 
  and Other Existing Stationary Facilities'', 
  (1980), EPA 450/3-80-009b.
``Guidelines on Air Quality Models (Revised)''                 51.166(l)
  (1986) and Supplement A (1987), EPA 450/2-78-
  027R.
  Copies may be obtained from: National Technical 
  Information Service, 5285 Port Royal Rd., 
  Springfield, VA 22161; Telephone: (703) 487-
  4650, FAX: (703) 487-4142

[[Page 583]]



                    Table of CFR Titles and Chapters




                      (Revised as of July 1, 2006)

                      Title 1--General Provisions

         I  Administrative Committee of the Federal Register 
                (Parts 1--49)
        II  Office of the Federal Register (Parts 50--299)
        IV  Miscellaneous Agencies (Parts 400--500)

                    Title 2--Grants and Agreements

            Subtitle A--Office of Management and Budget Guidance 
                for Grants and Agreements
         I  Office of Management and Budget Governmentwide 
                Guidance for Grants and Agreements (Parts 100-199)
        II  Office of Management and Budget Circulars and Guidance 
                (200-299)
            Subtitle B--Federal Agency Regulations for Grants and 
                Agreements [Reserved]


                        Title 3--The President

         I  Executive Office of the President (Parts 100--199)

                           Title 4--Accounts

         I  Government Accountability Office (Parts 1--99)

                   Title 5--Administrative Personnel

         I  Office of Personnel Management (Parts 1--1199)
        II  Merit Systems Protection Board (Parts 1200--1299)
       III  Office of Management and Budget (Parts 1300--1399)
         V  The International Organizations Employees Loyalty 
                Board (Parts 1500--1599)
        VI  Federal Retirement Thrift Investment Board (Parts 
                1600--1699)
      VIII  Office of Special Counsel (Parts 1800--1899)
        IX  Appalachian Regional Commission (Parts 1900--1999)
        XI  Armed Forces Retirement Home (Part 2100)
       XIV  Federal Labor Relations Authority, General Counsel of 
                the Federal Labor Relations Authority and Federal 
                Service Impasses Panel (Parts 2400--2499)

[[Page 584]]

        XV  Office of Administration, Executive Office of the 
                President (Parts 2500--2599)
       XVI  Office of Government Ethics (Parts 2600--2699)
       XXI  Department of the Treasury (Parts 3100--3199)
      XXII  Federal Deposit Insurance Corporation (Part 3201)
     XXIII  Department of Energy (Part 3301)
      XXIV  Federal Energy Regulatory Commission (Part 3401)
       XXV  Department of the Interior (Part 3501)
      XXVI  Department of Defense (Part 3601)
    XXVIII  Department of Justice (Part 3801)
      XXIX  Federal Communications Commission (Parts 3900--3999)
       XXX  Farm Credit System Insurance Corporation (Parts 4000--
                4099)
      XXXI  Farm Credit Administration (Parts 4100--4199)
    XXXIII  Overseas Private Investment Corporation (Part 4301)
      XXXV  Office of Personnel Management (Part 4501)
        XL  Interstate Commerce Commission (Part 5001)
       XLI  Commodity Futures Trading Commission (Part 5101)
      XLII  Department of Labor (Part 5201)
     XLIII  National Science Foundation (Part 5301)
       XLV  Department of Health and Human Services (Part 5501)
      XLVI  Postal Rate Commission (Part 5601)
     XLVII  Federal Trade Commission (Part 5701)
    XLVIII  Nuclear Regulatory Commission (Part 5801)
         L  Department of Transportation (Part 6001)
       LII  Export-Import Bank of the United States (Part 6201)
      LIII  Department of Education (Parts 6300--6399)
       LIV  Environmental Protection Agency (Part 6401)
        LV  National Endowment for the Arts (Part 6501)
       LVI  National Endowment for the Humanities (Part 6601)
      LVII  General Services Administration (Part 6701)
     LVIII  Board of Governors of the Federal Reserve System (Part 
                6801)
       LIX  National Aeronautics and Space Administration (Part 
                6901)
        LX  United States Postal Service (Part 7001)
       LXI  National Labor Relations Board (Part 7101)
      LXII  Equal Employment Opportunity Commission (Part 7201)
     LXIII  Inter-American Foundation (Part 7301)
       LXV  Department of Housing and Urban Development (Part 
                7501)
      LXVI  National Archives and Records Administration (Part 
                7601)
     LXVII  Institute of Museum and Library Services (Part 7701)
      LXIX  Tennessee Valley Authority (Part 7901)
      LXXI  Consumer Product Safety Commission (Part 8101)
    LXXIII  Department of Agriculture (Part 8301)
     LXXIV  Federal Mine Safety and Health Review Commission (Part 
                8401)
     LXXVI  Federal Retirement Thrift Investment Board (Part 8601)

[[Page 585]]

    LXXVII  Office of Management and Budget (Part 8701)
     XCVII  Department of Homeland Security Human Resources 
                Management System (Department of Homeland 
                Security--Office of Personnel Management) (Part 
                9701)
      XCIX  Department of Defense Human Resources Management and 
                Labor Relations Systems (Department of Defense--
                Office of Personnel Management) (Part 9901)

                      Title 6--Homeland Security

         I  Department of Homeland Security, Office of the 
                Secretary (Parts 0--99)

                         Title 7--Agriculture

            Subtitle A--Office of the Secretary of Agriculture 
                (Parts 0--26)
            Subtitle B--Regulations of the Department of 
                Agriculture
         I  Agricultural Marketing Service (Standards, 
                Inspections, Marketing Practices), Department of 
                Agriculture (Parts 27--209)
        II  Food and Nutrition Service, Department of Agriculture 
                (Parts 210--299)
       III  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 300--399)
        IV  Federal Crop Insurance Corporation, Department of 
                Agriculture (Parts 400--499)
         V  Agricultural Research Service, Department of 
                Agriculture (Parts 500--599)
        VI  Natural Resources Conservation Service, Department of 
                Agriculture (Parts 600--699)
       VII  Farm Service Agency, Department of Agriculture (Parts 
                700--799)
      VIII  Grain Inspection, Packers and Stockyards 
                Administration (Federal Grain Inspection Service), 
                Department of Agriculture (Parts 800--899)
        IX  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Fruits, Vegetables, Nuts), Department 
                of Agriculture (Parts 900--999)
         X  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Milk), Department of Agriculture 
                (Parts 1000--1199)
        XI  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Miscellaneous Commodities), Department 
                of Agriculture (Parts 1200--1299)
       XIV  Commodity Credit Corporation, Department of 
                Agriculture (Parts 1400--1499)
        XV  Foreign Agricultural Service, Department of 
                Agriculture (Parts 1500--1599)
       XVI  Rural Telephone Bank, Department of Agriculture (Parts 
                1600--1699)
      XVII  Rural Utilities Service, Department of Agriculture 
                (Parts 1700--1799)

[[Page 586]]

     XVIII  Rural Housing Service, Rural Business-Cooperative 
                Service, Rural Utilities Service, and Farm Service 
                Agency, Department of Agriculture (Parts 1800--
                2099)
        XX  Local Television Loan Guarantee Board (Parts 2200--
                2299)
      XXVI  Office of Inspector General, Department of Agriculture 
                (Parts 2600--2699)
     XXVII  Office of Information Resources Management, Department 
                of Agriculture (Parts 2700--2799)
    XXVIII  Office of Operations, Department of Agriculture (Parts 
                2800--2899)
      XXIX  Office of Energy Policy and New Uses, Department of 
                Agriculture (Parts 2900--2999)
       XXX  Office of the Chief Financial Officer, Department of 
                Agriculture (Parts 3000--3099)
      XXXI  Office of Environmental Quality, Department of 
                Agriculture (Parts 3100--3199)
     XXXII  Office of Procurement and Property Management, 
                Department of Agriculture (Parts 3200--3299)
    XXXIII  Office of Transportation, Department of Agriculture 
                (Parts 3300--3399)
     XXXIV  Cooperative State Research, Education, and Extension 
                Service, Department of Agriculture (Parts 3400--
                3499)
      XXXV  Rural Housing Service, Department of Agriculture 
                (Parts 3500--3599)
     XXXVI  National Agricultural Statistics Service, Department 
                of Agriculture (Parts 3600--3699)
    XXXVII  Economic Research Service, Department of Agriculture 
                (Parts 3700--3799)
   XXXVIII  World Agricultural Outlook Board, Department of 
                Agriculture (Parts 3800--3899)
       XLI  [Reserved]
      XLII  Rural Business-Cooperative Service and Rural Utilities 
                Service, Department of Agriculture (Parts 4200--
                4299)

                    Title 8--Aliens and Nationality

         I  Department of Homeland Security (Immigration and 
                Naturalization) (Parts 1--499)
         V  Executive Office for Immigration Review, Department of 
                Justice (Parts 1000--1399)

                 Title 9--Animals and Animal Products

         I  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 1--199)
        II  Grain Inspection, Packers and Stockyards 
                Administration (Packers and Stockyards Programs), 
                Department of Agriculture (Parts 200--299)
       III  Food Safety and Inspection Service, Department of 
                Agriculture (Parts 300--599)

[[Page 587]]

