MBUAPCD RULE 431 EMISSIONS FROM UTILITY BOILERS
LAST REVISED 08/16/95



RULE 431. EMISSIONS FROM UTILITY POWER BOILERS 


[Adopted 9-15-93; Revised 8-16-95]




CONTENTS                            


PART 1  GENERAL. . . . . . . . . . . . . . . . . . . . . . . . . . . . .  2
  1.1   Purpose. . . . . . . . . . . . . . . . . . . . . . . . . . . . .  2
  1.2   Applicability. . . . . . . . . . . . . . . . . . . . . . . . . .  2
  1.3   Exemptions . . . . . . . . . . . . . . . . . . . . . . . . . . .  2
  1.4   Effective Dates. . . . . . . . . . . . . . . . . . . . . . . . .  3
  1.5   References . . . . . . . . . . . . . . . . . . . . . . . . . . .  4

PART 2  DEFINITIONS. . . . . . . . . . . . . . . . . . . . . . . . . . .  4
  2.1   Annual Capacity Factor . . . . . . . . . . . . . . . . . . . . .  4
  2.2   Boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  4
  2.3   Capacity Rating. . . . . . . . . . . . . . . . . . . . . . . . .  4
  2.4   Carbon Monoxide (CO) . . . . . . . . . . . . . . . . . . . . . .  4
  2.5   Clock-hour Average Emissions . . . . . . . . . . . . . . . . . .  5
  2.6   Continuous Emission Monitoring System (CEMS) . . . . . . . . . .  5
  2.7   Emergency Conditions . . . . . . . . . . . . . . . . . . . . . .  5
  2.8   Emissions. . . . . . . . . . . . . . . . . . . . . . . . . . . .  5
  2.9   Force Majeure Natural Gas Curtailment. . . . . . . . . . . . . .  5
  2.10    Fuel Oil System Test Period. . . . . . . . . . . . . . . . . .  6
  2.11    Fuel Switching Period. . . . . . . . . . . . . . . . . . . . .  6
  2.13    Oil Operation Hours. . . . . . . . . . . . . . . . . . . . . .  6
  2.14    Parts-per-million (ppm). . . . . . . . . . . . . . . . . . . .  7
  2.15    Shut-down Period . . . . . . . . . . . . . . . . . . . . . . .  7
  2.16    Start-up Period. . . . . . . . . . . . . . . . . . . . . . . .  7
  2.17    Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  7
  2.18    Utility Power Boiler . . . . . . . . . . . . . . . . . . . . .  7

PART 3  REQUIREMENTS AND STANDARDS . . . . . . . . . . . . . . . . . . .  8
  3.1   Restrictions on the Use of Fuel Oil. . . . . . . . . . . . . . .  8
  3.2   Restrictions on Fuel Oil System Test Periods . . . . . . . . . .  8
  3.3   Restrictions on the Use of Anhydrous Ammonia . . . . . . . . . .  8
  3.4   CO Emission Limits . . . . . . . . . . . . . . . . . . . . . . .  8
  3.5   NH3 Emission Limits. . . . . . . . . . . . . . . . . . . . . . .  9
  3.6   NOx Emission Limits During Fuel Switching Periods. . . . . . . .  9
  3.7   NOx Emission Limits for 750 MW Unit Boilers. . . . . . . . . . .  9
  3.8   NOx Emission Limits for 120 MW Unit Boilers. . . . . . . . . . . 10
  3.9   NOx Emission Limits for 110 MW Unit Boilers. . . . . . . . . . . 11
  3.10    Stationary Source Test Measurements. . . . . . . . . . . . . . 12
  3.11    Continuous Emission Monitoring Systems (CEMSs) . . . . . . . . 13
  3.12    Calculation of Average Emissions . . . . . . . . . . . . . . . 14

PART 4  ADMINISTRATIVE REQUIREMENTS. . . . . . . . . . . . . . . . . . . 15
  4.1   Implementation Plan. . . . . . . . . . . . . . . . . . . . . . . 15
  4.2   Authority to Construct . . . . . . . . . . . . . . . . . . . . . 16
  4.3   Recordkeeping Requirements . . . . . . . . . . . . . . . . . . . 16
  4.4   Requirements for Accelerated Emission Reductions and
        Photochemical Modeling . . . . . . . . . . . . . . . . . . . . . 17




PART 1  GENERAL


1.1   Purpose

      The purpose of this Rule is to provide limitations on
      emissions of nitrogen oxides (NOx) and carbon monoxide (CO)
      during the combustion of natural gas or fuel oil by
      electric power generating steam boilers.


