SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

RULE 1135 - EMISSIONS OF OXIDES OF NITROGEN FROM ELECTRIC POWER GENERATING SYSTEMS
(Adopted August 4, 1989)(Amended December 21, 1990)(Amended July 19, 1991)

(a) Applicability

This rule applies to electric power generating systems.

(b) Definitions

  1. ADVANCED COMBUSTION RESOURCE means a combustion resource, within or outside the District, irrespective of ownership, capable of generating electricity using cogeneration; combined cycle gas turbines; intercooled, chemically recuperated, or other advanced gas turbines; and other advanced combustion processes.
  2. ALTERNATIVE RESOURCE means a resource, within or outside the District, irrespective of ownership, capable of generating electricity in a non-conventional manner, including, but not limited to: solar; geothermal; wind; fuel cells; electricity conservation; and electricity demand-side management measures.
  3. APPROVED ALTERNATIVE OR ADVANCED COMBUSTION RESOURCE means an alternative resource or advanced combustion resource which is approved by the Executive Officer. The Executive Officer shall disapprove an alternative resource or an advanced combustion resource unless and until it:

    (A) Displaces boiler capacity existing in the District on or after July 19, 1991; and

    (B) Emits NOx at no more than 0.10 pound per net megawatt-hours (MWH) on a daily average basis if the resource is located within the District, or no more than 0.05 pound per net MWH on a daily average basis if the resource is located outside the District; for cogeneration facilities, the daily NOx emission per MWH shall be calculated after deducting 0.013 pound of NOx for each million BTU of useful thermal energy produced which is not used for electric power generation; and

    (C) Commences operation on or after July 19, 1991; and

    (D) Is proven to the satisfaction of the Executive Officer that the net megawatt-hours obtained or conserved are real, quantifiable, and enforceable.

  4. ALTERNATIVE RESOURCE OR ADVANCED COMBUSTION RESOURCE BREAKDOWN means an unscheduled condition during which no net electric power is obtained from an approved alternative or advanced combustion resource for 24 continuous hours or more.
  5. BOILER means any combustion equipment in the District fired with liquid and/or gaseous fuel, which is primarily used to produce steam that is expanded in a turbine generator used for electric power generation. This includes only units existing on July 19, 1991, which are owned or operated by any one of the following: Southern California Edison, Los Angeles Department of Water and Power, City of Burbank, City of Glendale, and City of Pasadena, or any of their successors.
  6. COGENERATION FACILITY means equipment used to produce electricity and other forms of useful thermal energy through the sequential use of energy, as specified in Public Resources Code Section 25134.
  7. DAILY means a calendar day starting at 12 midnight and continuing through to the following 12 midnight hour.
  8. DISPLACE means either of the following:

    (A) The concurrent and enforceable reduction of equivalent boiler capacity from one or more designated boilers in the District, such that the combined electric power obtained from approved alternative or advanced combustion resources and designated boilers does not exceed the maximum permitted capacity of the designated boilers, on an hourly average basis; or

    (B) The reduction of boiler capacity, equivalent to the maximum electric power obtained from the approved alternative or advanced combustion resource, from one or more boilers in the District for not less than six months as specified in the Permit to Operate. The owner or operator of the boilers may apply to the Executive Officer for restoration of the displaced capacity in the Permit to Operate, which shall be approved upon:

    (i) Disapproval of the previously approved alternative or advanced combustion resource which was based on such displaced capacity; and

    (ii) Evidence of compliance with all provisions of this rule after the restoration of the displaced capacity.

    During an alternative or advanced combustion resource breakdown, the associated displaced boiler capacity may be utilized up to a maximum of 120 hours in any calendar month, provided the Executive Officer is notified prior to such utilization.

  9. DISTRICT-WIDE DAILY LIMITS means the daily emissions limits applicable to any electric power generating system, consisting of an emissions cap and/or an emissions rate.

    (A) EMISSIONS CAP is expressed in pounds of NOx and calculated as the total daily NOx emissions in pounds from all boilers, replacement units, and approved alternative or advanced combustion resources in the District.