                           Title 10--Energy

         I  Nuclear Regulatory Commission (Parts 0--199)
        II  Department of Energy (Parts 200--699)
       III  Department of Energy (Parts 700--999)
         X  Department of Energy (General Provisions) (Parts 
                1000--1099)
      XIII  Nuclear Waste Technical Review Board (Parts 1303--
                1399)
      XVII  Defense Nuclear Facilities Safety Board (Parts 1700--
                1799)
     XVIII  Northeast Interstate Low-Level Radioactive Waste 
                Commission (Part 1800)

                      Title 11--Federal Elections

         I  Federal Election Commission (Parts 1--9099)

                      Title 12--Banks and Banking

         I  Comptroller of the Currency, Department of the 
                Treasury (Parts 1--199)
        II  Federal Reserve System (Parts 200--299)
       III  Federal Deposit Insurance Corporation (Parts 300--399)
        IV  Export-Import Bank of the United States (Parts 400--
                499)
         V  Office of Thrift Supervision, Department of the 
                Treasury (Parts 500--599)
        VI  Farm Credit Administration (Parts 600--699)
       VII  National Credit Union Administration (Parts 700--799)
      VIII  Federal Financing Bank (Parts 800--899)
        IX  Federal Housing Finance Board (Parts 900--999)
        XI  Federal Financial Institutions Examination Council 
                (Parts 1100--1199)
       XIV  Farm Credit System Insurance Corporation (Parts 1400--
                1499)
        XV  Department of the Treasury (Parts 1500--1599)
      XVII  Office of Federal Housing Enterprise Oversight, 
                Department of Housing and Urban Development (Parts 
                1700--1799)
     XVIII  Community Development Financial Institutions Fund, 
                Department of the Treasury (Parts 1800--1899)

               Title 13--Business Credit and Assistance

         I  Small Business Administration (Parts 1--199)
       III  Economic Development Administration, Department of 
                Commerce (Parts 300--399)
        IV  Emergency Steel Guarantee Loan Board, Department of 
                Commerce (Parts 400--499)
         V  Emergency Oil and Gas Guaranteed Loan Board, 
                Department of Commerce (Parts 500--599)

[[Page 588]]

                    Title 14--Aeronautics and Space

         I  Federal Aviation Administration, Department of 
                Transportation (Parts 1--199)
        II  Office of the Secretary, Department of Transportation 
                (Aviation Proceedings) (Parts 200--399)
       III  Commercial Space Transportation, Federal Aviation 
                Administration, Department of Transportation 
                (Parts 400--499)
         V  National Aeronautics and Space Administration (Parts 
                1200--1299)
        VI  Air Transportation System Stabilization (Parts 1300--
                1399)

                 Title 15--Commerce and Foreign Trade

            Subtitle A--Office of the Secretary of Commerce (Parts 
                0--29)
            Subtitle B--Regulations Relating to Commerce and 
                Foreign Trade
         I  Bureau of the Census, Department of Commerce (Parts 
                30--199)
        II  National Institute of Standards and Technology, 
                Department of Commerce (Parts 200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  Foreign-Trade Zones Board, Department of Commerce 
                (Parts 400--499)
       VII  Bureau of Industry and Security, Department of 
                Commerce (Parts 700--799)
      VIII  Bureau of Economic Analysis, Department of Commerce 
                (Parts 800--899)
        IX  National Oceanic and Atmospheric Administration, 
                Department of Commerce (Parts 900--999)
        XI  Technology Administration, Department of Commerce 
                (Parts 1100--1199)
      XIII  East-West Foreign Trade Board (Parts 1300--1399)
       XIV  Minority Business Development Agency (Parts 1400--
                1499)
            Subtitle C--Regulations Relating to Foreign Trade 
                Agreements
        XX  Office of the United States Trade Representative 
                (Parts 2000--2099)
            Subtitle D--Regulations Relating to Telecommunications 
                and Information
     XXIII  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                2300--2399)

                    Title 16--Commercial Practices

         I  Federal Trade Commission (Parts 0--999)
        II  Consumer Product Safety Commission (Parts 1000--1799)

[[Page 589]]

             Title 17--Commodity and Securities Exchanges

         I  Commodity Futures Trading Commission (Parts 1--199)
        II  Securities and Exchange Commission (Parts 200--399)
        IV  Department of the Treasury (Parts 400--499)

          Title 18--Conservation of Power and Water Resources

         I  Federal Energy Regulatory Commission, Department of 
                Energy (Parts 1--399)
       III  Delaware River Basin Commission (Parts 400--499)
        VI  Water Resources Council (Parts 700--799)
      VIII  Susquehanna River Basin Commission (Parts 800--899)
      XIII  Tennessee Valley Authority (Parts 1300--1399)

                       Title 19--Customs Duties

         I  Bureau of Customs and Border Protection, Department of 
                Homeland Security; Department of the Treasury 
                (Parts 0--199)
        II  United States International Trade Commission (Parts 
                200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  Bureau of Immigration and Customs Enforcement, 
                Department of Homeland Security (Parts 400--599)

                     Title 20--Employees' Benefits

         I  Office of Workers' Compensation Programs, Department 
                of Labor (Parts 1--199)
        II  Railroad Retirement Board (Parts 200--399)
       III  Social Security Administration (Parts 400--499)
        IV  Employees Compensation Appeals Board, Department of 
                Labor (Parts 500--599)
         V  Employment and Training Administration, Department of 
                Labor (Parts 600--699)
        VI  Employment Standards Administration, Department of 
                Labor (Parts 700--799)
       VII  Benefits Review Board, Department of Labor (Parts 
                800--899)
      VIII  Joint Board for the Enrollment of Actuaries (Parts 
                900--999)
        IX  Office of the Assistant Secretary for Veterans' 
                Employment and Training, Department of Labor 
                (Parts 1000--1099)

                       Title 21--Food and Drugs

         I  Food and Drug Administration, Department of Health and 
                Human Services (Parts 1--1299)
        II  Drug Enforcement Administration, Department of Justice 
                (Parts 1300--1399)
       III  Office of National Drug Control Policy (Parts 1400--
                1499)

[[Page 590]]

                      Title 22--Foreign Relations

         I  Department of State (Parts 1--199)
        II  Agency for International Development (Parts 200--299)
       III  Peace Corps (Parts 300--399)
        IV  International Joint Commission, United States and 
                Canada (Parts 400--499)
         V  Broadcasting Board of Governors (Parts 500--599)
       VII  Overseas Private Investment Corporation (Parts 700--
                799)
        IX  Foreign Service Grievance Board Regulations (Parts 
                900--999)
         X  Inter-American Foundation (Parts 1000--1099)
        XI  International Boundary and Water Commission, United 
                States and Mexico, United States Section (Parts 
                1100--1199)
       XII  United States International Development Cooperation 
                Agency (Parts 1200--1299)
       XIV  Foreign Service Labor Relations Board; Federal Labor 
                Relations Authority; General Counsel of the 
                Federal Labor Relations Authority; and the Foreign 
                Service Impasse Disputes Panel (Parts 1400--1499)
        XV  African Development Foundation (Parts 1500--1599)
       XVI  Japan-United States Friendship Commission (Parts 
                1600--1699)
      XVII  United States Institute of Peace (Parts 1700--1799)

                          Title 23--Highways

         I  Federal Highway Administration, Department of 
                Transportation (Parts 1--999)
        II  National Highway Traffic Safety Administration and 
                Federal Highway Administration, Department of 
                Transportation (Parts 1200--1299)
       III  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 1300--1399)

                Title 24--Housing and Urban Development

            Subtitle A--Office of the Secretary, Department of 
                Housing and Urban Development (Parts 0--99)
            Subtitle B--Regulations Relating to Housing and Urban 
                Development
         I  Office of Assistant Secretary for Equal Opportunity, 
                Department of Housing and Urban Development (Parts 
                100--199)
        II  Office of Assistant Secretary for Housing-Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 200--299)
       III  Government National Mortgage Association, Department 
                of Housing and Urban Development (Parts 300--399)
        IV  Office of Housing and Office of Multifamily Housing 
                Assistance Restructuring, Department of Housing 
                and Urban Development (Parts 400--499)
         V  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 500--599)

[[Page 591]]

        VI  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 600--699) [Reserved]
       VII  Office of the Secretary, Department of Housing and 
                Urban Development (Housing Assistance Programs and 
                Public and Indian Housing Programs) (Parts 700--
                799)
      VIII  Office of the Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Section 8 Housing Assistance 
                Programs, Section 202 Direct Loan Program, Section 
                202 Supportive Housing for the Elderly Program and 
                Section 811 Supportive Housing for Persons With 
                Disabilities Program) (Parts 800--899)
        IX  Office of Assistant Secretary for Public and Indian 
                Housing, Department of Housing and Urban 
                Development (Parts 900--1699)
         X  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Interstate Land Sales 
                Registration Program) (Parts 1700--1799)
       XII  Office of Inspector General, Department of Housing and 
                Urban Development (Parts 2000--2099)
        XX  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 3200--3899)
       XXV  Neighborhood Reinvestment Corporation (Parts 4100--
                4199)