1.2   Applicability

      The provisions of this Rule shall apply to utility power
      boilers owned and/or operated by a California Public
      Utilities Commission (CPUC) regulated utility.  As of
      September 15, 1993, the Moss Landing Power Plant owned and
      operated by the Pacific Gas and Electric Company is the
      sole affected source.


1.3   Exemptions

  1.3.1   The provisions of Subsections 3.1.1 and 3.1.2 of this
          Rule shall not apply if a force majeure natural gas
          curtailment, as defined in Section 2.9 herein, is in
          effect.

  1.3.2   The provisions of Subsections 3.1.1, 3.1.2 and 3.1.3 of
          this Rule shall not apply during a fuel oil system test
          or a District-mandated emissions test.  

  1.3.3   The provisions of Subsections 3.8.4.1 and 3.9.4.1 of
          this Rule shall not apply if the units specified for
          these Subsections are required to operate under
          emergency conditions, as defined in Section 2.7 herein.

  1.3.4   The provisions of Subsections 3.1.3, 3.8.4.2 and
          3.9.4.2  of this Rule shall not apply if both of the
          following conditions are met:

    1.3.4.1   a force majeure natural gas curtailment, as defined
              in Section 2.9 herein, is in effect; and

    1.3.4.2   the units specified in these Subsections are
              required to operate under emergency conditions, as
              defined in Section 2.7 herein. 

  1.3.5   The provisions of Section 3.4, Subsections 3.7.2,
          3.7.3, 3.8.2, 3.8.4, 3.9.2 and 3.9.4 of this Rule shall
          not apply during periods of start-up, as defined in
          Section 2.16 herein, or shut-down, as defined in
          Section 2.15 herein.  

  1.3.6   The provisions of Subsections 3.8.4 and 3.9.4 shall not
          apply if the units specified in these Subsections
          operate at less than a two (2) percent capacity factor
          between May 1 and October 31 annually, and below an
          annual capacity factor of four (4) percent.

  1.3.7   If a 110 MW unit has (1) an average capacity factor of
          no more than 10 percent during the previous 3 calendar
          years and (2) a capacity factor of no more than 20
          percent in each of those calendar years:

    1.3.7.1   the CO emissions concentration may be determined
              using 40 Code of Federal Regulations (CFR) Part 60,
              App. A, Method 10 (EPA Method 10, "Determination of
              Carbon Monoxide Emissions from Stationary
              Sources"), rather than by CEMS as required by
              Subsection 3.11.4 herein; and

    1.3.7.2   the NOx emissions concentrations may be measured
              and recorded using one of the methods provided
              under 40 CFR Part 75.12(c) "Specific Provisions for
              Monitoring NOx Emissions (NOx and Diluent Gas
              Monitors:  Gas-fired Peaking Units or Oil-fired
              Peaking Units"), rather than by CEMS as required by
              Subsection 3.11.5 herein. 


1.4   Effective Dates

      This Rule, as most recently revised on August 16, 1995, is
      effective August 16, 1995.  Specific dates for attainment
      of reduced emissions levels are provided in relevant
      sections of Part 3 of this Rule.

1.5   References

      The requirements of this Rule arise from the provisions of
      the California Clean Air Act and amendments (Health and
      Safety Code Section 40910 et seq.) and from the
      requirements of Section 182(f) of the Federal Clean Air Act
      as amended (Title 42 United States Code Section 7401 et
      seq.)



PART 2  DEFINITIONS


2.1   Annual Capacity Factor

      The cumulative amount of steam generated during the most
      recent annual period for an individual unit expressed as a
      percent of the maximum possible steam generation for the
      unit.


2.2   Boiler

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

      The relationships between nominal capacity ratings,
      turbine-generators and utility power boilers at the Pacific
      Gas and Electric Company owned and operated Moss Landing
      Power Plant are as follows:

      Unit Capacity       Turbine-Generator
      Rating (MW)       Unit Numbers        Boiler Numbers
        110             1 through 3         1 through 6
        120             4 and 5             7 and 8
        750             6 and 7             6-1 and 7-1


2.3   Capacity Rating

      The electrical power output rating for a power generating
      unit, expressed in Megawatts (MW).  