    (B) EMISSIONS RATE is expressed in pounds of NOx per Megawatt-Hour and calculated as the total daily NOx emissions in pounds from all boilers, replacement units, and approved alternative or advanced combustion resources in the District, divided by the total daily net electric power generated and/or obtained in Megawatt-Hours from all boilers and replacement units in the District and approved alternative or advanced combustion resources within or outside the District. For the purposes of this calculation, 70 percent, or higher if proven to the satisfaction of the Executive Officer, of the net Megawatt-Hours obtained from an approved alternative or advanced combustion resource outside the District shall be used. NOx emissions during start-ups and shutdowns, up to a maximum of 12 hours for each event, shall not be included in the determination of the emissions rate for an electric power generating system if five or fewer boilers are in operation during this period.

    NOx emissions from approved cogeneration facilities shall be calculated after deducting 0.013 pound of NOx for each million BTU of useful thermal energy produced which is not used for electric power generation.

  10. ELECTRIC POWER GENERATING SYSTEM means all boilers, replacement units and approved alternative or advanced combustion resources owned or operated by, and approved alternative or advanced combustion resources and replacement units under contract to sell power to, any one of the following: Southern California Edison, Los Angeles Department of Water and Power, City of Burbank, City of Glendale, City of Pasadena, or any of their successors.
  11. FORCE MAJEURE NATURAL GAS CURTAILMENT means an interruption in natural gas service due to unforeseeable failure, malfunction, or natural disaster, not resulting from an intentional or negligent act or omission on the part of the owner or operator of a boiler or a replacement unit, or a supply restriction resulting from a California Public Utilities Commission priority allocation system, such that the daily fuel needs of a boiler or a replacement unit cannot be met with the natural gas available.
  12. NOx EMISSIONS means the sum of nitric oxides and nitrogen dioxides emitted, collectively expressed as nitrogen dioxide emissions.
  13. REPLACEMENT UNIT for the purpose of this rule means equipment within an electric power generating system, irrespective of ownership, which permanently replaces boiler capacity existing on July 19, 1991 in the same system in the District, and meets the requirements of Best Available Control Technology (BACT), as determined by the Executive Officer. If the replacement unit's electric power output in net megawatts exceeds the permitted net megawatt capacity of the boiler(s) replaced, only the electric power generation and NOx emissions prorated to the permitted net megawatt capacity of the boiler(s) replaced shall be subject to the provisions of this rule.
  14. START-UP OR SHUTDOWN is any one of the following events:

    (A) START-UP is the time period during which a boiler is heated to its normal operating temperature range from a cold or ambient temperature, or from a hot standby condition where no net electric power is produced for at least 8 hours.

    (B) SHUTDOWN is the time period during which a boiler is allowed to cool from its normal operating temperature range to a cold or ambient temperature, or to a hot standby condition where no net electric power is produced for at least 8 hours.

  15. USEFUL THERMAL ENERGY means thermal energy used in any industrial or commercial process, or used in any heating or cooling application. This shall not include the thermal energy of any condensate returned from the process or application to the cogeneration facility, or any thermal energy used to produce electric power.

(c) Emissions Limitations

  1. Southern California Edison, or its successor, shall not operate its electric power generating system unless the following District-wide daily limits on emissions rate and emissions cap are met during the applicable time period:
                           

District-Wide Daily Limits

Lb-NOx Lb NOx/Net Megawatt (MW) Hr C Per Day ------------------------------------------------------------------ Beginning December 31, 1989 1.10 Beginning December 31, 1990 1.01 Beginning December 31, 1991 0.91 Beginning December 31, 1992 0.82 Beginning December 31, 1993 0.72 Beginning December 31, 1994 0.63 Beginning December 31, 1995 0.53 Beginning December 31, 1996 0.44 Beginning December 31, 1997 0.34 Beginning December 31, 1998 0.25 Beginning December 31, 1999 0.15 13,400

  1. Los Angeles Department of Water and Power, or its successor, shall not operate its electric power generating system unless the following District-wide daily limits on emissions rate and emissions cap are met during the applicable time period:
                           