                           Title 25--Indians

         I  Bureau of Indian Affairs, Department of the Interior 
                (Parts 1--299)
        II  Indian Arts and Crafts Board, Department of the 
                Interior (Parts 300--399)
       III  National Indian Gaming Commission, Department of the 
                Interior (Parts 500--599)
        IV  Office of Navajo and Hopi Indian Relocation (Parts 
                700--799)
         V  Bureau of Indian Affairs, Department of the Interior, 
                and Indian Health Service, Department of Health 
                and Human Services (Part 900)
        VI  Office of the Assistant Secretary-Indian Affairs, 
                Department of the Interior (Parts 1000--1199)
       VII  Office of the Special Trustee for American Indians, 
                Department of the Interior (Part 1200)

                      Title 26--Internal Revenue

         I  Internal Revenue Service, Department of the Treasury 
                (Parts 1--899)

           Title 27--Alcohol, Tobacco Products and Firearms

         I  Alcohol and Tobacco Tax and Trade Bureau, Department 
                of the Treasury (Parts 1--399)

[[Page 592]]

        II  Bureau of Alcohol, Tobacco, Firearms, and Explosives, 
                Department of Justice (Parts 400--699)

                   Title 28--Judicial Administration

         I  Department of Justice (Parts 0--299)
       III  Federal Prison Industries, Inc., Department of Justice 
                (Parts 300--399)
         V  Bureau of Prisons, Department of Justice (Parts 500--
                599)
        VI  Offices of Independent Counsel, Department of Justice 
                (Parts 600--699)
       VII  Office of Independent Counsel (Parts 700--799)
      VIII  Court Services and Offender Supervision Agency for the 
                District of Columbia (Parts 800--899)
        IX  National Crime Prevention and Privacy Compact Council 
                (Parts 900--999)
        XI  Department of Justice and Department of State (Parts 
                1100--1199)

                            Title 29--Labor

            Subtitle A--Office of the Secretary of Labor (Parts 
                0--99)
            Subtitle B--Regulations Relating to Labor
         I  National Labor Relations Board (Parts 100--199)
        II  Office of Labor-Management Standards, Department of 
                Labor (Parts 200--299)
       III  National Railroad Adjustment Board (Parts 300--399)
        IV  Office of Labor-Management Standards, Department of 
                Labor (Parts 400--499)
         V  Wage and Hour Division, Department of Labor (Parts 
                500--899)
        IX  Construction Industry Collective Bargaining Commission 
                (Parts 900--999)
         X  National Mediation Board (Parts 1200--1299)
       XII  Federal Mediation and Conciliation Service (Parts 
                1400--1499)
       XIV  Equal Employment Opportunity Commission (Parts 1600--
                1699)
      XVII  Occupational Safety and Health Administration, 
                Department of Labor (Parts 1900--1999)
        XX  Occupational Safety and Health Review Commission 
                (Parts 2200--2499)
       XXV  Employee Benefits Security Administration, Department 
                of Labor (Parts 2500--2599)
     XXVII  Federal Mine Safety and Health Review Commission 
                (Parts 2700--2799)
        XL  Pension Benefit Guaranty Corporation (Parts 4000--
                4999)

[[Page 593]]

                      Title 30--Mineral Resources

         I  Mine Safety and Health Administration, Department of 
                Labor (Parts 1--199)
        II  Minerals Management Service, Department of the 
                Interior (Parts 200--299)
       III  Board of Surface Mining and Reclamation Appeals, 
                Department of the Interior (Parts 300--399)
        IV  Geological Survey, Department of the Interior (Parts 
                400--499)
       VII  Office of Surface Mining Reclamation and Enforcement, 
                Department of the Interior (Parts 700--999)

                 Title 31--Money and Finance: Treasury

            Subtitle A--Office of the Secretary of the Treasury 
                (Parts 0--50)
            Subtitle B--Regulations Relating to Money and Finance
         I  Monetary Offices, Department of the Treasury (Parts 
                51--199)
        II  Fiscal Service, Department of the Treasury (Parts 
                200--399)
        IV  Secret Service, Department of the Treasury (Parts 
                400--499)
         V  Office of Foreign Assets Control, Department of the 
                Treasury (Parts 500--599)
        VI  Bureau of Engraving and Printing, Department of the 
                Treasury (Parts 600--699)
       VII  Federal Law Enforcement Training Center, Department of 
                the Treasury (Parts 700--799)
      VIII  Office of International Investment, Department of the 
                Treasury (Parts 800--899)
        IX  Federal Claims Collection Standards (Department of the 
                Treasury--Department of Justice) (Parts 900--999)

                      Title 32--National Defense

            Subtitle A--Department of Defense
         I  Office of the Secretary of Defense (Parts 1--399)
         V  Department of the Army (Parts 400--699)
        VI  Department of the Navy (Parts 700--799)
       VII  Department of the Air Force (Parts 800--1099)
            Subtitle B--Other Regulations Relating to National 
                Defense
       XII  Defense Logistics Agency (Parts 1200--1299)
       XVI  Selective Service System (Parts 1600--1699)
     XVIII  National Counterintelligence Center (Parts 1800--1899)
       XIX  Central Intelligence Agency (Parts 1900--1999)
        XX  Information Security Oversight Office, National 
                Archives and Records Administration (Parts 2000--
                2099)
       XXI  National Security Council (Parts 2100--2199)
      XXIV  Office of Science and Technology Policy (Parts 2400--
                2499)
     XXVII  Office for Micronesian Status Negotiations (Parts 
                2700--2799)

[[Page 594]]

    XXVIII  Office of the Vice President of the United States 
                (Parts 2800--2899)

               Title 33--Navigation and Navigable Waters

         I  Coast Guard, Department of Homeland Security (Parts 
                1--199)
        II  Corps of Engineers, Department of the Army (Parts 
                200--399)
        IV  Saint Lawrence Seaway Development Corporation, 
                Department of Transportation (Parts 400--499)

                          Title 34--Education

            Subtitle A--Office of the Secretary, Department of 
                Education (Parts 1--99)
            Subtitle B--Regulations of the Offices of the 
                Department of Education
         I  Office for Civil Rights, Department of Education 
                (Parts 100--199)
        II  Office of Elementary and Secondary Education, 
                Department of Education (Parts 200--299)
       III  Office of Special Education and Rehabilitative 
                Services, Department of Education (Parts 300--399)
        IV  Office of Vocational and Adult Education, Department 
                of Education (Parts 400--499)
         V  Office of Bilingual Education and Minority Languages 
                Affairs, Department of Education (Parts 500--599)
        VI  Office of Postsecondary Education, Department of 
                Education (Parts 600--699)
        XI  National Institute for Literacy (Parts 1100--1199)
            Subtitle C--Regulations Relating to Education
       XII  National Council on Disability (Parts 1200--1299)

                         Title 35--[RESERVED]

             Title 36--Parks, Forests, and Public Property

         I  National Park Service, Department of the Interior 
                (Parts 1--199)
        II  Forest Service, Department of Agriculture (Parts 200--
                299)
       III  Corps of Engineers, Department of the Army (Parts 
                300--399)
        IV  American Battle Monuments Commission (Parts 400--499)
         V  Smithsonian Institution (Parts 500--599)
       VII  Library of Congress (Parts 700--799)
      VIII  Advisory Council on Historic Preservation (Parts 800--
                899)
        IX  Pennsylvania Avenue Development Corporation (Parts 
                900--999)
         X  Presidio Trust (Parts 1000--1099)
        XI  Architectural and Transportation Barriers Compliance 
                Board (Parts 1100--1199)
       XII  National Archives and Records Administration (Parts 
                1200--1299)
        XV  Oklahoma City National Memorial Trust (Part 1501)

[[Page 595]]

       XVI  Morris K. Udall Scholarship and Excellence in National 
                Environmental Policy Foundation (Parts 1600--1699)

             Title 37--Patents, Trademarks, and Copyrights

         I  United States Patent and Trademark Office, Department 
                of Commerce (Parts 1--199)
        II  Copyright Office, Library of Congress (Parts 200--299)
       III  Copyright Royalty Board, Library of Congress (Parts 
                301--399)
        IV  Assistant Secretary for Technology Policy, Department 
                of Commerce (Parts 400--499)
         V  Under Secretary for Technology, Department of Commerce 
                (Parts 500--599)

           Title 38--Pensions, Bonuses, and Veterans' Relief

         I  Department of Veterans Affairs (Parts 0--99)

                       Title 39--Postal Service

         I  United States Postal Service (Parts 1--999)
       III  Postal Rate Commission (Parts 3000--3099)

                  Title 40--Protection of Environment

         I  Environmental Protection Agency (Parts 1--1099)
        IV  Environmental Protection Agency and Department of 
                Justice (Parts 1400--1499)
         V  Council on Environmental Quality (Parts 1500--1599)
        VI  Chemical Safety and Hazard Investigation Board (Parts 
                1600--1699)
       VII  Environmental Protection Agency and Department of 
                Defense; Uniform National Discharge Standards for 
                Vessels of the Armed Forces (Parts 1700--1799)

          Title 41--Public Contracts and Property Management

            Subtitle B--Other Provisions Relating to Public 
                Contracts
        50  Public Contracts, Department of Labor (Parts 50-1--50-
                999)
        51  Committee for Purchase From People Who Are Blind or 
                Severely Disabled (Parts 51-1--51-99)
        60  Office of Federal Contract Compliance Programs, Equal 
                Employment Opportunity, Department of Labor (Parts 
                60-1--60-999)
        61  Office of the Assistant Secretary for Veterans' 
                Employment and Training Service, Department of 
                Labor (Parts 61-1--61-999)
            Subtitle C--Federal Property Management Regulations 
                System
       101  Federal Property Management Regulations (Parts 101-1--
                101-99)
       102  Federal Management Regulation (Parts 102-1--102-299)