2.4   Carbon Monoxide (CO)

      The molecular species, carbon monoxide.

2.5   Clock-hour Average Emissions

      Emissions based on a one-hour average computed from data
      points equally spaced over each clock-hour period.  

  2.5.1   For each CEMS associated with any 750 MW unit boiler
          subject to this Rule, the data shall be collected at a
          frequency of at least 10 data points per clock-hour.

  2.5.2   For each CEMS associated with any 120 or 110 MW unit
          boiler subject to this Rule, the data shall be
          collected at a frequency of at least 4 data points per
          clock-hour.


2.6   Continuous Emission Monitoring System (CEMS)

      The total equipment required for the continuous
      determination and recordkeeping of a gas concentration or
      emission rate.


2.7   Emergency Conditions

      When a utility facility is required to request or provide
      emergency support, as defined in Item 6 of the Coordinated
      Bulk Power Supply Program, Western Systems Coordinating
      Council (April, 1990).

  2.7.1   For the purposes of this Rule, this definition is
          limited to those situations in which the specified
          procedures for requesting emergency relief have been
          followed, including utility determination that normal
          arrangements for capacity and energy are not sufficient
          to meet a system's requirements, and the next relief
          measure for either the requesting or responding utility
          is reduction of firm load. 

 2.8    Emissions

      The rate of quantitative releases to the atmosphere from an
      emission point as measured by the continuous emission
      monitoring system (CEMS) and calculated by the methods
      specified in the Permit to Operate.


2.9   Force Majeure Natural Gas Curtailment

      An interruption in natural gas service, such that the daily
      fuel needs of a boiler cannot be met with the natural gas
      available, due to one of the following reasons:

  2.9.1   an 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 the
          owner or operator of a boiler; or 
  
  2.9.2   a natural disaster; or

  2.9.3   natural gas service is curtailed pursuant to CPUC rules
          or orders; or 

  2.9.4   the serving utility provides notice to the District
          that, with forecasted supplies and demands, natural gas
          service is expected to be curtailed pursuant to CPUC
          rules or orders.


2.10    Fuel Oil System Test Period   

      The period of time during which a boiler system is operated
      on fuel oil for the purpose of testing the ability to
      operate on fuel oil, or to conduct a CPUC-required
      performance test.
    

2.11    Fuel Switching Period

      The time period during which fuel type (gaseous or liquid)
      is gradually being changed from one type to another, and as
      a consequence, a mixture of fuel types is being used.


2.12    Nitrogen Oxides (NOx)

      The sum of the molecular forms of nitrogen oxide and
      nitrogen dioxide in stack gas.  When measured or
      calculated, the total of the two molecular forms are
      collectively expressed as nitrogen dioxide.  


2.13    Oil Operation Hours

  2.13.1    Operation of a boiler on fuel oil or a mixture of
            fuel oil and natural gas shall be counted as oil
            operating hours.

  2.13.2    Operation of a boiler on fuel oil during District-
            mandated source testing shall not be counted as oil
            operating hours.


2.14    Parts-per-million (ppm)

      Parts-per-million by volume.


2.15    Shut-down Period

    2.15.1    For those units without catalytic emissions
              reduction equipment, the time period during which a
              unit is reduced below minimum load, to a condition
              where the fires in the boiler(s) are extinguished,
              not to exceed eight (8) hours.

    2.15.2    For those units with catalytic emissions reduction
              equipment, the time period during which a unit is
              reduced below minimum load or catalytic reduction
              temperature, to a condition where the fires in the
              boiler are extinguished, not to exceed eight (8)
              hours.


2.16    Start-up Period

    2.16.1    For those units without catalytic emissions
              reduction equipment, the time period during which a
              boiler has no fires in it, until the unit that it
              serves has reached minimum operating load, not to
              exceed twelve (12) hours.  

    2.16.2    For those units with catalytic emissions reduction
              equipment, the time period during which a boiler
              has no fires in it, until the unit that it serves
              has reached minimum operating load, the catalytic
              reaction temperature and main breaker closure.


2.17    Unit

      In reference to electric power generating equipment, an
      electric power generating system consisting of at least one
      boiler and one turbine-generator.


2.18    Utility Power Boiler

      A utility-owned and/or operated electric power generating
      steam boiler.