District-Wide Daily Limits

Lb-NOx Lb NOx/Net Megawatt (MW) Hr Per Day ------------------------------------------------------------------ Beginning December 31, 1989 1.60 Beginning December 31, 1990 1.41 Beginning December 31, 1991 1.21 Beginning December 31, 1992 1.02 Beginning December 31, 1993 0.82 Beginning December 31, 1994 0.73 Beginning December 31, 1995 0.63 Beginning December 31, 1996 0.54 Beginning December 31, 1997 0.43 Beginning December 31, 1998 0.29 Beginning December 31, 1999 0.15 5,400 Beginning December 31, 2004 0.15 6,400 Beginning December 31, 2009 0.15 7,400

  1. The City of Burbank, the City of Glendale, and the City of Pasadena, or any of their successors, shall not operate their electric power generating system unless at least one of the following District-wide daily limits on emissions rate or emissions cap is met during the applicable time period:

    (A) For the City of Burbank:

                           

District-Wide Daily Limits

Lb NOx/Net Date Megawatt (MW) Hr Lb NOx Per Day ------------------------------------------------------------------ Beginning December 31, 1989 2.47 3,870 Beginning December 31, 1993 1.73 2,763 Beginning December 31, 1996 0.99 1,657 Beginning December 31, 1999 0.20 580 (B) For the City of Glendale:

                           

District-Wide Daily Limits

Lb NOx/Net Date Megawatt (MW) Hr Lb NOx Per Day -------------------------------------------------------------------- Beginning December 31, 1989 2.52 2,940 Beginning December 31, 1993 1.76 2,050 Beginning December 31, 1996 1.00 1,170 Beginning December 31, 1999 0.20 390 (C) For the City of Pasadena:

                           

District-Wide Daily Limits

Lb NOx/Net Megawatt (MW) Hr Lb NOx Per Day -------------------------------------------------------------------- Beginning December 31, 1989 3.05 5,230 Beginning December 31, 1993 2.12 3,680 Beginning December 31, 1996 1.18 2,130 Beginning December 31, 1999 0.20 900

  1. Electric power generating systems shall not emit NOx from all boilers, replacement units and approved alternative resources or advanced combustion resources in the District, for any calendar year beginning with 2000, in excess of the following limits:

    (A) 1,640 tons per year for Southern California Edison Co.;

    (B) 960 tons per year for Los Angeles Department of Water and Power;

    (C) 56 tons per year for the City of Burbank;

    (D) 35 tons per year for the City of Glendale; if Grayson combined cycle gas turbine Unit 8BC cannot produce electricity because of a breakdown for 30 continuous days or more, the annual NOx emissions limit shall be increased by 65 pounds per day, up to a maximum of 41 tons per year.

    (E) 80 tons per year for the City of Pasadena.

  2. A violation of any requirement specified in paragraphs (c)(1), or (c)(2), or (c)(3), or (c)(4) shall constitute a violation of this rule for every permitted unit operating during the exceedance period in the applicable electric power generating system. This provision shall not be applicable to approved alternative or advanced combustion resources, and compliance shall be determined assuming that NOx emissions from approved alternative or advanced combustion resources occur at actual or permitted levels, whichever is lower.
  3. All retrofit emission control devices required to meet the provisions of this rule for the year 2000 shall be installed and be operative on each boiler by December 31, 1997, except for the three cities of Glendale, Pasadena and Burbank for whom the deadline shall be December 31, 1999. All replacement units and approved alternative or advanced combustion resources required by the approved compliance plan for all the electric power generating systems shall be installed and be operative by December 31, 1999.
  4. The owner or operator of each boiler and approved alternative or advanced combustion resource in the District shall submit an application for change of permit conditions to include NOx emission limits for each boiler and approved alternative or advanced combustion resource, as specified in the compliance plan requirements in subparagraph (d)(1)(C). Such applications shall be submitted no later than January 1, 1992, to the Executive Officer for approval.
  5. A violation of any unit-specific NOx emissions limits established in a District Permit to Operate or approved compliance plan shall constitute a violation of this rule for that unit of the electric power generating system.

(d) Compliance Plans

  1. Compliance Plan (Plan) approval and disapproval:

    (A) Each owner or operator of a boiler shall submit a Plan by
    January 1, 1992 to the Executive Officer for approval. The Plan shall propose actions and alternatives which will be taken to meet or exceed the requirements of this rule.

