San Luis Obispo County Air Pollution Control District

RULE 429 - OXIDES OF NITROGEN AND CARBON MONOXIDE EMISSIONS FROM ELECTRIC UTILITY BOILERS

(Adopted 11/16/93; Revised 4/26/95 and 11/13/96)

A. APPLICABILITY

The provisions of this Rule shall apply to all electric utility boilers.

B. DEFINITIONS

For the purposes of this Rule, the following definitions shall apply:

  1. "Boiler": An individual piece of combustion equipment fired with liquid or gaseous fuel and used to produce steam.


  2. "Boiler Rating": The rating of a boiler expressed in million British Thermal Units per hour (mmBTU/hr).


  3. "Clock Hour Average Emissions": Emissions based on a one (1) hour average for each clock hour. The one (1) hour average shall be based on ten (10) consecutive six (6) minute periods. All valid data points within each six (6) minute period shall be averaged to determine the value for that period.
  4. "Electric Utility Boilers": A boiler owned and/or operated by a Public Utilities Commission regulated utility.
  5. "Force Majeure Natural Gas Curtailment": An interruption in natural gas service due to one of the following reasons:


a. unforeseeable failure or malfunction, not resulting from an intentional act or omission which the California Public Utilities Commission (CPUC) finds to be due to an act of gross negligence on the part of owner or operator of a boiler; or

b. a natural disaster; or

c. a natural gas curtailment pursuant to CPUC rules or orders; or

d. the serving utility provides notice to the Air Pollution Control Officer (APCO) that, with forecasted supplies and demands, natural gas service is expected to be curtailed pursuant to CPUC rules or orders.

  1. "Oxides of Nitrogen (NOX)": The molecular forms of nitrogen oxide and nitrogen dioxide. When measured or collected, the total of the two molecular forms are collectively expressed as nitrogen dioxide.


  1. "Shut-down Period": The time period during which a unit is reduced below minimum load or below catalytic reaction temperature, if applicable, to a condition where the fires in the boilers are extinguished.


  2. "Start-up": The time period during which a boiler has no fires in it, until the unit that it serves has reached minimum operating load and catalytic reaction temperature, if applicable.


  3. "Steady State Compliance Testing": Testing which is required by the APCO under the authority of the California Health and Safety Code Section 42303 and District Rule 210.B.1 which occurs at or near steady state turbine load.


C. EXEMPTIONS

  1. The emission limitations listed in Subsections D.1 and D.3 below shall not apply during:


a. periods of start-up, not to exceed twelve (12) hours; or

b. periods of shut-down, not to exceed eight (8) hours; or

c. APCO-approved control system calibration and tuning, not to exceed forty-eight (48) hours, following maintenance or overhaul of a boiler or its control system. To qualify for this exemption, the APCO shall receive notice at least forty-eight (48) hours prior to any calibration and tuning or at the beginning of maintenance if it is of an emergency or unforeseen nature.

  1. The provisions of Subsection D.5.a shall not apply for a unit during:


a. force majeure natural gas curtailment; or

b. oil burn readiness testing or CPUC required performance testing not to exceed a total of twenty-four (24) hours annually between May 1 and October 31 and a total of ninety-six (96) hours per year; or

c. oil burn emission testing required by the APCO.

  1. The provisions of Subsection D.1.e shall not apply to a boiler if the owner or operator has a complete application to repower the applicable boiler on file with the lead agency and the lead agency is processing the application or permit request. The limits of D.1.e shall apply two (2) years after the application or permit request has been withdrawn by the applicant or denied by the lead agency. The limits of D.1.e shall apply on December 31, 2006, regardless of the application status.


D. REQUIREMENTS

  1. Oxides of Nitrogen (NOX) Emission Limits


a. Oxides of nitrogen emissions from electric utility boilers rated between 1,500 and 2,000 mmBTU/hr shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis:

    1. operation on natural gas: 150 ppm


    2. operation on fuel oil: 450 ppm


b. Oxides of nitrogen emissions from electric utility boilers rated at 2,000 mmBTU/hr or greater shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis:

    1. operation on natural gas: 125 ppm


    2. operation on fuel oil: 250 ppm

c. Electric utility boilers rated at 2,000 mmBTU/hr or greater shall meet the requirements of either Subsections D.1.c.1 or D.1.c.2 as follows:

    1. Effective June 1, 1996, oxides of nitrogen emissions from all the boilers located at a single stationary source shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis:

i. operation on natural gas: 67 ppm

ii. operation on fuel oil: 250 ppm; or

    1. Effective December 31, 1996, oxides of nitrogen emissions from fifty percent (50%) of all the boilers located at a single stationary source shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis:

i. operation on natural gas: 10 ppm

ii. operation on fuel oil: 25 ppm.

d. Effective December 31, 2000, oxides of nitrogen emissions from all electric utility boilers in the District rated at 2,000 mmBTU/hr or greater shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis:

    1. operation on natural gas: 10 ppm


    2. operation on fuel oil: 25 ppm


e. Effective December 31, 2002, oxides of nitrogen emissions from electric utility boilers rated between 1,500 and 2,000 mmBTU/hr shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis:

    1. operation on natural gas: 30 ppm


    2. operation on fuel oil: 110 ppm


f. Oxides of nitrogen emissions during fuel changes shall not exceed the applicable fuel oil limit. Should the duration of the fuel change exceed twelve (12) hours, then the limit expressed in Subsection D.1.g below shall apply. The APCO must be notified in advance of the fuel change in order to qualify for the fuel oil limit except where force majeure natural gas curtailment conditions preclude advanced notification.