PART 3  REQUIREMENTS AND STANDARDS


3.1   Restrictions on the Use of Fuel Oil

  3.1.1   Effective May 1, 1994, oil and mixtures of oil and
          natural gas shall not be used as fuel for utility power
          boilers providing steam for power generation to the 750
          MW units during the period of May 1 through October 31
          annually.  

  3.1.2   When the 750 MW units are subject to the limits in
          Subsection 3.7.2.2, oil and mixtures of oil and natural
          gas shall not be used as fuel for utility power boilers
          providing steam for power generation to the 750 MW
          units.

  3.1.3   Effective May 1, 1994, oil and mixtures of oil and
          natural gas shall not be used as fuel for utility power
          boilers providing steam for power generation to the 110
          MW or 120 MW units.


3.2   Restrictions on Fuel Oil System Test Periods

      Fuel oil system test periods for any boiler shall not
      exceed a total of 24 hours between May 1 and October 31
      annually, or 96 hours per year for any boiler.


3.3   Restrictions on the Use of Anhydrous Ammonia

      Anhydrous ammonia shall not be used as the feed-stock in
      NOx emission control systems for boilers regulated under
      the provisions of this Rule, unless environmental, health
      and safety concerns have been mitigated to the satisfaction
      of the Air Pollution Control Officer.


3.4   CO Emission Limits

      Effective December 31, 1994 for the 110 MW unit boilers and
      120 MW unit boilers, December 31, 1995 for one 750 MW unit
      boiler, and December 31, 1996 for the second 750 MW unit
      boiler, carbon monoxide (CO) emissions from any utility
      power boiler providing steam for power generation shall not
      exceed the following limits:

  3.4.1   during steady-state compliance tests:  400 ppm, based
          upon a 60-consecutive minute average;

  3.4.2   during normal operations:  1000 ppm, based on a one (1)
          hour clock-hour average at three (3) percent oxygen on
          a dry basis.


3.5   NH3 Emission Limits

  3.5.1   NH3 emissions from any emission control device
          installed and operated pursuant to the requirements of
          this Rule shall not exceed 10 ppm, based upon a 60-
          consecutive minute average.

  3.5.2   A monthly source test using the methods referenced in
          Subsection 3.10.3 herein shall be performed to
          determine compliance with this limit and reported to
          the District monthly, or less frequently if deemed
          appropriate by the Air Pollution Control Officer.


3.6   NOx Emission Limits During Fuel Switching Periods

      The NOx emission limits during the first six (6) hours of a
      fuel switching period shall be the applicable fuel oil
      emission limit.  The NOx emission limit after the first six
      (6) hours in a fuel switching period is expressed as
      follows:  

  3.6.1   NOx limit = [(f1)(N1)] + [(f2)(N2)], where:

        f1 = (total heat input from oil)/(total heat input)

        f2 = (total heat input from natural gas)/(total heat input)

        N1 = oil NOx limit

        N2 = natural gas NOx limit

    
3.7   NOx Emission Limits for 750 MW Unit Boilers

  3.7.1   Prior to the effective date in Subsection 3.7.2 herein,
          the emissions of nitrogen oxides from the utility power
          boilers providing steam for power generation to the 750
          MW units shall not exceed the following limits based on
          a one (1) hour average at three (3) percent oxygen (O2)
          on a dry basis:

    3.7.1.1   during operation on natural gas:  225 ppm;

    3.7.1.2   during operation on fuel oil:  225 ppm.

  3.7.2   Effective December 31, 1996, emissions of nitrogen
          oxides from the utility power boilers providing steam
          for power generation to the 750 MW units shall not
          exceed the following limits based on a one (1) hour
          average at three (3) percent oxygen (O2) on a dry
          basis:

    3.7.2.1   during operation on natural gas:  90 ppm above 400
              gross MW;  450 lb/hr at or below 400 gross MW.

    3.7.2.2   during operation on fuel oil:  225 ppm.

    3.7.2.3   During the period from May 1 through October 31
              each year, the total NOx emissions from all units
              shall not exceed an average of 9.64 tons per day.

  3.7.3   Effective December 31, 2000 for one unit, and December
          31, 2001 for the second unit, emissions of nitrogen
          oxides from the utility power boilers providing steam
          for power generation to the 750 MW units shall not
          exceed the following limits based on a one (1) hour
          average at three (3) percent oxygen (O2) on a dry
          basis:

    3.7.3.1   during operation on natural gas:  10 ppm;

    3.7.3.2   during operation on fuel oil:  25 ppm.