    (B) The Executive Officer shall seek input from the Air Resources Board (ARB), the California Energy Commission (CEC), and the California Public Utilities Commission (CPUC) prior to approval of the Plan. All written comments received from the ARB, the CEC, and the CPUC for a CPUC-regulated utility, within 30 days of the receipt of the Plan, shall be considered by the Executive Officer for Plan approval.

    (C) The Executive Officer shall disapprove the Plan unless the applicant proves to the satisfaction of the Executive Officer that the implementation of the Plan will result in timely compliance with all provisions of this rule. The approved Plan shall specify a NOx emission limit for each unit of the electric power generating system in Lb NOx per net Megawatt Hour on an hourly average basis; such emission limit shall not be applicable when the unit is not producing any net electric power, or during a start-up, a shutdown, or 12 hours for each start-up or shutdown, whichever is less.

    (D) On and after July 1, 1992, failure to have an approved Plan or failure to implement the provisions of an approved Plan shall constitute a violation of this rule.

  2. The Plan shall contain, at a minimum:

    (A) A list of all boilers subject to this rule with the maximum rated net and gross generating capacity for each unit.

    (B) A schedule of equipment to be controlled, displaced, or replaced, indicating the type of control to be applied to each existing boiler and the emissions reductions for each compliance increment, and identifying each unit to be displaced with an alternative or advanced combustion resource.

    (C) Detailed schedules for submittal of permit applications, construction activities, and planned operation phases.

    (D) A detailed list of all assumptions and calculations used to determine compliance with the District-wide daily limits.

    (E) A list of the control devices and methods which are being proposed for each boiler specified in subparagraph (d)(2)(A), along with the percent NOx reduction efficiency assumed for each.

    (F) Historical power generating data for each boiler and future resource plans used to support power generation mix assumptions.

    (G) For each year, beginning with 1992, a graph of the NOx emission in Lb NOx/hour versus net Megawatts generated on an hourly average basis for the full load range of each unit of the electric power generating system burning natural gas that will result in compliance with the District-wide daily limits as specified in subsection (c), Emissions Limitations, for the following cases:

    (i) Under a projected peak generation day for each future year of compliance, based on District guidelines, and

    (ii) Individually for each unit, under maximum power generation for that unit on a projected peak generation day for each future year of compliance.

    (H) Identification of conditions that may require an exemption under subsection (h) and the actions taken or to be taken to minimize or eliminate such conditions.

  3. The Plan shall also include proposed increments of progress for the following:

    (A) Southern California Edison shall install and operate by December 31, 1993 a Selective Catalytic Reduction unit (SCR) on an existing 480 MW steam boiler such that NOx emissions from the facility do not exceed 0.25 pound of NOx per net MWH; and

    (B) Los Angeles Department of Water and Power shall replace at least 240 megawatts of existing steam boiler capacity by
    December 31, 1993 such that NOx emissions from the replacement unit do not exceed applicable Best Available Control Technology standards, as determined by the Executive Officer.

  4. Not earlier than July 1 of any year following 1992, amendments to a previously approved Plan may be proposed to the Executive Officer as necessary to reflect energy regulatory agency resource or municipal authority planning determinations, adjustments to unit specific emissions limits required in subparagraph (d)(1)(C) in view of emissions control performance test data, and advancements in emissions control technology. The Executive Officer shall disapprove such amendments unless the applicant proves to the satisfaction of the Executive Officer that the implementation of the amended Plan will result in timely compliance with all provisions of this rule.
  5. All approved Plans and approved amendments to Plans shall be submitted by the District to the Air Resources Board and the Environmental Protection Agency as source-specific revisions to the State Implementation Plan.