[[Page 596]]

       105  General Services Administration (Parts 105-1--105-999)
       109  Department of Energy Property Management Regulations 
                (Parts 109-1--109-99)
       114  Department of the Interior (Parts 114-1--114-99)
       115  Environmental Protection Agency (Parts 115-1--115-99)
       128  Department of Justice (Parts 128-1--128-99)
            Subtitle D--Other Provisions Relating to Property 
                Management [Reserved]
            Subtitle E--Federal Information Resources Management 
                Regulations System
       201  Federal Information Resources Management Regulation 
                (Parts 201-1--201-99) [Reserved]
            Subtitle F--Federal Travel Regulation System
       300  General (Parts 300-1--300-99)
       301  Temporary Duty (TDY) Travel Allowances (Parts 301-1--
                301-99)
       302  Relocation Allowances (Parts 302-1--302-99)
       303  Payment of Expenses Connected with the Death of 
                Certain Employees (Part 303-1--303-99)
       304  Payment of Travel Expenses from a Non-Federal Source 
                (Parts 304-1--304-99)

                        Title 42--Public Health

         I  Public Health Service, Department of Health and Human 
                Services (Parts 1--199)
        IV  Centers for Medicare & Medicaid Services, Department 
                of Health and Human Services (Parts 400--499)
         V  Office of Inspector General-Health Care, Department of 
                Health and Human Services (Parts 1000--1999)

                   Title 43--Public Lands: Interior

            Subtitle A--Office of the Secretary of the Interior 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Lands
         I  Bureau of Reclamation, Department of the Interior 
                (Parts 200--499)
        II  Bureau of Land Management, Department of the Interior 
                (Parts 1000--9999)
       III  Utah Reclamation Mitigation and Conservation 
                Commission (Parts 10000--10010)

             Title 44--Emergency Management and Assistance

         I  Federal Emergency Management Agency, Department of 
                Homeland Security (Parts 0--399)
        IV  Department of Commerce and Department of 
                Transportation (Parts 400--499)

[[Page 597]]

                       Title 45--Public Welfare

            Subtitle A--Department of Health and Human Services 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Welfare
        II  Office of Family Assistance (Assistance Programs), 
                Administration for Children and Families, 
                Department of Health and Human Services (Parts 
                200--299)
       III  Office of Child Support Enforcement (Child Support 
                Enforcement Program), Administration for Children 
                and Families, Department of Health and Human 
                Services (Parts 300--399)
        IV  Office of Refugee Resettlement, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 400--499)
         V  Foreign Claims Settlement Commission of the United 
                States, Department of Justice (Parts 500--599)
        VI  National Science Foundation (Parts 600--699)
       VII  Commission on Civil Rights (Parts 700--799)
      VIII  Office of Personnel Management (Parts 800--899)
         X  Office of Community Services, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 1000--1099)
        XI  National Foundation on the Arts and the Humanities 
                (Parts 1100--1199)
       XII  Corporation for National and Community Service (Parts 
                1200--1299)
      XIII  Office of Human Development Services, Department of 
                Health and Human Services (Parts 1300--1399)
       XVI  Legal Services Corporation (Parts 1600--1699)
      XVII  National Commission on Libraries and Information 
                Science (Parts 1700--1799)
     XVIII  Harry S. Truman Scholarship Foundation (Parts 1800--
                1899)
       XXI  Commission on Fine Arts (Parts 2100--2199)
     XXIII  Arctic Research Commission (Part 2301)
      XXIV  James Madison Memorial Fellowship Foundation (Parts 
                2400--2499)
       XXV  Corporation for National and Community Service (Parts 
                2500--2599)

                          Title 46--Shipping

         I  Coast Guard, Department of Homeland Security (Parts 
                1--199)
        II  Maritime Administration, Department of Transportation 
                (Parts 200--399)
       III  Coast Guard (Great Lakes Pilotage), Department of 
                Homeland Security (Parts 400--499)
        IV  Federal Maritime Commission (Parts 500--599)

                      Title 47--Telecommunication

         I  Federal Communications Commission (Parts 0--199)

[[Page 598]]

        II  Office of Science and Technology Policy and National 
                Security Council (Parts 200--299)
       III  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                300--399)

           Title 48--Federal Acquisition Regulations System

         1  Federal Acquisition Regulation (Parts 1--99)
         2  Defense Acquisition Regulations System, Department of 
                Defense (Parts 200--299)
         3  Department of Health and Human Services (Parts 300--
                399)
         4  Department of Agriculture (Parts 400--499)
         5  General Services Administration (Parts 500--599)
         6  Department of State (Parts 600--699)
         7  United States Agency for International Development 
                (Parts 700--799)
         8  Department of Veterans Affairs (Parts 800--899)
         9  Department of Energy (Parts 900--999)
        10  Department of the Treasury (Parts 1000--1099)
        12  Department of Transportation (Parts 1200--1299)
        13  Department of Commerce (Parts 1300--1399)
        14  Department of the Interior (Parts 1400--1499)
        15  Environmental Protection Agency (Parts 1500--1599)
        16  Office of Personnel Management, Federal Employees 
                Health Benefits Acquisition Regulation (Parts 
                1600--1699)
        17  Office of Personnel Management (Parts 1700--1799)
        18  National Aeronautics and Space Administration (Parts 
                1800--1899)
        19  Broadcasting Board of Governors (Parts 1900--1999)
        20  Nuclear Regulatory Commission (Parts 2000--2099)
        21  Office of Personnel Management, Federal Employees' 
                Group Life Insurance Federal Acquisition 
                Regulation (Parts 2100--2199)
        23  Social Security Administration (Parts 2300--2399)
        24  Department of Housing and Urban Development (Parts 
                2400--2499)
        25  National Science Foundation (Parts 2500--2599)
        28  Department of Justice (Parts 2800--2899)
        29  Department of Labor (Parts 2900--2999)
        30  Department of Homeland Security, Homeland Security 
                Acquisition Regulation (HSAR) (Parts 3000--3099)
        34  Department of Education Acquisition Regulation (Parts 
                3400--3499)
        35  [Reserved]
        44  Federal Emergency Management Agency (Parts 4400--4499)
        51  Department of the Army Acquisition Regulations (Parts 
                5100--5199)

[[Page 599]]

        52  Department of the Navy Acquisition Regulations (Parts 
                5200--5299)
        53  Department of the Air Force Federal Acquisition 
                Regulation Supplement (Parts 5300--5399)
        54  Defense Logistics Agency, Department of Defense (Parts 
                5400--5499)
        57  African Development Foundation (Parts 5700--5799)
        61  General Services Administration Board of Contract 
                Appeals (Parts 6100--6199)
        63  Department of Transportation Board of Contract Appeals 
                (Parts 6300--6399)
        99  Cost Accounting Standards Board, Office of Federal 
                Procurement Policy, Office of Management and 
                Budget (Parts 9900--9999)

                       Title 49--Transportation

            Subtitle A--Office of the Secretary of Transportation 
                (Parts 1--99)
            Subtitle B--Other Regulations Relating to 
                Transportation
         I  Pipeline and Hazardous Materials Safety 
                Administration, Department of Transportation 
                (Parts 100--199)
        II  Federal Railroad Administration, Department of 
                Transportation (Parts 200--299)
       III  Federal Motor Carrier Safety Administration, 
                Department of Transportation (Parts 300--399)
        IV  Coast Guard, Department of Homeland Security (Parts 
                400--499)
         V  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 500--599)
        VI  Federal Transit Administration, Department of 
                Transportation (Parts 600--699)
       VII  National Railroad Passenger Corporation (AMTRAK) 
                (Parts 700--799)
      VIII  National Transportation Safety Board (Parts 800--999)
         X  Surface Transportation Board, Department of 
                Transportation (Parts 1000--1399)
        XI  Research and Innovative Technology Administration, 
                Department of Transportation (Parts 1400--1499)
       XII  Transportation Security Administration, Department of 
                Homeland Security (Parts 1500--1699)

                   Title 50--Wildlife and Fisheries

         I  United States Fish and Wildlife Service, Department of 
                the Interior (Parts 1--199)
        II  National Marine Fisheries Service, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 200--299)
       III  International Fishing and Related Activities (Parts 
                300--399)

[[Page 600]]

        IV  Joint Regulations (United States Fish and Wildlife 
                Service, Department of the Interior and National 
                Marine Fisheries Service, National Oceanic and 
                Atmospheric Administration, Department of 
                Commerce); Endangered Species Committee 
                Regulations (Parts 400--499)
         V  Marine Mammal Commission (Parts 500--599)
        VI  Fishery Conservation and Management, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 600--699)

                      CFR Index and Finding Aids

            Subject/Agency Index
            List of Agency Prepared Indexes
            Parallel Tables of Statutory Authorities and Rules
            List of CFR Titles, Chapters, Subchapters, and Parts
            Alphabetical List of Agencies Appearing in the CFR

[[Page 601]]





           Alphabetical List of Agencies Appearing in the CFR




                      (Revised as of July 1, 2006)