  3.7.4   Any time the two 750 MW units are subject to different
          NOx emission limits under this Rule, when both units
          are available, the owner or operator shall
          preferentially operate the  unit subject to the lower
          emission limit, such that its MW-hours equal or exceed
          the MW-hours of the  unit subject to the higher
          emission limit, provided that such preferential
          operation shall not impair the provision of reliable
          electric service.

  3.7.5   Effective August 16, 1995, in addition to any
          applicable one hour average emission limits, the
          maximum allowable average nitrogen oxide emissions from
          all units at a contiguous site shall not exceed 0.30
          pounds of NOx per million Btu.

    3.7.5.1   Compliance with the 0.30 pounds of NOx per million
              Btu limit may be determined on a continuous basis
              through the use of a 30-day rolling average
              emission rate, calculated each operating day as the
              average of all hourly data for the preceding 30
              operating days.


3.8   NOx Emission Limits for 120 MW Unit Boilers

  3.8.1   Prior to the effective date in Subsection 3.8.2 herein,
          the emissions of nitrogen oxides from the utility power
          boilers providing steam for power generation to the 120
          MW units shall not exceed the following limits based on
          a one (1) hour average at three (3) percent oxygen (O2)
          on a dry basis:

    3.8.1.1   during operation on natural gas:  200 ppm;

    3.8.1.2   during operation on fuel oil:  500 ppm.

  3.8.2   Effective December 31, 1994, emissions of nitrogen
          oxides from utility power boilers providing steam for
          power generation to the 120 MW units shall not exceed
          the following limits based on a one (1) hour average at
          three (3) percent oxygen (O2) on a dry basis:

    3.8.2.1   during operation on natural gas:  90 ppm;

    3.8.2.2   during operation on fuel oil:  500 ppm.  

  3.8.3   Effective December 31, 1994, in addition to any
          applicable one hour average emission limits, the
          maximum allowable average nitrogen oxide emissions from
          all units at a contiguous site shall not exceed 0.30
          pounds of NOx per million Btu.

    3.8.3.1   Compliance with the 0.30 pounds of NOx per million
              Btu limit may be determined on a continuous basis
              through the use of a 30-day rolling average
              emission rate, calculated each operating day as the
              average of all hourly data for the preceding 30
              operating days.

  3.8.4   Effective December 31, 1999, emissions of nitrogen
          oxides from utility power boilers providing steam for
          power generation to the 120 MW units shall not exceed
          the following limits based on a one (1) hour average at
          three (3) percent oxygen (O2) on a dry basis:

    3.8.4.1   during operation on natural gas:  30 ppm;

    3.8.4.2   during operation on fuel oil:  110 ppm.  


3.9   NOx Emission Limits for 110 MW Unit Boilers

  3.9.1   Prior to the effective date in Subsection 3.9.2 herein,
          the emissions of nitrogen oxides from the utility power
          boilers providing steam for power generation to the 110
          MW units shall not exceed the following limits based on
          a one (1) hour average at three (3) percent oxygen (O2)
          on a dry basis:

    3.9.1.1   during operation on natural gas:  150 ppm;

    3.9.1.2   during operation on fuel oil:  500 ppm.

  3.9.2   Effective December 31, 1993, emissions of nitrogen
          oxides from utility power boilers providing steam for
          power generation to the 110 MW units shall not exceed
          the following limits based on a one (1) hour average at
          three (3) percent oxygen (O2) on a dry basis:

    3.9.2.1   during operation on natural gas:  125 ppm;

    3.9.2.2   during operation on fuel oil:  500 ppm.  

  3.9.3   Effective December 31, 1994, in addition to any
          applicable one hour average emission limits, the
          maximum allowable average nitrogen oxide emissions from
          all units at a contiguous site shall not exceed 0.30
          pounds of NOx per million Btu.

    3.9.3.1   Compliance with the 0.30 pounds of NOx per million
              Btu limit may be determined on a continuous basis
              through the use of a 30-day rolling average
              emission rate, calculated each operating day as the
              average of all hourly data for the preceding 30
              operating days.

  3.9.4   Effective December 31, 1999, emissions of nitrogen
          oxides from utility power boilers providing steam for
          power generation to the 110 MW units shall not exceed
          the following limits based on a one (1) hour average at
          three (3) percent oxygen (O2) on a dry basis:

    3.9.4.1   during operation on natural gas:  30 ppm;

    3.9.4.2   during operation on fuel oil:  110 ppm.  