(e) Measurements

  1. The owner or operator of each boiler, replacement unit and approved alternative or advanced combustion resource in the District shall install, operate, and maintain in calibration an continuous emission monitoring system (CEMS) and a Remote Terminal Unit (RTU) to demonstrate compliance with the provisions of this rule.
  2. Each CEMS shall meet all applicable federal, state and District requirements for certification, calibration, performance, measurement, maintenance, notification, recordkeeping and reporting, including, but not limited to, the requirements set forth in the District's "CEMS Requirements Document for Utility Boilers," dated July 19, 1991. Prior to the installation of a CEMS, the owner or operator of each boiler, replacement unit and approved alternative or advanced combustion resource in the District shall submit a revised detailed CEM Plan by October 19, 1991 for the approval of the Executive Officer. The CEM Plan shall contain all information required in the District's "CEMS Requirements Document for Utility Boilers," dated July 19, 1991.
  3. Each RTU shall meet specifications set forth by the Executive Officer to ensure that emissions and other data necessary to determine compliance are reliably and accurately telecommunicated from each unit to the District in a format compatible with District equipment. Each RTU shall be installed with the prior approval of the Executive Officer by January 1, 1993.
  4. Starting December 21, 1990 until January 1, 1993, the owner or operator of each boiler, replacement unit and approved alternative or advanced combustion resource in the District shall submit a monthly compliance report to the Executive Officer, and shall make all data available to the District staff on a daily basis according to the interim reporting requirements specified in the "CEMS Requirements Document for Utility Boilers," dated July 19, 1991.
  5. The owner or operator of each boiler, replacement unit and approved alternative or advanced combustion resource in the District shall install testing facilities as specified in the "CEMS Requirements Document for Utility Boilers," dated July 19, 1991, by January 1, 1993.
  6. The owner or operator of each boiler, replacement unit and approved alternative or advanced combustion resource in the District shall install, maintain and operate a backup data gathering and storage system after each associated RTU is installed, but not later than January 1, 1993, as specified in the "CEMS Requirements Document for Utility Boilers," dated July 19, 1991.
  7. CEMS data shall be gathered and recorded at least once per minute at each boiler, replacement unit and approved alternative or advanced combustion resource in the District, and valid data, as specified in the "CEMS Requirements Document for Utility Boilers," dated July 19, 1991, shall be obtained for at least 90 percent of the data points in any calendar day.
  8. If valid data is not obtained by a CEMS for any boiler, replacement unit or approved alternative or advanced combustion resource in the District, the following alternative means of NOx emissions data generation may be used for not more than 72 hours in any one calendar month:

    (A) Reference test methods as specified in the "CEMS Requirements Document for Utility Boilers," dated July 19, 1991; or

    (B) Load curves provided approval is obtained as specified in the "CEMS Requirements Document for Utility Boilers," dated July 19, 1991. New load curves shall be submitted for the approval of the Executive Officer if the basic equipment is modified.

(f) Use of Liquid Petroleum Fuel

  1. The District-wide daily limits on emissions rate and emissions cap specified in paragraphs (c)(1), (c)(2), and (c)(3) shall not apply to an electric power generating system on days of force majeure natural gas curtailment when the use of liquid petroleum fuel is required, provided that:

    (A) Within 15 days of each occurrence, the owner or operator of each boiler submits an affidavit signed by a corporate officer affirming that liquid petroleum fuel was burned due to force majeure natural gas curtailment; and

    (B) Each boiler, when it burns natural gas exclusively, meets the applicable unit-specific NOx emission limit specified in subparagraph (d)(1)(C); and

    (C) Each boiler, when it burns liquid petroleum fuel exclusively, emits oxides of nitrogen at no more than 2 times the applicable unit-specific NOx emission limit specified in subparagraph (d)(1)(C); and

    (D) Each boiler, when it burns a combination of liquid petroleum fuel and natural gas, emits oxides of nitrogen at no more than the prorated limit for that unit, obtained from the requirements specified in subparagraphs (f)(1)(B) and (f)(1)(C), and weighted by the flow rate and gross heating value of natural gas and liquid petroleum fuel, respectively. The calculation procedure in the "CEMS Requirement Document for Utility Boilers", dated July 19, 1991 shall be followed.

  2. A boiler may burn liquid petroleum fuel for up to 24 hours in any calendar year for fuel readiness testing provided that the emission limitation specified in subparagraph (f)(1)(C) is met. The unit specific NOx emission limit specified in subparagraph (d)(1)(C) shall not apply during this period.