g. Oxides of nitrogen emissions for boilers firing on mixture of oil and gas shall not exceed the following calculated limit:

Where: NOX limit = (OF)(oil NOX limit) + (GF)(gas NOX limit)

OF = Total Heat Input From Oil / Total Heat Input

GF = Total Heat Input From Gas / Total Heat Input

  1. Preferential Operation of Retrofitted Boilers. When two (2) boilers with the same boiler rating and different NOX emission limits are both available for operation during the period between the first and second unit retrofit, the owner or operator of an electric utility shall preferentially operate the boiler with the lowest NOXemission rate such that the operating hours of the lowest emitting boiler shall equal or exceed the operating hours of the higher emitting boiler, provided that such operation shall not impair the provision of reliable electric service.
  2. Carbon Monoxide Emission Limits. Carbon monoxide emissions from electric utility boilers rated above 1,500 mmBTU/hr shall not exceed 1,000 ppm based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis.


  3. Ammonia Emission Limit. Ammonia emissions from control devices installed to meet the requirements of this Rule shall not exceed 10 ppm based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis.


  4. Fuel Oil Usage


a. Except as allowed by Subsection C.2 above, fuel oil and mixtures of fuel oil and natural gas shall not be used as fuel for electric utility boilers during the following periods:

    1. at all times for boilers rated between 1,500 mmBTU/hr and 2,000 mmBTU/hr.


    2. at all times for boilers rated above 2,000 mmBTU/hr that are subject to the emission limits of Subsection D.1.c.1.


    3. from May 1 through October 31 annually for boilers rated above 2,000 mmBTU/hr that are not subject to the emission limits of Subsection D.1.c.1.


b. Operation of a boiler unit on a mixture of oil and gas shall be counted as oil operating hours.

  1. Continuous Emission Monitoring Systems (CEMS)


a. Effective January 1, 1995 for all boilers subject to this Rule, continuous emission monitoring systems which meet the federal requirements referenced below shall be installed, certified, maintained and operated for continuous in-stack monitoring necessary to calculate CO emission rates corrected to three percent (3%) oxygen on a dry basis:

    1. 40 CFR Pt. 60, App. B, Performance Specification 4 -Specifications and Test Procedures for Carbon Monoxide Continuous Emissions Monitoring Systems in Stationary Sources; and


b. Effective January 1, 1995 for all boilers subject to this Rule, continuous emission monitoring systems which meet the federal requirements referenced below shall be installed, certified, maintained and operated for continuous in-stack monitoring necessary to calculate NOX emission rates corrected to three percent (3%) oxygen on a dry basis:

    1. 40 CFR Pt. 60, App. B, Performance Specification 2 -Specifications and Test Procedures for SO2 and NOX Continuous Emissions Monitoring Systems in Stationary Sources; and


    2. 40 CFR Pt. 60, App. B, Performance Specification 3 -Specifications and Test Procedures for O2 and CO2 Continuous Emissions Monitoring Systems in Stationary Sources; and


    3. 40 CFR Pt. 75, Continuous Emission Monitoring and Appendices.


c. Operators of the continuous emission systems (CEMS) must follow the EPA quality assurance procedures referenced below:

    1. 40 CFR Pt. 75, Appendix B to Part 75 - Quality Assurance and Quality Control Procedures; and


    2. 40 CFR Pt. 60, Appendix F - Quality Assurance Procedures, "Procedure 1. Quality Assurance Requirements for Gas Continuous Emission Monitoring Systems Used for Compliance Determination".


d. Calculation of Average Emissions for CEMS

    1. Average emissions shall be calculated as clock hour averages. Conversions shall be calculated according to the procedures within 40 CFR Part 75, Appendix F - "Conversion Procedures".


    2. Data recorded during periods of CEMS breakdown, repairs, calibrations, checks, zero and span adjustments shall not be included in the data averages computed under this section. Missing data shall be estimated according to the procedures of 40 CFR Part 75, Appendix C- "Missing Data Statistical Estimation Procedures".


e. Where 40 CFR Part 60 and Part 75 have conflicting requirements, those requirements contained in Part 75 shall supersede those contained in Part 60.

  1. Interim Emission Reduction Program


a. Not later than December 31, 1995, operators of all electric utility boilers rated at 2,000 mmBTU/hr or greater, with an oxides of nitrogen (NOX) emission compliance date effective after December 31, 1996, shall prepare a draft Interim Emission Reduction Plan (IERP) including one or more options for achieving interim emission reductions, and submit the draft IERP to the APCO for review and approval.

b. Within 120 days of receipt, the APCO shall approve one of the options in the draft IERP, provided it complies with Subsection D.7.c.

c. The approved IERP shall include programs or projects for ozone precursor emission reductions of twenty percent (20%) of the emission reductions that would have occurred had the limits of D.1.d. been in effect as of December 31, 1996. The ozone precursor emission reductions shall be quantifiable and beyond the requirements of the District's existing regulations. The options in the draft IERP shall focus on NOX emissions as a first priority, however the APCO may approve an IERP that reduces emission of other ozone precursors. In no event shall the operator of an affected boiler be required to spend more than $3,600 per ton of interim emission reductions.

d. Within sixty (60) days of a determination by the District or the ARB that the District cannot attain the state ozone standard by January 31, 1997, but no sooner than sixty (60) days after IERP approval, the approved IERP shall be implemented according to the schedule contained within the IERP.