                                                  CFR Title, Subtitle or 
                     Agency                               Chapter

Administrative Committee of the Federal Register  1, I
Advanced Research Projects Agency                 32, I
Advisory Council on Historic Preservation         36, VIII
African Development Foundation                    22, XV
  Federal Acquisition Regulation                  48, 57
Agency for International Development, United      22, II
     States
  Federal Acquisition Regulation                  48, 7
Agricultural Marketing Service                    7, I, IX, X, XI
Agricultural Research Service                     7, V
Agriculture Department                            5, LXXIII
  Agricultural Marketing Service                  7, I, IX, X, XI
  Agricultural Research Service                   7, V
  Animal and Plant Health Inspection Service      7, III; 9, I
  Chief Financial Officer, Office of              7, XXX
  Commodity Credit Corporation                    7, XIV
  Cooperative State Research, Education, and      7, XXXIV
       Extension Service
  Economic Research Service                       7, XXXVII
  Energy, Office of                               7, XXIX
  Environmental Quality, Office of                7, XXXI
  Farm Service Agency                             7, VII, XVIII
  Federal Acquisition Regulation                  48, 4
  Federal Crop Insurance Corporation              7, IV
  Food and Nutrition Service                      7, II
  Food Safety and Inspection Service              9, III
  Foreign Agricultural Service                    7, XV
  Forest Service                                  36, II
  Grain Inspection, Packers and Stockyards        7, VIII; 9, II
       Administration
  Information Resources Management, Office of     7, XXVII
  Inspector General, Office of                    7, XXVI
  National Agricultural Library                   7, XLI
  National Agricultural Statistics Service        7, XXXVI
  Natural Resources Conservation Service          7, VI
  Operations, Office of                           7, XXVIII
  Procurement and Property Management, Office of  7, XXXII
  Rural Business-Cooperative Service              7, XVIII, XLII
  Rural Development Administration                7, XLII
  Rural Housing Service                           7, XVIII, XXXV
  Rural Telephone Bank                            7, XVI
  Rural Utilities Service                         7, XVII, XVIII, XLII
  Secretary of Agriculture, Office of             7, Subtitle A
  Transportation, Office of                       7, XXXIII
  World Agricultural Outlook Board                7, XXXVIII
Air Force Department                              32, VII
  Federal Acquisition Regulation Supplement       48, 53
Air Transportation Stabilization Board            14, VI
Alcohol and Tobacco Tax and Trade Bureau          27, I
Alcohol, Tobacco, Firearms, and Explosives,       27, II
     Bureau of
AMTRAK                                            49, VII
American Battle Monuments Commission              36, IV
American Indians, Office of the Special Trustee   25, VII
Animal and Plant Health Inspection Service        7, III; 9, I
Appalachian Regional Commission                   5, IX

[[Page 602]]

Architectural and Transportation Barriers         36, XI
     Compliance Board
Arctic Research Commission                        45, XXIII
Armed Forces Retirement Home                      5, XI
Army Department                                   32, V
  Engineers, Corps of                             33, II; 36, III
  Federal Acquisition Regulation                  48, 51
Benefits Review Board                             20, VII
Bilingual Education and Minority Languages        34, V
     Affairs, Office of
Blind or Severely Disabled, Committee for         41, 51
     Purchase From People Who Are
Broadcasting Board of Governors                   22, V
  Federal Acquisition Regulation                  48, 19
Census Bureau                                     15, I
Centers for Medicare & Medicaid Services          42, IV
Central Intelligence Agency                       32, XIX
Chief Financial Officer, Office of                7, XXX
Child Support Enforcement, Office of              45, III
Children and Families, Administration for         45, II, III, IV, X
Civil Rights, Commission on                       45, VII
Civil Rights, Office for                          34, I
Coast Guard                                       33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage)                46, III
Commerce Department                               44, IV
  Census Bureau                                   15, I
  Economic Affairs, Under Secretary               37, V
  Economic Analysis, Bureau of                    15, VIII
  Economic Development Administration             13, III
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 13
  Fishery Conservation and Management             50, VI
  Foreign-Trade Zones Board                       15, IV
  Industry and Security, Bureau of                15, VII
  International Trade Administration              15, III; 19, III
  National Institute of Standards and Technology  15, II
  National Marine Fisheries Service               50, II, IV, VI
  National Oceanic and Atmospheric                15, IX; 50, II, III, IV, 
       Administration                             VI
  National Telecommunications and Information     15, XXIII; 47, III
       Administration
  National Weather Service                        15, IX
  Patent and Trademark Office, United States      37, I
  Productivity, Technology and Innovation,        37, IV
       Assistant Secretary for
  Secretary of Commerce, Office of                15, Subtitle A
  Technology, Under Secretary for                 37, V
  Technology Administration                       15, XI
  Technology Policy, Assistant Secretary for      37, IV
Commercial Space Transportation                   14, III
Commodity Credit Corporation                      7, XIV
Commodity Futures Trading Commission              5, XLI; 17, I
Community Planning and Development, Office of     24, V, VI
     Assistant Secretary for
Community Services, Office of                     45, X
Comptroller of the Currency                       12, I
Construction Industry Collective Bargaining       29, IX
     Commission
Consumer Product Safety Commission                5, LXXI; 16, II
Cooperative State Research, Education, and        7, XXXIV
     Extension Service
Copyright Office                                  37, II
Copyright Royalty Board                           37, III
Corporation for National and Community Service    45, XII, XXV
Cost Accounting Standards Board                   48, 99
Council on Environmental Quality                  40, V
Court Services and Offender Supervision Agency    28, VIII
     for the District of Columbia
Customs and Border Protection Bureau              19, I
Defense Contract Audit Agency                     32, I
Defense Department                                5, XXVI; 32, Subtitle A; 
                                                  40, VII

[[Page 603]]

  Advanced Research Projects Agency               32, I
  Air Force Department                            32, VII
  Army Department                                 32, V; 33, II; 36, III, 
                                                  48, 51
  Defense Acquisition Regulations System          48, II
  Defense Intelligence Agency                     32, I
  Defense Logistics Agency                        32, I, XII; 48, 54
  Engineers, Corps of                             33, II; 36, III
  National Imagery and Mapping Agency             32, I
  Navy Department                                 32, VI; 48, 52
  Secretary of Defense, Office of                 32, I
Defense Contract Audit Agency                     32, I
Defense Intelligence Agency                       32, I
Defense Logistics Agency                          32, XII; 48, 54
Defense Nuclear Facilities Safety Board           10, XVII
Delaware River Basin Commission                   18, III
District of Columbia, Court Services and          28, VIII
     Offender Supervision Agency for the
Drug Enforcement Administration                   21, II
East-West Foreign Trade Board                     15, XIII
Economic Affairs, Under Secretary                 37, V
Economic Analysis, Bureau of                      15, VIII
Economic Development Administration               13, III
Economic Research Service                         7, XXXVII
Education, Department of                          5, LIII
  Bilingual Education and Minority Languages      34, V
       Affairs, Office of
  Civil Rights, Office for                        34, I
  Educational Research and Improvement, Office    34, VII
       of
  Elementary and Secondary Education, Office of   34, II
  Federal Acquisition Regulation                  48, 34
  Postsecondary Education, Office of              34, VI
  Secretary of Education, Office of               34, Subtitle A
  Special Education and Rehabilitative Services,  34, III
       Office of
  Vocational and Adult Education, Office of       34, IV
Educational Research and Improvement, Office of   34, VII
Elementary and Secondary Education, Office of     34, II
Emergency Oil and Gas Guaranteed Loan Board       13, V
Emergency Steel Guarantee Loan Board              13, IV
Employee Benefits Security Administration         29, XXV
Employees' Compensation Appeals Board             20, IV
Employees Loyalty Board                           5, V
Employment and Training Administration            20, V
Employment Standards Administration               20, VI
Endangered Species Committee                      50, IV
Energy, Department of                             5, XXIII; 10, II, III, X
  Federal Acquisition Regulation                  48, 9
  Federal Energy Regulatory Commission            5, XXIV; 18, I
  Property Management Regulations                 41, 109
Energy, Office of                                 7, XXIX
Engineers, Corps of                               33, II; 36, III
Engraving and Printing, Bureau of                 31, VI
Environmental Protection Agency                   5, LIV; 40, I, IV, VII
  Federal Acquisition Regulation                  48, 15
  Property Management Regulations                 41, 115
Environmental Quality, Office of                  7, XXXI
Equal Employment Opportunity Commission           5, LXII; 29, XIV
Equal Opportunity, Office of Assistant Secretary  24, I
     for
Executive Office of the President                 3, I
  Administration, Office of                       5, XV
  Environmental Quality, Council on               40, V
  Management and Budget, Office of                5, III, LXXVII; 14, VI; 
                                                  48, 99
  National Drug Control Policy, Office of         21, III
  National Security Council                       32, XXI; 47, 2
  Presidential Documents                          3
  Science and Technology Policy, Office of        32, XXIV; 47, II

[[Page 604]]