(g) Municipal Bubble Options

  1. Any electric power generating system may form a municipal bubble by linking with one or more electric power generating system(s), for the purposes of this rule, provided all of the following conditions are met:

    (A) The municipal bubble does not include Southern California Edison; and

    (B) The municipal bubble is formed for at least one year, or more; and

    (C) An application for approval of the municipal bubble is submitted jointly by all affected municipal utilities to the Executive Officer, at least six months in advance; and

    (D) Written approval of the application for the municipal bubble is obtained from the Executive Officer prior to utilization of any provision contained in subsection (g), Municipal Bubble Options.

  2. The application for a municipal bubble required in subparagraph (g)(1)(C) shall include, without being limited to:

    (A) Proposed amendments to the compliance plans of all affected municipal utilities, as required to meet or exceed the municipal bubble emissions limitations specified in paragraph (g)(3); and

    (B) Applications for change of permit conditions to adjust NOx emissions limits for each boiler, replacement unit and approved alternative or advanced combustion resource in the District, as required by the proposed amendments to the compliance plans; and

    (C) Any other information required by the Executive Officer to evaluate compliance with the provisions of this rule.

    The Executive Officer shall not approve the application for a municipal bubble unless it is demonstrated to the satisfaction of the Executive Officer that such action(s) will result in compliance with the municipal bubble emissions limitations specified in paragraph (g)(3) in an enforceable manner.

  3. Municipal bubble emissions limitations shall be derived from the District-wide daily limits on emissions rate and emissions cap specified in paragraphs (c)(2) and (c)(3), for each municipal utility, as follows:

    (A) The District-wide daily limits on emissions rate in pounds of NOx per net megawatt-hours shall be the sum of the emissions rates of each participating utility, weighted by the maximum permitted capacity of each utility as a fraction of the total permitted capacity in the municipal bubble, for the applicable time period; and

    (B) The District-wide daily limits on emissions cap in pounds of NOx per day shall be the sum of the emissions cap of all participating utilities, for the applicable time period, and beginning December 31, 1999, if Los Angeles Department of Water and Power is included in the municipal bubble; and

  4. An electric power generating system subject to a municipal bubble approved by the Executive Officer shall be exempt from the utility-specific requirements of paragraphs (c)(2) and (c)(3); and be subject to the municipal bubble emissions limitations specified in paragraph (g)(3) for the applicable time period.
  5. A violation of any municipal bubble emissions limitations required in paragraph (g)(4) shall constitute a violation for each permitted boiler and replacement unit, operating during the exceedance period, in the municipal bubble. This provision shall not apply to approved alternative or advanced combustion resources.

(h) Exemptions

  1. Notwithstanding the provisions of paragraphs (c)(1) or (c)(2), Southern California Edison or Los Angeles Department of Water and Power may operate its electric power generating system if both the following District-wide daily limits on emissions rate and emissions cap are met:
                           

District-Wide Daily Limits

Lb NOx/Net Megawatt (MW) Hr Lb NOx Per Day ----------------------------------------------------------------------- Southern California Edison 0.25 5,360 Los Angeles Department of Water and Power 0.25 2,960

  1. Notwithstanding the provisions of paragraphs (c)(1), (c)(2), or (c)(3), an electric power generating system may be operated for no more than 10 calendar days in any calendar year if all the following conditions are met:

    (A) Both the following District-wide daily limits on emissions rate and emissions cap are met:

                           

District-Wide Daily Limits

Lb NOx/Net Megawatt (MW) Hr Lb NOx Per Day ------------------------------------------------------------------------- Southern California Edison 0.25 20,100 Los Angeles Department of Water Power and 0.25 11,100 Burbank 0.25 870 Glendale 0.25 580 Pasadena 0.25 1,350; and

(B) The electric generating system owner/operator has taken all possible steps to comply with paragraphs (c)(1), (c)(2) and (c)(3), including the interruption of non-firm load.

(C) The exemption is not required as a result of operator error, neglect, or improper operating or maintenance procedures;

(D) Steps are immediately taken to correct the condition;

(E) The electric power generating system owner/operator reports to the District the need for the exemption within one hour of the occurrence or within one hour of the time said operator knew or reasonably should have known of the occurrence;

(F) No later than one week after each event the owner/operator submits a written report to the District including but not limited to:

(i) A statement that the situation has been corrected, together with the date of correction and proof of compliance;

(ii) A specific statement of the reason(s) or cause(s) for the exemption sufficient to enable the Executive Officer to determine whether the occurrence was in accordance with the criteria set forth in subparagraphs (h)(2)(B) and (h)(2)(C) of this rule;

(iii) A description of the corrective measures undertaken and/or to be undertaken to avoid such an occurrence in the future.