E. RECORDKEEPING REQUIREMENTS

  1. Beginning January 1, 1995 for electric utility boilers subject to this Rule permanent records shall be maintained for a period of four (4) years after creation and shall be made available for inspection by the APCO upon request. The records shall include, but are not limited to:


a. gross and net energy production in megawatt hours (MW-hrs) calculated on a daily basis;

b. quantity of natural gas burned on an hourly basis;

c. quantity of fuel oil burned on an hourly basis or on a federally permitted and accepted alternative;

d. type of fuel oil burned and its sulfur content for each period of operation on fuel oil. Sulfur content shall be determined by methods referenced in 40 CFR Part 75, Appendix D, Subsections 2.2.3 and 2.2.4 or by a federally permitted and accepted alternative;

e. the injection rate of reactant chemicals used for NOXemission reduction on an hourly basis;

f. the CO emissions rate in lb/hr and ppm, corrected to three percent (3%) O2 on dry basis, based on data from the in-stack CEM system on an hourly basis;

g. the NOX emissions rate in lb/hr and ppm, corrected to three percent (3%) O2 on dry basis, based on data from the in-stack CEM system on an hourly basis; and

h. the dates, times and durations of any start-up and shut-down periods.

  1. For CEM systems subject to this Rule, records of all raw and processed emissions data for parameters measured shall be maintained for a period of two (2) years after creation and shall be made available for inspection by the APCO upon request. These records may be kept in an electronic format subject to the APCO's approval. Raw data shall be considered to be uncorrected clock hour averages of measured parameters.


F. TEST METHODS

  1. Steady state compliance testing for oxides of nitrogen emission limits shall be determined by California Air Resources Board Method 100 or EPA Method 7E.


  2. Steady state compliance testing for carbon monoxide emission limits shall be determined by California Air Resources Board Method 100 or EPA Method 10.


  3. Steady state compliance testing for O2 concentrations shall be determined by California Air Resources Board Method 100 or EPA Method 3A.


  4. For steady state compliance testing, the emission limits of Section D shall be based on a sixty (60) consecutive minute average instead of the specified one (1) clock hour average.


  5. A violation of the oxides of nitrogen limits shall be defined as the following which includes error for testing equipment:


a. for steady state compliance testing, when the limit applicable to the unit is exceeded by five percent (5%).

b. for continuous in-stack monitoring, when the limit applicable to the unit is exceeded by ten percent (10%) or 2 ppm whichever is greater.

G. COMPLIANCE SCHEDULE

  1. A compliance plan for any modifications necessary to meet the requirements contained in any of the above sections shall be submitted by November 16, 1994. The compliance plan shall propose actions and alternatives which will be taken to meet or exceed the requirements of this Rule.


a. The plan shall contain, at a minimum:

    1. detailed schedule for submittal of permit applications, construction activities, and planned operation phases.


    2. a list of air pollution control devices and methods which are being considered for each boiler and their respective and cumulative control efficiencies.


SLOAPCD RULE 429 - NOx & CARBON MONOXIDE EMIS. FRM ELEC. UTILITY BOILERS
LAST REVISED 4/26/95

RULE 429. OXIDES OF NITROGEN AND CARBON MONOXIDE EMISSIONS
          FROM ELECTRIC UTILITY BOILERS  (Adopted 11/16/93; Revised
4/26/95)


     A.   APPLICABILITY.  The provisions of this Rule shall apply to
all 
          electric utility boilers.
     
     B.   DEFINITIONS.  For the purposes of this Rule, the following 
          definitions shall apply:
     
          1.   "Boiler":  An individual piece of combustion equipment
fired 
               with liquid or gaseous fuel and used to produce steam.

          2.   "Boiler Rating":  The rating of a boiler expressed in
million 
               British Thermal Units per hour (mmBTU/hr).

          3.   "Clock Hour Average Emissions":  Emissions based on a
one (1) 
               hour average for each clock hour.  The one (1) hour
average 
               shall be based on ten (10) consecutive six (6) minute
periods. 
               All valid data points within each six (6) minute period
shall 
               be averaged to determine the value for that period. 
     
          4.   "Electric Utility Boilers":   A boiler owned and/or
operated 
               by a Public Utilities Commission regulated utility.
     
          5.   "Force Majeure Natural Gas Curtailment":  An
interruption in 
               natural gas service due to one of the following
reasons:

               a.   unforeseeable failure or malfunction, not
resulting from 
                    an intentional act or omission which the
California 
                    Public Utilities Commission (CPUC) finds to be due
to an 
                    act of gross negligence on the part of owner or
operator 
                    of a boiler; or

               b.   a natural disaster; or

               c.   a natural gas curtailment pursuant to CPUC rules
or 
                    orders; or

               d.   the serving utility provides notice to the Air
Pollution 
                    Control Officer (APCO) that, with forecasted
supplies 
                    and demands, natural gas service is expected to be

                    curtailed pursuant to CPUC rules or orders.

          6.   "Oxides of Nitrogen (NOX)":  The molecular forms of
nitrogen 
               oxide and nitrogen dioxide.  When measured or
collected, the 
               total of the two molecular forms are collectively
expressed 
               as nitrogen dioxide.

          7.   "Shut-down Period":  The time period during which a
unit is 
               reduced below minimum load or below catalytic reaction 
               temperature, if applicable, to a condition where the
fires 
               in the boilers are extinguished.

          8.   "Start-up":  The time period during which a boiler has
no 
               fires in it, until the unit that it serves has reached
minimum 
               operating load and catalytic reaction temperature, if 
               applicable.

          9.   "Steady State Compliance Testing":  Testing which is
required 
               by the APCO under the authority of the California
Health and 
               Safety Code Section 42303 and District Rule 210.B.1
which 
               occurs at or near steady state turbine load.