  Trade Representative, Office of the United      15, XX
       States
Export-Import Bank of the United States           5, LII; 12, IV
Family Assistance, Office of                      45, II
Farm Credit Administration                        5, XXXI; 12, VI
Farm Credit System Insurance Corporation          5, XXX; 12, XIV
Farm Service Agency                               7, VII, XVIII
Federal Acquisition Regulation                    48, 1
Federal Aviation Administration                   14, I
  Commercial Space Transportation                 14, III
Federal Claims Collection Standards               31, IX
Federal Communications Commission                 5, XXIX; 47, I
Federal Contract Compliance Programs, Office of   41, 60
Federal Crop Insurance Corporation                7, IV
Federal Deposit Insurance Corporation             5, XXII; 12, III
Federal Election Commission                       11, I
Federal Emergency Management Agency               44, I
  Federal Acquisition Regulation                  48, 44
Federal Employees Group Life Insurance Federal    48, 21
     Acquisition Regulation
Federal Employees Health Benefits Acquisition     48, 16
     Regulation
Federal Energy Regulatory Commission              5, XXIV; 18, I
Federal Financial Institutions Examination        12, XI
     Council
Federal Financing Bank                            12, VIII
Federal Highway Administration                    23, I, II
Federal Home Loan Mortgage Corporation            1, IV
Federal Housing Enterprise Oversight Office       12, XVII
Federal Housing Finance Board                     12, IX
Federal Labor Relations Authority, and General    5, XIV; 22, XIV
     Counsel of the Federal Labor Relations 
     Authority
Federal Law Enforcement Training Center           31, VII
Federal Management Regulation                     41, 102
Federal Maritime Commission                       46, IV
Federal Mediation and Conciliation Service        29, XII
Federal Mine Safety and Health Review Commission  5, LXXIV; 29, XXVII
Federal Motor Carrier Safety Administration       49, III
Federal Prison Industries, Inc.                   28, III
Federal Procurement Policy Office                 48, 99
Federal Property Management Regulations           41, 101
Federal Railroad Administration                   49, II
Federal Register, Administrative Committee of     1, I
Federal Register, Office of                       1, II
Federal Reserve System                            12, II
  Board of Governors                              5, LVIII
Federal Retirement Thrift Investment Board        5, VI, LXXVI
Federal Service Impasses Panel                    5, XIV
Federal Trade Commission                          5, XLVII; 16, I
Federal Transit Administration                    49, VI
Federal Travel Regulation System                  41, Subtitle F
Fine Arts, Commission on                          45, XXI
Fiscal Service                                    31, II
Fish and Wildlife Service, United States          50, I, IV
Fishery Conservation and Management               50, VI
Food and Drug Administration                      21, I
Food and Nutrition Service                        7, II
Food Safety and Inspection Service                9, III
Foreign Agricultural Service                      7, XV
Foreign Assets Control, Office of                 31, V
Foreign Claims Settlement Commission of the       45, V
     United States
Foreign Service Grievance Board                   22, IX
Foreign Service Impasse Disputes Panel            22, XIV
Foreign Service Labor Relations Board             22, XIV
Foreign-Trade Zones Board                         15, IV
Forest Service                                    36, II
General Services Administration                   5, LVII; 41, 105
  Contract Appeals, Board of                      48, 61
  Federal Acquisition Regulation                  48, 5
  Federal Management Regulation                   41, 102

[[Page 605]]

  Federal Property Management Regulations         41, 101
  Federal Travel Regulation System                41, Subtitle F
  General                                         41, 300
  Payment From a Non-Federal Source for Travel    41, 304
       Expenses
  Payment of Expenses Connected With the Death    41, 303
       of Certain Employees
  Relocation Allowances                           41, 302
  Temporary Duty (TDY) Travel Allowances          41, 301
Geological Survey                                 30, IV
Government Accountability Office                  4, I
Government Ethics, Office of                      5, XVI
Government National Mortgage Association          24, III
Grain Inspection, Packers and Stockyards          7, VIII; 9, II
     Administration
Harry S. Truman Scholarship Foundation            45, XVIII
Health and Human Services, Department of          5, XLV; 45, Subtitle A
  Centers for Medicare & Medicaid Services        42, IV
  Child Support Enforcement, Office of            45, III
  Children and Families, Administration for       45, II, III, IV, X
  Community Services, Office of                   45, X
  Defense Acquisition Regulations System          48, 2
  Family Assistance, Office of                    45, II
  Federal Acquisition Regulation                  48, 3
  Food and Drug Administration                    21, I
  Human Development Services, Office of           45, XIII
  Indian Health Service                           25, V; 42, I
  Inspector General (Health Care), Office of      42, V
  Public Health Service                           42, I
  Refugee Resettlement, Office of                 45, IV
Homeland Security, Department of                  6, I
  Coast Guard                                     33, I; 46, I; 49, IV
  Coast Guard (Great Lakes Pilotage)              46, III
  Customs and Border Protection Bureau            19, I
  Federal Emergency Management Agency             44, I
  Immigration and Customs Enforcement Bureau      19, IV
  Immigration and Naturalization                  8, I
  Transportation Security Administration          49, XII
Housing and Urban Development, Department of      5, LXV; 24, Subtitle B
  Community Planning and Development, Office of   24, V, VI
       Assistant Secretary for
  Equal Opportunity, Office of Assistant          24, I
       Secretary for
  Federal Acquisition Regulation                  48, 24
  Federal Housing Enterprise Oversight, Office    12, XVII
       of
  Government National Mortgage Association        24, III
  Housing--Federal Housing Commissioner, Office   24, II, VIII, X, XX
       of Assistant Secretary for
  Housing, Office of, and Multifamily Housing     24, IV
       Assistance Restructuring, Office of
  Inspector General, Office of                    24, XII
  Public and Indian Housing, Office of Assistant  24, IX
       Secretary for
  Secretary, Office of                            24, Subtitle A, VII
Housing--Federal Housing Commissioner, Office of  24, II, VIII, X, XX
     Assistant Secretary for
Housing, Office of, and Multifamily Housing       24, IV
     Assistance Restructuring, Office of
Human Development Services, Office of             45, XIII
Immigration and Customs Enforcement Bureau        19, IV
Immigration and Naturalization                    8, I
Immigration Review, Executive Office for          8, V
Independent Counsel, Office of                    28, VII
Indian Affairs, Bureau of                         25, I, V
Indian Affairs, Office of the Assistant           25, VI
     Secretary
Indian Arts and Crafts Board                      25, II
Indian Health Service                             25, V; 42, I
Industry and Security, Bureau of                  15, VII
Information Resources Management, Office of       7, XXVII
Information Security Oversight Office, National   32, XX
   Archives and Records Administration
[[Page 606]]

Inspector General
  Agriculture Department                          7, XXVI
  Health and Human Services Department            42, V
  Housing and Urban Development Department        24, XII
Institute of Peace, United States                 22, XVII
Inter-American Foundation                         5, LXIII; 22, X
Interior Department
  American Indians, Office of the Special         25, VII
       Trustee
  Endangered Species Committee                    50, IV
  Federal Acquisition Regulation                  48, 14
  Federal Property Management Regulations System  41, 114
  Fish and Wildlife Service, United States        50, I, IV
  Geological Survey                               30, IV
  Indian Affairs, Bureau of                       25, I, V
  Indian Affairs, Office of the Assistant         25, VI
       Secretary
  Indian Arts and Crafts Board                    25, II
  Land Management, Bureau of                      43, II
  Minerals Management Service                     30, II
  National Indian Gaming Commission               25, III
  National Park Service                           36, I
  Reclamation, Bureau of                          43, I
  Secretary of the Interior, Office of            43, Subtitle A
  Surface Mining and Reclamation Appeals, Board   30, III
       of
  Surface Mining Reclamation and Enforcement,     30, VII
       Office of
Internal Revenue Service                          26, I
International Boundary and Water Commission,      22, XI
     United States and Mexico, United States 
     Section
International Development, United States Agency   22, II
     for
  Federal Acquisition Regulation                  48, 7
International Development Cooperation Agency,     22, XII
     United States
International Fishing and Related Activities      50, III
International Investment, Office of               31, VIII
International Joint Commission, United States     22, IV
     and Canada
International Organizations Employees Loyalty     5, V
     Board
International Trade Administration                15, III; 19, III
International Trade Commission, United States     19, II
Interstate Commerce Commission                    5, XL
James Madison Memorial Fellowship Foundation      45, XXIV
Japan-United States Friendship Commission         22, XVI
Joint Board for the Enrollment of Actuaries       20, VIII
Justice Department                                5, XXVIII; 28, I, XI; 40, 
                                                  IV
  Alcohol, Tobacco, Firearms, and Explosives,     27, II
       Bureau of
  Drug Enforcement Administration                 21, II
  Federal Acquisition Regulation                  48, 28
  Federal Claims Collection Standards             31, IX
  Federal Prison Industries, Inc.                 28, III
  Foreign Claims Settlement Commission of the     45, V
       United States
  Immigration Review, Executive Office for        8, V
  Offices of Independent Counsel                  28, VI
  Prisons, Bureau of                              28, V
  Property Management Regulations                 41, 128
Labor Department                                  5, XLII
  Benefits Review Board                           20, VII
  Employee Benefits Security Administration       29, XXV
  Employees' Compensation Appeals Board           20, IV
  Employment and Training Administration          20, V
  Employment Standards Administration             20, VI
  Federal Acquisition Regulation                  48, 29
  Federal Contract Compliance Programs, Office    41, 60
       of
  Federal Procurement Regulations System          41, 50
  Labor-Management Standards, Office of           29, II, IV
  Mine Safety and Health Administration           30, I
  Occupational Safety and Health Administration   29, XVII
  Public Contracts                                41, 50