FOR REFERENCE PURPOSES ONLY: (Amended July 19, 1991)

CONTINUOUS EMISSION MONITORING SYSTEMS (CEMS)
REQUIREMENTS DOCUMENT FOR UTILITY BOILERS

This document specifies requirements under Rule 1135 for continuous emission monitoring systems. Other District rules and permit conditions may require measurements, calculations, and reporting in addition to those indicated in this document.

1. REQUIREMENTS

1.1  The owner or operator of each boiler, unit, and approved alternative

     or advanced combustion resource shall install, calibrate, maintain,

     and operate an approved CEMS, and record the output of the system,

     for measuring the following:

a. Nitrogen oxides emissions (in units of ppmv) discharged to the atmosphere from each boiler, unit, and approved alternative or advanced combustion resource.

b. Oxygen concentration, at each location where nitrogen oxides are monitored.

c. Stack gas volumetric flow rate. An in-stack flow meter may be used to determine mass emission rates to the atmosphere from each boiler, unit, and approved alternative or advanced combustion resource, except:

(i) when more than one boiler or resource vents to the atmosphere through a single stack, or

(ii) during periods of low flow rates when the flow rate is no longer within the applicable range of the in-stack flow meter.

d. Heat input rate when needed by the CEMS to determine the stack gas volumetric flow rate, or to determine applicable prorated emission limits during periods when the boiler, unit, or approved alternative or advanced combustion resource is firing on both gaseous and liquid fuels. The owner or operator shall include in the CEMS calculations the Fd factors listed in 40 CFR Part 60, Appendix A, Method 19, Table 19-1. The owner or operator shall submit data to develop Fd factors when alternative fuels are fired and obtain the approval of the Executive Officer for use of the Fd factors before firing any alternative fuels.

e. Net MWH of electricity produced at each affected boiler, unit, or approved alternative or advanced combustion resource.

The owner or operator shall also provide any other data necessary for calculating air contaminant emission rates as determined by the Executive Officer.

2. MONITORING SYSTEMS

2.1  All CEMS at each affected boiler, unit, or approved alternative

     or advanced combustion resource shall, at a minimum, generate

     and record the following data points once per minute:

a. Nitrogen oxide concentration in the stack in units of ppmv.

b. Oxygen concentration in the stack in units of percent.

c. Volumetric flow rate of stack gases in units of dry standard cubic feet per minute (DSCFM). For Rule 1135 standard gas conditions are defined as temperature at 68oF and one atmosphere of pressure.

d. Fuel flow rates in units of standard cubic feet per minute (SCFM) for gaseous fuels or pounds per minute (lb/min) for liquid fuels if EPA Method 19 is used to calculate the stack gas volumetric flow rate.

e. Nitrogen oxide emission rate in units of lb/minute. The nitrogen oxide emission rate is calculated according to the following:

FORMULA

where   ei = The emission rate of nitrogen oxides in pounds per

             minute measured every minute, 



        ai = The stack gas concentration of nitrogen oxides measured

             each minute (ppmv),



        ci = The stack gas volumetric flow rate measured each minute

             (DSCFM).

When the CEMS uses the heat input rate to determine the nitrogen oxides emission rates, the CEMS will use the following equation to calculate the emission rate of nitrogen oxides:

FORMULA

where   ei = The emission rate of nitrogen oxides in pounds per

             minute measured every minute,



        ai = The stack gas concentration of nitrogen oxides measured

             each minute (ppmv) on a dry basis,



        bi = The stack gas concentrations of oxygen measured every minute



        r  = The number of different types of fuel,



       Fdi = The dry F factor for each type of fuel, the ratio of the

             dry gas volume of the products of combustion to the heat content

             of the fuel (DSCF/106 BTU),



        di = The fuel flow rate for each type of fuel measured every

             minute,



        Vi = The higher heating value of the fuel for each type of fuel.