     C.      EXEMPTIONS

          1.   The emission limitations listed in Subsections D.1 and
D.3 
               below shall not apply during:

               a.   periods of start-up, not to exceed twelve (12)
hours; or

               b.   periods of shut-down, not to exceed eight (8)
hours; or

               c.   APCO-approved control system calibration and
tuning, not 
                    to exceed forty-eight (48) hours, following
maintenance 
                    or overhaul of a boiler or its control system. To
qualify 
                    for this exemption, the APCO shall receive notice
at 
                    least forty-eight (48) hours prior to any
calibration and 
                    tuning or at the beginning of maintenance if it is
of an 
                    emergency or unforeseen nature.

          2.   The provisions of Subsection D.5.a shall not apply for
a unit 
               during:

               a.   force majeure natural gas curtailment; or

               b.   oil burn readiness testing or CPUC required
performance 
                    testing not to exceed a total of twenty-four (24)
hours 
                    annually between May 1 and October 31 and a total
of 
                    ninety-six (96) hours per year; or

               c.   oil burn emission testing required by the APCO.

          3.   The provisions of Subsection D.1.e shall not apply to a
boiler 
               if the owner or operator has a complete application to
repower 
               the applicable boiler on file with the lead agency and
the 
               lead agency is processing the application or permit
request.  
               The limits of D.1.e shall apply two (2) years after the

               application or permit request has been withdrawn by the

               applicant or denied by the lead agency.  The limits of
D.1.e 
               shall apply on December 31, 2006, regardless of the 
               application status.

     D.       REQUIREMENTS

          1.   Oxides of Nitrogen (NOX) Emission Limits

               a.   Oxides of nitrogen emissions from electric utility

                    boilers rated between 1,500 and 2,000 mmBTU/hr
shall 
                    not exceed the following limits based on a one (1)
clock 
                    hour average at three percent (3%) oxygen on a dry
basis:

                    1)   operation on natural gas:      150 ppm

                    2)   operation on fuel oil:         450 ppm       

      

               b.   Oxides of nitrogen emissions from electric utility

                    boilers rated at 2,000 mmBTU/hr or greater shall
not 
                    exceed the following limits based on a one (1)
clock 
                    hour average at three percent (3%) oxygen on a dry
basis:
          
                    1)   operation on natural gas:      125 ppm

                    2)   operation on fuel oil:         250 ppm
          
               c.   Electric utility boilers rated at 2,000 mmBTU/hr
or 
                    greater shall meet the requirements of either
Subsections 
                    D.1.c.1 or D.1.c.2 as follows:

                    1)   Effective June 1, 1996, oxides of nitrogen
emissions 
                         from all the boilers located at a single
stationary 
                         source shall not exceed the following limits
based 
                         on a one (1) clock hour average at three
percent 
                         (3%) oxygen on a dry basis:
     
                         i.     operation on natural gas:        67
ppm

                         ii.  operation on fuel oil:             250
ppm; or

                    2)   Effective December 31, 1996, oxides of
nitrogen 
                         emissions from fifty percent (50%) of all the

                         boilers  located at a single stationary
source shall 
                         not exceed the following limits based on a
one (1) 
                         clock hour average at three percent (3%)
oxygen on 
                         a dry basis:
     
                         i.     operation on natural gas:        10
ppm

                         ii.  operation on fuel oil:             25
ppm.

               d.   Effective December 31, 1999, oxides of nitrogen
emissions 
                    from all electric utility boilers in the District
rated 
                    at 2,000 mmBTU/hr or greater shall not exceed the 
                    following limits based on a one (1) clock hour
average at 
                    three percent (3%) oxygen on a dry basis:
     
                    1)     operation on natural gas:        10 ppm

                    2)     operation on fuel oil:           25 ppm

               e.   Effective December 31, 2002, oxides of nitrogen
emissions 
                    from electric utility boilers rated between 1,500
and 
                    2,000 mmBTU/hr shall not exceed the following
limits 
                    based on a one (1) clock hour average at three
percent 
                    (3%) oxygen on a dry basis:

                    1)     operation on natural gas:       30 ppm

                    2)     operation on fuel oil:         110 ppm

               f.   Oxides of nitrogen emissions during fuel changes
shall 
                    not exceed the applicable fuel oil limit. Should
the 
                    duration of the fuel change exceed twelve (12)
hours, 
                    then the limit expressed in Subsection D.1.g below
shall
                    apply. The APCO must be notified in advance of the
fuel 
                    change in order to qualify for the fuel oil limit
except 
                    where force majeure natural gas curtailment
conditions 
                    preclude advanced notification.

               g.   Oxides of nitrogen emissions for boilers firing on

                    mixture of oil and gas shall not exceed the
following 
                    calculated limit:
     
               Where:  NOX limit = (OF)(oil NOX limit) + (GF)(gas NOX
limit)
                              OF = Total Heat Input From Oil / Total
Heat 
                                   Input
                              GF = Total Heat Input From Gas / Total
Heat 
                                   Input

          2.   Preferential Operation of Retrofitted Boilers.  When
two (2) 
               boilers with the same boiler rating and different NOX
emission
               limits are both available for operation during the
period 
               between the first and second unit retrofit, the owner
or 
               operator of an electric utility shall preferentially
operate 
               the boiler with the lowest NOX emission rate such that
the 
               operating hours of the lowest emitting boiler shall
equal or 
               exceed the operating hours of the higher emitting
boiler, 
               provided that such operation shall not impair the
provision 
               of reliable electric service.
     
          3.   Carbon Monoxide Emission Limits.  Carbon monoxide
emissions 
               from electric utility boilers rated above 1,500
mmBTU/hr shall 
               not exceed 1,000 ppm based on a one (1) clock hour
average at 
               three percent (3%) oxygen on a dry basis.