[[Page 607]]

  Secretary of Labor, Office of                   29, Subtitle A
  Veterans' Employment and Training Service,      41, 61; 20, IX
       Office of the Assistant Secretary for
  Wage and Hour Division                          29, V
  Workers' Compensation Programs, Office of       20, I
Labor-Management Standards, Office of             29, II, IV
Land Management, Bureau of                        43, II
Legal Services Corporation                        45, XVI
Library of Congress                               36, VII
  Copyright Office                                37, II
  Copyright Royalty Board                         37, III
Local Television Loan Guarantee Board             7, XX
Management and Budget, Office of                  5, III, LXXVII; 14, VI; 
                                                  48, 99
Marine Mammal Commission                          50, V
Maritime Administration                           46, II
Merit Systems Protection Board                    5, II
Micronesian Status Negotiations, Office for       32, XXVII
Mine Safety and Health Administration             30, I
Minerals Management Service                       30, II
Minority Business Development Agency              15, XIV
Miscellaneous Agencies                            1, IV
Monetary Offices                                  31, I
Morris K. Udall Scholarship and Excellence in     36, XVI
     National Environmental Policy Foundation
National Aeronautics and Space Administration     5, LIX; 14, V
  Federal Acquisition Regulation                  48, 18
National Agricultural Library                     7, XLI
National Agricultural Statistics Service          7, XXXVI
National and Community Service, Corporation for   45, XII, XXV
National Archives and Records Administration      5, LXVI; 36, XII
  Information Security Oversight Office           32, XX
National Bureau of Standards                      15, II
National Capital Planning Commission              1, IV
National Commission for Employment Policy         1, IV
National Commission on Libraries and Information  45, XVII
     Science
National Council on Disability                    34, XII
National Counterintelligence Center               32, XVIII
National Credit Union Administration              12, VII
National Crime Prevention and Privacy Compact     28, IX
     Council
National Drug Control Policy, Office of           21, III
National Foundation on the Arts and the           45, XI
     Humanities
National Highway Traffic Safety Administration    23, II, III; 49, V
National Imagery and Mapping Agency               32, I
National Indian Gaming Commission                 25, III
National Institute for Literacy                   34, XI
National Institute of Standards and Technology    15, II
National Labor Relations Board                    5, LXI; 29, I
National Marine Fisheries Service                 50, II, IV, VI
National Mediation Board                          29, X
National Oceanic and Atmospheric Administration   15, IX; 50, II, III, IV, 
                                                  VI
National Park Service                             36, I
National Railroad Adjustment Board                29, III
National Railroad Passenger Corporation (AMTRAK)  49, VII
National Science Foundation                       5, XLIII; 45, VI
  Federal Acquisition Regulation                  48, 25
National Security Council                         32, XXI
National Security Council and Office of Science   47, II
     and Technology Policy
National Telecommunications and Information       15, XXIII; 47, III
     Administration
National Transportation Safety Board              49, VIII
National Weather Service                          15, IX
Natural Resources Conservation Service            7, VI
Navajo and Hopi Indian Relocation, Office of      25, IV
Navy Department                                   32, VI
  Federal Acquisition Regulation                  48, 52

[[Page 608]]

Neighborhood Reinvestment Corporation             24, XXV
Northeast Interstate Low-Level Radioactive Waste  10, XVIII
     Commission
Nuclear Regulatory Commission                     5, XLVIII; 10, I
  Federal Acquisition Regulation                  48, 20
Occupational Safety and Health Administration     29, XVII
Occupational Safety and Health Review Commission  29, XX
Offices of Independent Counsel                    28, VI
Oklahoma City National Memorial Trust             36, XV
Operations Office                                 7, XXVIII
Overseas Private Investment Corporation           5, XXXIII; 22, VII
Patent and Trademark Office, United States        37, I
Payment From a Non-Federal Source for Travel      41, 304
     Expenses
Payment of Expenses Connected With the Death of   41, 303
     Certain Employees
Peace Corps                                       22, III
Pennsylvania Avenue Development Corporation       36, IX
Pension Benefit Guaranty Corporation              29, XL
Personnel Management, Office of                   5, I, XXXV; 45, VIII
  Federal Acquisition Regulation                  48, 17
  Federal Employees Group Life Insurance Federal  48, 21
       Acquisition Regulation
  Federal Employees Health Benefits Acquisition   48, 16
       Regulation
Pipeline and Hazardous Materials Safety           49, I
     Administration
Postal Rate Commission                            5, XLVI; 39, III
Postal Service, United States                     5, LX; 39, I
Postsecondary Education, Office of                34, VI
President's Commission on White House             1, IV
     Fellowships
Presidential Documents                            3
Presidio Trust                                    36, X
Prisons, Bureau of                                28, V
Procurement and Property Management, Office of    7, XXXII
Productivity, Technology and Innovation,          37, IV
     Assistant Secretary
Public Contracts, Department of Labor             41, 50
Public and Indian Housing, Office of Assistant    24, IX
     Secretary for
Public Health Service                             42, I
Railroad Retirement Board                         20, II
Reclamation, Bureau of                            43, I
Refugee Resettlement, Office of                   45, IV
Regional Action Planning Commissions              13, V
Relocation Allowances                             41, 302
Research and Innovative Technology                49, XI
     Administration
Rural Business-Cooperative Service                7, XVIII, XLII
Rural Development Administration                  7, XLII
Rural Housing Service                             7, XVIII, XXXV
Rural Telephone Bank                              7, XVI
Rural Utilities Service                           7, XVII, XVIII, XLII
Saint Lawrence Seaway Development Corporation     33, IV
Science and Technology Policy, Office of          32, XXIV
Science and Technology Policy, Office of, and     47, II
     National Security Council
Secret Service                                    31, IV
Securities and Exchange Commission                17, II
Selective Service System                          32, XVI
Small Business Administration                     13, I
Smithsonian Institution                           36, V
Social Security Administration                    20, III; 48, 23
Soldiers' and Airmen's Home, United States        5, XI
Special Counsel, Office of                        5, VIII
Special Education and Rehabilitative Services,    34, III
     Office of
State Department                                  22, I; 28, XI
  Federal Acquisition Regulation                  48, 6
Surface Mining and Reclamation Appeals, Board of  30, III
Surface Mining Reclamation and Enforcement,       30, VII
     Office of
Surface Transportation Board                      49, X
Susquehanna River Basin Commission                18, VIII

[[Page 609]]

Technology Administration                         15, XI
Technology Policy, Assistant Secretary for        37, IV
Technology, Under Secretary for                   37, V
Tennessee Valley Authority                        5, LXIX; 18, XIII
Thrift Supervision Office, Department of the      12, V
     Treasury
Trade Representative, United States, Office of    15, XX
Transportation, Department of                     5, L
  Commercial Space Transportation                 14, III
  Contract Appeals, Board of                      48, 63
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 12
  Federal Aviation Administration                 14, I
  Federal Highway Administration                  23, I, II
  Federal Motor Carrier Safety Administration     49, III
  Federal Railroad Administration                 49, II
  Federal Transit Administration                  49, VI
  Maritime Administration                         46, II
  National Highway Traffic Safety Administration  23, II, III; 49, V
  Pipeline and Hazardous Materials Safety         49, I
       Administration
  Saint Lawrence Seaway Development Corporation   33, IV
  Secretary of Transportation, Office of          14, II; 49, Subtitle A
  Surface Transportation Board                    49, X
  Transportation Statistics Bureau                49, XI
Transportation, Office of                         7, XXXIII
Transportation Security Administration            49, XII
Transportation Statistics Bureau                  49, XI
Travel Allowances, Temporary Duty (TDY)           41, 301
Treasury Department                               5, XXI; 12, XV; 17, IV; 
                                                  31, IX
  Alcohol and Tobacco Tax and Trade Bureau        27, I
  Community Development Financial Institutions    12, XVIII
       Fund
  Comptroller of the Currency                     12, I
  Customs and Border Protection Bureau            19, I
  Engraving and Printing, Bureau of               31, VI
  Federal Acquisition Regulation                  48, 10
  Federal Law Enforcement Training Center         31, VII
  Fiscal Service                                  31, II
  Foreign Assets Control, Office of               31, V
  Internal Revenue Service                        26, I
  International Investment, Office of             31, VIII
  Monetary Offices                                31, I
  Secret Service                                  31, IV
  Secretary of the Treasury, Office of            31, Subtitle A
  Thrift Supervision, Office of                   12, V
Truman, Harry S. Scholarship Foundation           45, XVIII
United States and Canada, International Joint     22, IV
     Commission
United States and Mexico, International Boundary  22, XI
     and Water Commission, United States Section
Utah Reclamation Mitigation and Conservation      43, III
     Commission
Veterans Affairs Department                       38, I
  Federal Acquisition Regulation                  48, 8
Veterans' Employment and Training Service,        41, 61; 20, IX
     Office of the Assistant Secretary for
Vice President of the United States, Office of    32, XXVIII
Vocational and Adult Education, Office of         34, IV
Wage and Hour Division                            29, V
Water Resources Council                           18, VI
Workers' Compensation Programs, Office of         20, I
World Agricultural Outlook Board                  7, XXXVIII

[[Page 611]]



List of CFR Sections Affected



All changes in this volume of the Code of Federal Regulations that were 
made by documents published in the Federal Register since January 1, 
2001, are enumerated in the following list. Entries indicate the nature 
of the changes effected. Page numbers refer to Federal Register pages. 
The user should consult the entries for chapters and parts as well as 
sections for revisions.
For the period before January 1, 2001, see the ``List of CFR Sections 
Affected, 1949-1963, 1964-1972, 1973-1985, and 1986-2000,rdquo; which is 
published in 11 separate volumes.