3.10    Stationary Source Test Measurements

  3.10.1    For any boiler subject to this Rule which does not
            have a CEMS installed and certified to determine
            emission rates, quarterly stationary source testing
            shall be required to determine compliance with the
            emission limits of this Rule for any such boiler
            which operated during the quarter.  Quarterly reports
            containing the results of these stationary tests will
            be submitted to the District within 45 days of the
            end of each calendar quarter.

  3.10.2    For determination of CO emissions concentrations in
            stack gases during stationary source tests, 40 CFR
            Part 60, App. A, Method 10 (EPA Method 10,
            "Determination of Carbon Monoxide Emissions from
            Stationary Sources") or California Air Resources
            Board (ARB) Method 100, "Procedures for Continuous
            Gaseous Emission Stack Sampling" shall be performed.

  3.10.3    For determination of NH3 concentrations in stack
            gases during stationary source tests of controlled
            equipment which use NH3 as a reagent, Bay Area Air
            Quality Management District (BAAQMD) Source Test
            Procedure ST-1B, "Ammonia, Integrated Sampling" and
            EPA Method 350.3, "Ion Specific Electrode", shall be
            performed.  Alternate methods may not be used without
            prior approval of the Air Pollution Control Officer
            and, if necessary, the California Air Resources Board
            and United States Environmental Protection Agency.

  3.10.4    For determination of NOx emissions concentrations in
            stack gases during stationary source tests, 40 CFR
            Part 60, App. A, Method 7E (EPA Method 7E,
            "Determination of Nitrogen Oxides Emissions from
            Stationary Sources (Instrumental Analyzer
            Procedure)") or ARB Method 100, "Procedures for
            Continuous Gaseous Emission Stack Sampling", shall be
            performed.

  3.10.5    For determination of O2 concentrations in stack gases
            during stationary source tests, 40 CFR Part 60, App.
            A, Method 3A (EPA Method 3A, "Determination of O2 and
            CO2 Concentrations in Emissions from Stationary
            Sources (Instrumental Analyzer Procedure)") or ARB
            Method 100, "Procedures for Continuous Gaseous
            Emission Stack Sampling" shall be performed.

  3.10.6    All stationary source testing shall be performed in
            compliance with the District Source Testing
            Procedures Manual.


3.11    Continuous Emission Monitoring Systems (CEMSs)

  3.11.1    Each CEMS associated with a 750 MW unit boiler
            subject to this Rule shall complete a minimum of one
            cycle of operation (sampling, analyzing and data
            recording) for each successive 6-minute period.  

  3.11.2    Each CEMS associated with a 120 or 110 MW unit boiler
            subject to this Rule shall complete a minimum of one
            cycle of operation (sampling, analyzing and data
            recording) for each successive 15-minute period.

  3.11.3    CEMS electronic data files shall be made available in
            a District-approved format compatible with electronic
            data transfer.

  3.11.4    Effective December 31, 1994 for all boilers subject
            to this Rule, continuous emission monitoring systems
            (CEMSs) 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 (3) percent oxygen on a dry basis:

    3.11.4.1    40 CFR Part 60, App. B, Spec. 4 (EPA Performance
                Specification 4, "Specifications and Test
                Procedures for Carbon Monoxide Continuous
                Emission Monitoring Systems in Stationary
                Sources"); and

    3.11.4.2    40 CFR Part 60, App. B, Spec. 3 (EPA Performance
                Specification 3, "Specifications and Test
                Procedures for O2 and CO2 Continuous Emission
                Monitoring Systems in Stationary Sources").

  3.11.5    Effective December 31, 1994 for all boilers subject
            to this Rule, continuous emission monitoring systems
            (CEMSs) 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 (3) percent oxygen on a dry basis:

    3.11.5.1    40 CFR Part 75 and Appendices (Continuous
                Emission Monitoring);

    3.11.5.2    40 CFR Part 60, App. B, Spec. 2 (EPA Performance
                Specification 2, "Specifications and Test
                Procedures for SO2 and NOx Continuous Emission
                Monitoring Systems in Stationary Sources"); and

    3.11.5.3    40 CFR Part 60, App. B, Spec. 3 (EPA Performance
                Specification 3, "Specifications and Test
                Procedures for O2 and CO2 Continuous Emission
                Monitoring Systems in Stationary Sources").