          4.   Ammonia Emission Limit.  Ammonia emissions from control

               devices installed to meet the requirements of this Rule

               shall not exceed 10 ppm based on a one (1) clock hour
average 
               at three percent (3%) oxygen on a dry basis.

          5.   Fuel Oil Usage

               a.   Except as allowed by Subsection C.2 above, fuel
oil and 
                    mixtures of fuel oil and natural gas shall not be
used 
                    as fuel for electric utility boilers during the
following 
                    periods:

                    1)   at all times for boilers rated between 1,500 
                         mmBTU/hr and 2,000 mmBTU/hr.

                    2)   at all times for boilers rated above 2,000
mmBTU/hr 
                         that are subject to the emission limits of 
                         Subsection D.1.c.1.

                    3)   from May 1 through October 31 annually for
boilers 
                         rated above 2,000 mmBTU/hr that are not
subject to 
                         the emission limits of Subsection D.1.c.1.

               b.   Operation of a boiler unit on a mixture of oil and
gas 
                    shall be counted as oil operating hours.          
                    
          6.   Continuous Emission Monitoring Systems (CEMS) 

               a.   Effective January 1, 1995 for all boilers subject
to this 
                    Rule, continuous emission monitoring systems which
meet 
                    the federal requirements referenced below shall be

                    installed, certified, maintained and operated for 
                    continuous in-stack monitoring necessary to
calculate CO 
                    emission rates corrected to three percent (3%)
oxygen on 
                    a dry basis:

                    1)   40 CFR Pt. 60, App. B, Performance
Specification 4 
                         -Specifications and Test Procedures for
Carbon 
                         Monoxide Continuous Emissions Monitoring
Systems 
                         in Stationary Sources; and 

               b.   Effective January 1, 1995 for all boilers subject
to this 
                    Rule, continuous emission monitoring systems which
meet 
                    the federal requirements referenced below shall be

                    installed, certified, maintained and operated for 
                    continuous in-stack monitoring necessary to
calculate NOX 
                    emission rates corrected to three percent (3%)
oxygen on 
                    a dry basis:

                    1)   40 CFR Pt. 60, App. B, Performance
Specification 2 
                         -Specifications and Test Procedures for SO2
and NOX 
                         Continuous Emissions Monitoring Systems in 
                         Stationary Sources; and

                    2)   40 CFR Pt. 60, App. B, Performance
Specification 3 
                         -Specifications and Test Procedures for O2
and CO2 
                         Continuous Emissions Monitoring Systems in 
                         Stationary Sources; and

                    3)   40 CFR Pt. 75, Continuous Emission Monitoring
and 
                         Appendices.

               c.   Operators of the continuous emission systems
(CEMS) must 
                    follow the EPA quality assurance procedures
referenced 
                    below:

                    1)   40 CFR Pt. 75, Appendix B to Part 75 -
Quality 
                         Assurance and Quality Control Procedures; and

                    2)   40 CFR Pt. 60, Appendix F - Quality Assurance

                         Procedures, "Procedure 1. Quality Assurance 
                         Requirements for Gas Continuous Emission
Monitoring 
                         Systems Used for Compliance Determination".

               d.   Calculation of Average Emissions for CEMS

                    1)   Average emissions shall be calculated as
clock hour 
                         averages.  Conversions shall be calculated
according 
                         to the procedures within 40 CFR Part 75,
Appendix F 
                         - "Conversion Procedures".

                    2)   Data recorded during periods of CEMS
breakdown, 
                         repairs, calibrations, checks, zero and span 
                         adjustments shall not be included in the data

                         averages computed under this section. 
Missing data 
                         shall be estimated according to the
procedures of 
                         40 CFR Part 75, Appendix C- "Missing Data 
                         Statistical Estimation Procedures".

               e.   Where 40 CFR Part 60 and Part 75 have conflicting 
                    requirements, those requirements contained in Part
75 
                    shall supersede those contained in Part 60.

          7.   Interim Emission Reduction Program

               a.   Not later than December 31, 1995, operators of all

                    electric utility boilers rated at 2,000 mmBTU/hr
or 
                    greater, with an oxides of nitrogen (NOX) emission

                    compliance date effective after December 31, 1996,
shall 
                    prepare a draft Interim Emission Reduction Plan
(IERP) 
                    including one or more options for achieving
interim 
                    emission reductions, and submit the draft IERP to
the 
                    APCO for review and approval. 

               b.   Within 120 days of receipt, the APCO shall approve
one 
                    of the options in the draft IERP, provided it
complies 
                    with Subsection D.7.c.
 
               c.   The approved IERP shall include programs or
projects for 
                    ozone precursor emission reductions of twenty
percent 
                    (20%) of the emission reductions that would have
occurred 
                    had the limits of D.1.d. been in effect as of
December
                    31, 1996.  The ozone precursor emission reductions
shall 
                    be quantifiable and beyond the requirements of the

                    District's existing regulations.  The options in
the 
                    draft IERP shall focus on NOX emissions as a first

                    priority, however the APCO may approve  an IERP
that 
                    reduces emission of other ozone precursors.  In no
event 
                    shall the operator of an affected boiler be
required to 
                    spend more than $3,600 per ton of interim emission

                    reductions.

               d.   Within sixty (60) days of a determination by the
District 
                    or the ARB that the District cannot attain the
state 
                    ozone standard by January 31, 1997, but no sooner
than 
                    sixty (60) days after IERP approval, the approved
IERP 
                    shall be implemented according to the schedule
contained 
                    within the IERP.  