                                  2001

40 CFR
                                                                   66 FR
                                                                    Page
Chapter I
Chapter Nomenclature change........................................34375
    Technical corrections..........................................34376
51 State implementation plan determinations........................40609
    Comment period extended........................................47887
51.351 (c) revised.................................................18176
51.352 (c) revised.................................................18177
51.356 (a)(6) added................................................18177
51.357 (a)(5), (12), (b)(1), (4) and (d) introductory text revised
                                                                   18177
51.358 (a)(1) revised..............................................18178
51.366 (a)(2)(xi), (xii), (xiii), (xiv), (xv), (xvi), (xvii) and 
        (xviii) revised............................................18178
51.373 (g) revised.................................................18178

                                  2002

40 CFR
                                                                   67 FR
                                                                    Page
Chapter I
50 Meeting.........................................................11924
50 Appendix H corrected; CFR correction............................11579
51 State implementation plan determinations....3819, 48032, 50600, 62388
    Notice.........................................................10844
    Policy statement...............................................21868
51.1--51.45 (Subpart A) Added......................................39611
51.165 (a)(1)(i), (iv)(A)(1) amended; (a) introductory text, 
        (1)(v)(A), (B), (C)(8), (vi)(A), (C), (E)(2), (4) and 
        revised; (a)(1)(v)(D), (vi)(E)(5) and (G) added............80244
    (a)(1)(xii), (xiii) introductory text, (xviii), (xxv) and (2) 
revised; (a)(1)(i) and (iv)(A)(1) amended; (a)(1)(xxvi) through 
(xlii), (3)(ii)(H), (I), (J), (6), (7), and (c) through (g) added; 
(a)(1)(xxi) removed................................................80245
51.166 (b)(1)(i)(b), (5) and (23)(i) amended; (a)(7), (b)(2)(iv), 
        (3)(vi)(d), (viii), and (38) through (52) added; (i)(4) 
        through (12) redesignated as (i)(1) through (9); (a)(1), 
        (6)(i), (b)(2)(i), (ii), (iii)(h), (3)(i), (iii), (iv), 
        (vi)(b), (c), (7), (8), (13), (21), (31), (i) introductory 
        text and new (i)(5)(i)(g) through (j) revised; (i)(1), (2) 
        and (3) removed............................................80659
    (b)(1)(i)(a), (12), (23)(ii), new (i)(4), (j)(2) and (3) 
amended; (r)(3) through (7) and (t) through (x) added; new 
(i)(5)(i)(k), (l) and (m) removed..................................80260
51.321 Revised.....................................................39615
51.322 Revised.....................................................39615
51.323 Revised.....................................................39616

[[Page 612]]

                                  2003

40 CFR
                                                                   68 FR
                                                                    Page
Chapter I
50 National ambient air quality standards for ozone..................614
50.9 (c) added; eff. 8-25-03.......................................38163
51 Technical correction............................................25684
    Policy statement...............................................44620
51.165 (a)(1)(v)(C)(1) revised; (a)(1)(xliii) through (xlvi) and 
        (h) added..................................................61276
    (a)(1)(vii)(B) and (f)(6) revised; (a)(1)(xxi) added...........63027
51.166 (b)(2)(iii)(a) revised; (b)(53) through (56) and (y) added 
                                                                   61278
    (b)(7)(ii) and (w)(6) revised; (b)(32) added...................63028
51.309 (b)(5), (c), (d)(4)(i) through (iv), (f)(1)(i) and (3) 
        revised; (b)(8) through (13) and (h) added; eff. 8-4-03....33784
    (b)(6) and (d)(5)(i) revised; (d)(ii) and (iii) removed; 
(d)(iv) redesignated as new (d)(ii)................................39846
    (b)(6) and (d)(5)(i) revised; (d)(5)(ii) redesignated as 
(d)(5)(iv); new (d)(5)(ii) and (iii) added.........................61368
    (b)(6) and (d)(5)(i) revised; (d)(5)(ii) and (iii) removed; 
(d)(5)(iv) redesignated as (d)(5)(ii)..............................71014
51 Appendix W revised..............................................18448

                                  2004

40 CFR
                                                                   69 FR
                                                                    Page
Title 40 Nomenclature change.......................................18803
Chapter I
50 Technical correction............................................35526
50.3 Revised.......................................................45595
50.7 Heading and (a) introductory text revised; (a)(1) 
        introductory text, (2), (d) and (e) removed; (a)(1)(i) and 
        (ii) redesignated as (a)(1) and (2)........................45595
50.9 (b) amended...................................................23996
50 Appendix K heading revised......................................45595
    Appendix M removed.............................................45595
    Appendix N amended.............................................45595
51 State implementation plan determinations........................28830
    Technical correction...........................................35526
    Policy statement...............................................40278
    Hearings.......................................................42560
51.100 (s)(1) revised..............................................69298
    (s)(5) added...................................................69304
51.121 (b)(1)(ii), (2)(ii)(B), (C), (D), (E) introductory text, 
        (c), (d)(1), (e)(1) and (2) revised; (e)(3) and (4) 
        redesignated as (e)(4) and (5); (a)(3) and new (e)(3) 
        added; new (e)(4)(i), (ii), (iii), (iv)(A) introductory 
        text, (1), (3), (B) introductory text, (1), (2), (3)(i), 
        (ii) and (iii) revised.....................................21642
51.122 (g)(1) and (2) revised; (g) (3) removed; (g)(4) 
        redesignated as new (g)(3); (h)(1) revised.................21644
51.165 (a)(1)(v)(C)(1), (xliii) through (xlvi) and (h) footnotes 
        added......................................................40275
51.166 (b)(2)(iii)(a), (53) through (56) and (y) footnotes added 
                                                                   40275
51.900--51.916 (Subpart X) Added...................................23996

                                  2005

40 CFR
                                                                   70 FR
                                                                    Page
Chapter I
51 Reconsideration notice..........................................33838
    Actions on petitions...........................................39413
    Technical correction...........................................55212
51.100 (s)(6) added................................................53935
51.121 (r) added...................................................25317
    (s) added......................................................51597
51.122 Revised.....................................................25317
51.123 Added.......................................................25319
51.124 Added.......................................................25328
51.125 Added.......................................................25333
51.165 (a)(1)(iv)(A)(1), (2), (x) and (3)(ii)(C) revised; 
        (a)(1)(iv)(A)(3), (v)(E), (F), (8), (9) and (10) added.....71698
51.166 (c) revised.................................................59618
    (b)(1)(ii), (2)(ii), (49)(i) and (i)(5)(i)(e) Footnote 1 
revised; (b)(23)(i) amended........................................71699
51.286 Added.......................................................59887
51.302 (c)(4)(iii) revised.........................................39156
51.308 (b), (e)(1)(ii), (3) and (4) revised; (c) removed; (e)(5) 
        and (6) added..............................................39156
51.900 (f) introductory text revised; (f)(13) added................30604
51.905 (e)(2)(ii) revised; (e)(2)(iii) added.......................30604
    (c)(1) amended.................................................44474
51.906 Added.......................................................71700

[[Page 613]]

51.908 Heading revised; existing text designated as (d); (a), (b) 
        and (c) added..............................................71700
51.910 Added.......................................................71700
51.912 Added.......................................................71701
51.913 Added.......................................................71701
51.914 Added.......................................................71702
51.915 Added.......................................................71702
51.916 Added.......................................................71702
51.917 Added.......................................................71702
51.918 Added.......................................................71702
51 Appendix Y added................................................39156
    Appendix W revised.............................................68228
    Appendix S amended.............................................71702

                                  2006

   (Regulations published from January 1, 2006, through July 1, 2006)

40 CFR
                                                                   71 FR
                                                                    Page
Chapter I
51 Actions on petitions............................................25304
    State implementation plan determinations........................6347
51.123 (c)(1) and (3) revised; (e)(2) table and (4)(ii) table 
        amended....................................................25301
    (o)(2)(ii)(B), (C) and (cc) amended; (o)(2)(ii)(D), (p) and 
(ee) added.........................................................25370
51.124 (c) revised; (e)(2) table amended...........................25302
    (q) amended; (r) added.........................................25372
51.125 (a)(1) revised..............................................25302
51.351 (c) revised; (i) added......................................17710
51.352 (c) revised; (e) added......................................17711
51.353 (c)(4) revised..............................................17711
51.360 (a)(6) revised..............................................17711
51.372 (b)(1) and (3) removed; (b)(2) revised......................17711
51.373 (b) and (d) revised; (e) removed; (h) added.................17711
51.852 Regulation at 71 FR 17008 withdrawn.........................31093
51.853 Regulation at 71 FR 17008 withdrawn.........................31093
51.852 Amended.....................................................17008
51.853 (b) revised.................................................17008


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