  3.11.6    Operators of the continuous emission monitoring
            systems (CEMSs) must follow the EPA quality assurance
            procedures referenced below:

    3.11.6.1    40 CFR Part 75, App. B (Appendix B to Part 75 -
                Quality Assurance and Quality Control
                Procedures); and

    3.11.6.2    40 CFR Part 60, App. F (Appendix F to Part 60 -
                Quality Assurance Procedures "Procedure 1. 
                Quality Assurance Requirements for Gas Continuous
                Emission Monitoring Systems Used for Compliance
                Determination").


3.12    Calculation of Average Emissions

  3.12.1    For CEMSs, average emissions shall be calculated as
            clock-hour averages.  Conversions shall be calculated
            according to the procedures within 40 CFR Part 75,
            App. F (Appendix F to Part 75 - Conversion
            Procedures).

  3.12.2    For steady state compliance testing required by
            Subsections 3.10.1, 3.10.2, 3.10.4 and 3.10.5, the
            average emissions shall be calculated as 60-
            consecutive minute averages, instead of clock-hour
            averages.

  3.12.3    Data recorded during periods of continuous emission
            monitoring system (CEMS) breakdowns, repairs,
            calibration checks, and zero and span adjustments
            shall not be included in the data averages computed
            under this Section.  Missing data shall be estimated
            following the procedures of 40 CFR Part 75, App. C
            (Appendix C to Part 75 - Missing Data Statistical
            Estimation Procedures).

  3.12.4    An arithmetic or integrated average of all data may
            be used.  

  3.12.5    After conversion into the same units of measure as
            the standard, the data may be rounded to the same
            numbers of significant digits as used in the
            applicable subsections to specify the emission limit.



PART 4  ADMINISTRATIVE REQUIREMENTS


4.1   Implementation Plan

  4.1.1   By January 15, 1994, the owner or operator of an
          applicable unit shall submit for approval to the Air
          Pollution Control Officer an Implementation Plan for
          compliance with the provisions of Section 3.4,
          Subsections 3.7.2, 3.8.2, 3.9.2, 3.11.4, 3.11.5 and
          3.11.6 of this Rule.

  4.1.2   By October 31, 1995, the owner or operator of an
          applicable unit shall submit for approval to the Air
          Pollution Control Officer a revised Implementation Plan
          for compliance with the provisions of Subsection 3.7.2
          of this Rule.

  4.1.3   By December 31, 1997, the owner or operator of an
          applicable unit shall submit for approval to the Air
          Pollution Control Officer an Implementation Plan for
          compliance with the provisions of Subsections 3.8.4 and
          3.9.4 of this Rule.  

  4.1.4   By December 31, 1998, the owner or operator of an
          applicable unit shall submit for approval to the Air
          Pollution Control Officer an Implementation Plan for
          compliance with the provisions of Subsection 3.7.3 of
          this Rule.

  4.1.5   Each Implementation Plan shall propose actions and
          alternatives which will be taken to meet or exceed the
          requirements of this Rule.  At a minimum, each Plan
          shall include:

    4.1.5.1   a list of all units subject to the Rule, including
              the manufacturer, model number, and maximum rated
              capacity for each unit; and

    4.1.5.2   a description of the emissions control systems
              proposed for each unit, as well as a description of
              any ancillary equipment related to the control of
              emissions, and expected technical performance
              specifications for any CO and NOx emissions control
              systems; and

    4.1.5.3   a description of the continuous emission monitoring
              system (CEMS) proposed for each unit; and

    4.1.5.4   a compliance schedule for each unit, including, but
              not limited to, specific dates for the following
              events:  submittal of permit applications, final
              engineering, contract award, begin construction,
              planned operation phases, complete construction,
              and final compliance, including certification of
              any CEMS.


4.2   Authority to Construct

      The owner or operator of an applicable unit shall submit
      complete applications for the Authorities to Construct
      required to install any equipment necessary to comply with
      the provisions of Section 3.4, Subsections 3.7.2, 3.7.3,
      3.8.2, 3.8.4, 3.9.2, 3.9.4, 3.11.4 and 3.11.5 of this Rule
      to the Air Pollution Control Officer twelve months prior to
      the scheduled beginning of construction stated in the
      relevant District-approved Implementation Plan.