     E.     RECORDKEEPING REQUIREMENTS

          1.   Beginning January 1, 1995 for electric utility boilers
subject 
               to this Rule permanent records shall be maintained for
a 
               period of four (4) years after creation and shall be
made 
               available for inspection by the APCO upon request. The
records 
               shall include, but are not limited to:

               a.   gross and net energy production in megawatt hours 
                    (MW-hrs) calculated on a daily basis;

               b.   quantity of natural gas burned on an hourly basis;

               c.   quantity of fuel oil burned on an hourly basis or
on a 
                    federally permitted and accepted alternative; 

               d.   type of fuel oil burned and its sulfur content for
each 
                    period of operation on fuel oil. Sulfur content
shall be 
                    determined by methods referenced in 40 CFR Part
75, 
                    Appendix D, Subsections 2.2.3 and 2.2.4 or by a
federally
                    permitted and accepted alternative;

               e.   the injection rate of reactant chemicals used for
NOX 
                    emission reduction on an hourly basis;

               f.   the CO emissions rate in lb/hr and ppm, corrected
to 
                    three percent (3%) O2 on dry basis, based on data
from 
                    the in-stack CEM system on an hourly basis;

               g.   the NOX emissions rate in lb/hr and ppm, corrected
to 
                    three percent (3%) O2 on dry basis, based on data
from 
                    the in-stack CEM system on an hourly basis; and
     
               h.   the dates, times and durations of any start-up and

                    shut-down periods.

          2.   For CEM systems subject to this Rule, records of all
raw and 
               processed emissions data for parameters measured shall
be 
               maintained for a period of two (2) years after creation
and 
               shall be made available for inspection by the APCO upon

               request. These records may be kept in an electronic
format 
               subject to the APCO's approval.  Raw data shall be
considered 
               to be uncorrected clock hour averages of measured
parameters.

     F.     TEST METHODS

          1.   Steady state compliance testing for oxides of nitrogen 
               emission limits shall be determined by California Air 
               Resources Board Method 100 or EPA Method 7E.

          2.   Steady state compliance testing for carbon monoxide
emission 
               limits shall be determined by California Air Resources
Board 
               Method 100 or EPA Method 10.

          3.   Steady state compliance testing for O2 concentrations
shall be 
               determined by California Air Resources Board Method 100
or EPA 
               Method 3A.

          4.   For steady state compliance testing, the emission
limits of 
               Section D shall be based on a sixty (60) consecutive
minute 
               average instead of the specified one (1) clock hour
average. 

          5.   A violation of the oxides of nitrogen limits shall be
defined 
               as the following which includes error for testing
equipment:

               a.   for steady state compliance testing, when the
limit 
                    applicable to the unit is exceeded by five percent
(5%).

               b.   for continuous in-stack monitoring, when the limit

                    applicable to the unit is exceeded by ten percent
(10%) 
                    or 2 ppm whichever is greater.     
                    
     G.     COMPLIANCE SCHEDULE

          1.   A compliance plan for any modifications necessary to
meet the 
               requirements contained in any of the above sections
shall be 
               submitted by November 16, 1994.  The compliance plan
shall 
               propose actions and alternatives which will be taken to
meet 
               or exceed the requirements of this Rule.

               a.   The plan shall contain, at a minimum:

                    1)   detailed schedule for submittal of permit 
                         applications, construction activities, and
planned 
                         operation phases.

                    2)   a list of air pollution control devices and
methods 
                         which are being considered for each boiler
and their 
                         respective and cumulative control
efficiencies.


SLOAPCD RULE 429 NOx & CO EMIS. FROM ELEC. UTIL. BOILERS

LAST REVISED 11/16/93

RULE 429. OXIDES OF NITROGEN AND CARBON MONOXIDE EMISSIONS FROM ELECTRIC UTILITY BOILERS (Adopted 11/16/93)

A. APPLICABILITY The provisions of this rule shall apply to all electric utility boilers.

B. DEFINITIONS: For the purposes of this rule, the following definitions shall apply:

1. Boiler: An individual piece of combustion equipment fired with liquid or gaseous fuel and used to produce steam.

2. Boiler Rating: The rating of a boiler expressed in million British Thermal Units per hour (mmBTU/hr).

3. Clock Hour Average Emissions: Emissions based on a one (1) hour average for each clock hour. The one (1) hour average shall be based on ten (10) consecutive six (6) minute periods. All valid data points within each six (6) minute period shall be averaged to determine the value for that period.

4. Electric Utility Boilers: A boiler owned and/or operated by a Public Utilities Commission regulated utility.

5. Force Majeure Natural Gas Curtailment: An interruption in natural gas service due to one of the following reasons: a. unforeseeable failure or malfunction, not resulting from an intentional act or omission which the California Public Utilities Commission (CPUC) finds to be due to an act of gross negligence on the part of owner or operator of a boiler; or b. a natural disaster; or c. a natural gas curtailment pursuant to CPUC rules or orders; or d. the serving utility provides notice to the Air Pollution Control Officer (APCO) that, with forecasted supplies and demands, natural gas service is expected to be curtailed pursuant to CPUC rules or orders.

6. Oxides of Nitrogen (NOX): The molecular forms of nitrogen oxide and nitrogen dioxide. When measured or collected, the total of the two molecular forms are collectively expressed as nitrogen dioxide.

7. Shut-down Period: The time period during which a unit is reduced below minimum load or below catalytic reaction temperature, if applicable, to a condition where the fires in the boilers are extinguished.

8. Start-up: The time period during which a boiler has no fires in it, until the unit that it serves has reached minimum operating load and catalytic reaction temperature, if applicable.

9. Steady State Compliance Testing: Testing which is required by the APCO under the authority of the California Health and Safety Code Section 42303 and District Rule 210.B.1. which occurs at or near steady state turbine load.

C. EXEMPTIONS

1. The emission limitations listed in Sections D.1. and D.3. below shall not apply during: a. periods of start-up, not to exceed twelve (12) hours; or b. periods of shut-down, not to exceed eight (8) hours; or c. APCO-approved control system calibration and tuning, not to exceed forty-eight (48) hours, following maintenance or overhaul of a boiler or its control system. To qualify for this exemption, the APCO shall receive notice at least forty-eight (48) hours prior to any calibration and tuning or at the beginning of maintenance if it is of an emergency or unforeseen nature.

2. The provisions of Section D.5.a. shall not apply for a unit during: a. force majeure natural gas curtailment; or b. oil burn readiness testing or California Public Utilities Commission (CPUC) required performance testing not to exceed a total of twenty-four (24) hours annually between May 1 and October 31 and a total of ninety-six (96) hours per year; or c. oil burn emission testing required by the APCO.

3. The provisions of section D.1.c. shall not apply to a boiler if the owner or operator has a complete application to repower the applicable boiler on file with the lead agency and the lead agency is processing the application or permit request. The limits of D.1.c. shall apply two (2) years after the application or permit request has been withdrawn by the applicant or denied by the lead agency. The limits of D.1.c. shall apply on December 31, 2006, regardless of the application status.

D. REQUIREMENTS

1. Oxides of Nitrogen (NOX) Emission Limits a. Effective January 1, 1995, oxides of nitrogen emissions from electric utility boilers rated between 1,500 and 2,000 mmBTU/hr shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis: 1) operation on natural gas: 150 ppm 2) operation on fuel oil: 450 ppm b. Effective November 16, 1993 oxides of nitrogen emissions from electric utility boilers rated at 2,000 mmBTU/hr or greater shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis: 1) operation on natural gas: 125 ppm 2) operation on fuel oil: 250 ppm c. Effective December 31, 2002, oxides of nitrogen emissions from electric utility boilers rated between 1,500 and 2,000 mmBTU/hr shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis: 1) operation on natural gas: 30 ppm 2) operation on fuel oil: 110 ppm d. Effective December 31, 1996, oxides of nitrogen emissions from fifty percent (50%) of all the electric utility boilers rated at 2,000 mmBTU/hr or greater located at a single stationary source shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis: 1) operation on natural gas: 10 ppm 2) operation on fuel oil: 25 ppm e. Effective December 31, 1999, oxides of nitrogen emissions from all electric utility boilers in the District rated at 2,000 mmBTU/hr or greater shall not exceed the following limits based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis: 1) operation on natural gas: 10 ppm 2) operation on fuel oil: 25 ppm f. Oxides of nitrogen emissions during fuel changes shall not exceed the applicable fuel oil limit. Should the duration of the fuel change exceed twelve (12) hours, then the limit expressed in Section D.1.g. below shall apply. The APCO must be notified in advance of the fuel change in order to qualify for the fuel oil limit except where force majeure natural gas curtailment conditions preclude advanced notification. g. Oxides of nitrogen emissions for boilers firing on mixture of oil and gas shall not exceed the following calculated limit: Where: NOX limit = (OF)(oil NOX limit) + (GF)(gas NOX limit) OF = Total Heat Input From Oil / Total Heat Input GF = Total Heat Input From Gas / Total Heat Input

2. Preferential Operation of Retrofitted Boilers When two (2) boilers with the same boiler rating and different NOX emission limits are both available for operation during the period between the first and second unit retrofit, the owner or operator of an electric utility shall preferentially operate the boiler with the lowest NOX emission rate such that the operating hours of the lowest emitting boiler shall equal or exceed the operating hours of the higher emitting boiler, provided that such operation shall not impair the provision of reliable electric service.

3. Carbon Monoxide Emission Limits Effective January 1, 1995, carbon monoxide emissions from electric utility boilers rated above 1,500 mmbtu/hr shall not exceed 1,000 ppm based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis.

4. Ammonia Emission Limit Ammonia emissions from control devices installed to meet the requirements of this rule shall not exceed 10 ppm based on a one (1) clock hour average at three percent (3%) oxygen on a dry basis.

5. Fuel Oil Usage a. Effective November 16, 1993 and except as allowed by Section C.2. above, fuel oil and mixtures of fuel oil and natural gas shall not be used as fuel for electric utility boilers during the following periods: 1) at all times for boilers rated between 1,500 mmBTU/hr and 2,000 mmBTU/hr. 2) from May 1 through October 31 annually for boilers rated above 2,000 mmBTU/hr. b. Operation of a boiler unit on a mixture of oil and gas shall be counted as oil operating hours.