4.3   Recordkeeping Requirements

  4.3.1   For any utility power boiler subject to this Rule,
          permanent hourly records, or records in a District-
          approved electronic format, shall be maintained for a
          period of five years after creation and shall be made
          available for inspection by the Air Pollution Control
          Officer upon request.  The records for each hour shall
          include, but are not limited to:  

    4.3.1.1   dates, times and durations of any start-up and
              shut-down periods; 

    4.3.1.2   type of fuel oil burned and its sulfur content as
              determined by the methods referenced in 40 CFR Part
              75 Appendix D Subsections 2.2.3 and 2.2.4;

    4.3.1.3   quantity of fuel burned; 

    4.3.1.4   gross and net energy production in Megawatt-hours
              (MW-hrs); 

    4.3.1.5   the injection rate of reactant chemicals; 

    4.3.1.6   the CO emissions concentration in ppm, corrected to
              three percent oxygen (O2) on a dry basis, based on
              data from the in-stack continuous emission
              monitoring system (CEMS); and 

    4.3.1.7   the NOx emissions in lb/hr and ppm, corrected to
              three percent oxygen (O2) on a dry basis, based on
              data from the in-stack continuous emission
              monitoring system (CEMS).

    4.3.1.8   During the period from May 1 through October 31 of
              each year, the total daily NOx emissions, in pounds
              per day corrected to three percent oxygen on a dry
              basis, for all units must be recorded, based on
              data from the in-stack continuous emission
              monitoring system (CEMS).  The seasonal average
              from May 1 through October 31 of each year in
              pounds per day shall be calculated based upon these
              daily data.

  4.3.2   For any 110 or 120 MW unit, in addition to the
          information required by Subsection 4.3.1, this record
          shall also include the total daily steam production for
          each unit.

  4.3.3   For any CEMS subject to this Rule, records of all raw
          and processed data for parameters measured shall be
          maintained for a period of five years after creation
          and shall be made available for inspection by the Air
          Pollution Control Officer upon request.  These records
          may be kept in a District-approved electronic format.


4.4   Requirements for Accelerated Emission Reductions and
      Photochemical Modeling

  4.4.1   By February 1, 1994 the owner or operator of any
          applicable unit shall tender to the Air Pollution
          Control District the sum of one million dollars
          ($1,000,000), to be used to secure accelerated emission
          reductions.  The District shall hold these funds in
          trust in an account, to be named the Emission
          Reductions Account, separate from its general operating
          funds.  These funds shall be utilized only to secure
          ozone precursor emission reductions that are not
          otherwise required by local, state or federal law, such
          as from mobile sources or innovative or technology-
          forcing emission reduction strategies.

  4.4.2   By August 1, 1994 the owner or operator of any
          applicable unit shall tender to the Air Pollution
          Control District the sum of one and one half million
          dollars ($1,500,000), to be used as additional funding
          to secure accelerated emission reductions as described
          in Subsection 4.4.1 herein.

  4.4.3   By August 1, 1995 the owner or operator of any
          applicable unit shall tender to the Air Pollution
          Control District the sum of two and one half million
          dollars ($2,500,000), to be used as additional funding
          to secure accelerated emission reductions as described
          in Subsection 4.4.1 herein.

  4.4.4   By March 1, 1994 the owner or operator of any
          applicable unit shall tender to the Air Pollution
          Control District the sum of one quarter million dollars
          ($250,000), to be used as matching funds for the
          installation of a compressed natural gas (CNG) fueling
          facility in Santa Cruz County.

  4.4.5   By March 1, 1995 the owner or operator of any
          applicable unit shall tender to the Air Pollution
          Control District the sum of one half million dollars
          ($500,000), to be used as funding for the installation
          of a CNG fueling facility in San Benito County.

  4.4.6   By February 1, 1994 the owner or operator of any
          applicable unit shall tender to the Air Pollution
          Control District the sum of one and one quarter million
          dollars ($1,250,000), to be used to conduct
          photochemical modeling of air basin ozone formation and
          transport scenarios.

    4.4.6.1   Prior to conducting any modeling, the District
              shall prepare a protocol that meets all applicable
              state and federal guidelines for photochemical
              modeling, and the District shall submit this
              protocol to the California Air Resources Board (and
              the United States Environmental Protection Agency,
              as appropriate) for their review and approval.

    4.4.6.2   Any portion of the one and one quarter million
              dollars ($1,250,000) that has not been used for the
              purpose described in Subsection 4.4.6 by December
              31, 2001 shall be returned to the owner or operator
              that tendered the sum. 
                                 * * * * *