6. Continuous Emission Monitoring Systems (CEMS) a. Effective January 1, 1995 for all boilers subject to this rule, continuous emission monitoring systems which meet the federal requirements referenced below shall be installed, certified, maintained and operated for continuous in-stack monitoring necessary to calculate CO emission rates corrected to three percent (3%) oxygen on a dry basis: 1) 40 CFR Pt. 60, App. B, Performance Specification 4 -Specifications and Test Procedures for Carbon Monoxide Continuous Emissions Monitoring Systems in Stationary Sources; and b. Effective January 1, 1995 for all boilers subject to this rule, continuous emission monitoring systems which meet the federal requirements referenced below shall be installed, certified, maintained and operated for continuous in-stack monitoring necessary to calculate NOX emission rates corrected to three percent (3%) oxygen on a dry basis: 1) 40 CFR Pt. 60, App. B, Performance Specification 2 -Specifications and Test Procedures for SO2 and NOX Continuous Emissions Monitoring Systems in Stationary Sources; and 2) 40 CFR Pt. 60, App. B, Performance Specification 3 -Specifications and Test Procedures for O2 and CO2 Continuous Emissions Monitoring Systems in Stationary Sources; and 3) 40 CFR Pt. 75, Continuous Emission Monitoring and Appendices. c. Operators of the continuous emission systems (CEMS) must follow the EPA quality assurance procedures referenced below: 1) 40 CFR Pt. 75, Appendix B to Part 75 - Quality Assurance and Quality Control Procedures; and 2) 40 CFR Pt. 60, Appendix F - Quality Assurance Procedures, "Procedure 1. Quality Assurance Requirements for Gas Continuous Emission Monitoring Systems Used for Compliance Determination". d. Calculation of Average Emissions for CEMS 1) Average emissions shall be calculated as clock hour averages. Conversions shall be calculated according to the procedures within 40 CFR Part 75, Appendix F - "Conversion Procedures". 2) Data recorded during periods of CEMS breakdown, repairs, calibrations, checks, zero and span adjustments shall not be included in the data averages computed under this section. Missing data shall be estimated according to the procedures of 40 CFR Part 75, Appendix C - "Missing Data Statistical Estimation Procedures". e. Where 40 CFR Part 60 and Part 75 have conflicting requirements, those requirements contained in Part 75 shall supersede those contained in Part 60.

7. Interim Emission Reduction Program a. Not later than December 31, 1995, operators of all electric utility boilers rated at 2,000 mmBTU/hr or greater, with an oxides of nitrogen (NOX) emission compliance date effective after December 31, 1996, shall prepare a draft Interim Emission Reduction Plan (IERP) including one or more options for achieving interim emission reductions, and submit the draft IERP to the APCO for review and approval. b. Within 120 days of receipt, the APCO shall approve one of the options in the draft IERP, provided it complies with Section 7.c. c. The approved IERP shall include programs or projects for ozone precursor emission reductions of twenty percent (20%) of the emission reductions that would have occurred had the limits of D.1.e. been in effect as of December 31, 1996. The ozone precursor emission reductions shall be quantifiable and beyond the requirements of the District's existing regulations. The options in the draft IERP shall focus on NOX emissions as a first priority, however the APCO may approve an IERP that reduces emission of other ozone precursors. In no event shall the operator of an affected boiler be required to spend more than $3,600 per ton of interim emission reductions. d. Within sixty (60) days of a determination by the District or the ARB that the District cannot attain the state ozone standard by January 31, 1997, but no sooner than sixty (60) days after IERP approval, the approved IERP shall be implemented according to the schedule contained within the IERP.

E. RECORDKEEPING REQUIREMENTS

1. Beginning January 1, 1995 for electric utility boilers subject to this rule permanent records shall be maintained for a period of four (4) years after creation and shall be made available for inspection by the APCO upon request. The records shall include, but are not limited to: a. gross and net energy production in megawatt hours (MW-hrs) calculated on a daily basis; b. quantity of natural gas burned on an hourly basis; c. quantity of fuel oil burned on an hourly basis or on a federally permitted and accepted alternative; d. type of fuel oil burned and its sulfur content for each period of operation on fuel oil. Sulfur content shall be determined by methods referenced in 40 CFR Part 75, Appendix D, Subsections 2.2.3 and 2.2.4 or by a federally permitted and accepted alternative; e. the injection rate of reactant chemicals used for NOX emission reduction on an hourly basis; f. the CO emissions rate in lb/hr and ppm, corrected to three percent (3%) O2 on dry basis, based on data from the in-stack CEM system on an hourly basis; g. the NOX emissions rate in lb/hr and ppm, corrected to three percent (3%) O2 on dry basis, based on data from the in-stack CEM system on an hourly basis; and h. the dates, times and durations of any start- up and shut-down periods.

2. For CEM systems subject to this rule, records of all raw and processed emissions data for parameters measured shall be maintained for a period of two (2) years after creation and shall be made available for inspection by the APCO upon request. These records may be kept in an electronic format subject to the APCO's approval. Raw data shall be considered to be uncorrected clock hour averages of measured parameters. F. TEST METHODS 1. Steady state compliance testing for oxides of nitrogen emission limits shall be determined by California Air Resources Board Method 100 or EPA Method 7E. 2. Steady state compliance testing for carbon monoxide emission limits shall be determined by California Air Resources Board Method 100 or EPA Method 10.

3. Steady state compliance testing for O2 concentrations shall be determined by California Air Resources Board Method 100 or EPA Method 3A.

4. For steady state compliance testing, the emission limits of Section D shall be based on a sixty (60) consecutive minute average instead of the specified one (1) clock hour average.

5. A violation of the oxides of nitrogen limits shall be defined as the following which includes error for testing equipment: a. for steady state compliance testing, when the limit applicable to the unit is exceeded by five percent (5%). b. for continuous in-stack monitoring, when the limit applicable to the unit is exceeded by ten percent (10%) or 2 ppm whichever is greater.

G. COMPLIANCE SCHEDULE

1. A compliance plan for any modifications necessary to meet the requirements contained in any of the above sections shall be submitted by November 16, 1994. The compliance plan shall propose actions and alternatives which will be taken to meet or exceed the requirements of this rule. a. The Plan shall contain, at a minimum: 1) detailed schedule for submittal of permit applications, construction activities, and planned operation phases. 2) a list of air pollution control devices and methods which are being considered for each boiler and their respective and cumulative control efficiencies.