The product (di x Vi) must have units of millions of BTU per minute (106 BTU/min).

f. During any one minute period when the net MW output of the replacement unit exceeds the permitted net MW capacity of the replaced boiler, the data points ei and fi (defined in Paragraph 2.2) must be recalculated by multiplying by the following factor:

(MWp/MWr)

where   MWp = Net MW output capacity of the replaced boiler,



    and MWr = Net MW output during the one minute period



            = fi x 60

Record the uncorrected and corrected values of ei and fi. Calculate and record the data points E, F, G, and H, the hourly lb NOx/net MWH of electricity produced, and the daily lb NOx/net MWH of electricity produced using first the uncorrected and corrected ei and fi values and using then the corrected ei and fi values.

g. Net MWH of electricity produced. The net MWH are defined as:

net MWH = VIt cos ø /106

where   V = Voltage to the power grid (Volt),



        I = Current to the power grid (Ampere),



    cos ø = Power factor,



    and ø = Phase angle.



        t = Time (hr) = 1/60 hr,

The above equation is only a definition of MWH and a meter which measures MWH directly may be used. The voltage, current, power factor, and time do not need to be measured separately.

net MWH = Gross MWH - Auxiliary MWH

h. CEMS status. The following codes shall be used to report the CEMS status:

     0 - Collecting valid data,

 

     1 - In calibration,



     2 - Off line,



     3 - Tamper/security,



     4 - Alternative data acquisition (see Paragraphs 2.7 and 2.8),



     5 - Hot Standby,



     6 - Out-of-control,



     7 - Startup/shutdown.



2.2  The hourly average stack gas concentrations of nitrogen oxides

     and oxygen, the stack gas volumetric flow rate, the fuel flow

     rate, emissions of nitrogen oxides, the net MWH of electricity

     produced, and the emissions rate of nitrogen oxides shall be calculated

     and recorded for each affected boiler, unit, or approved alternative

     or advanced combustion resource:

FORMULA(for NOx concentration)

FORMULA(for O2 concentration)

FORMULA(for stack gas volumetric flow rate)

FORMULA(for fuel flow rates)

Calculate D for each type of fuel firing separately.

FORMULA(for NOx emissions)

FORMULA(for net MWH)

P = E/F (for NOx emissions rate)

All concentrations and stack gas flow rates shall be made on a consistent wet or dry basis.

where  A = The hourly average stack gas concentration of nitrogen

           oxides,



      ai = The stack gas concentrations of nitrogen oxides measured

           every minute,



       B = The hourly average oxygen stack concentration,



      bi = The stack gas concentrations of oxygen measured every minute,



       C = The hourly average stack gas flow rate,



      ci = The stack gas volumetric flow rates measured every minute,



      Di = The hourly average fuel flow rates, for each type of fuel,



      di = The fuel flow rate for each type of fuel measured every

           minute,



       E = The hourly average emission rates of nitrogen oxides,



      ei = The emissions of nitrogen oxides in pounds per minute measured

           every minute,



       F = The hourly net MWH of electricity produced,



      fi = The net MWH of electricity produced measured every minute,



       P = The emissions rate of nitrogen oxides in pounds per net

            MWH of electricity produced



       n = Number of valid data points during the hour.

           Indicate any hourly data where n <45.

2.3 The average daily emissions of nitrogen oxides shall be calculated

    and recorded for each affected boiler, unit, or approved alternative

    or advanced combustion resource:

FORMULA

where   G = The daily emissions of nitrogen oxides in units of

            lb/day,



        M = Number of operating minutes during the day,



   and  N = Number of valid data points during the day.

            Indicate any daily data where N <90 percent of M.

2.4 The average daily net MWH of electricity produced shall be

    calculated and recorded for each affected boiler, unit, or approved

    alternative or advanced combustion resource:

FORMULA

where H = The daily net MWH of electricity produced during the day, Indicate any daily data where N <90 percent of M.

2.5 The hourly unit-specific emission limit shall be calculated

    and recorded when more than one fuel is burned during the hour:

FORMULA

where J = Hourly unit-specific emission limit when more than

          one type of fuel is fired (lb NOx/net MWH of electricity produced)



     Li = Unit-specific emission limit for each type of fuel fired

          (lb NOx/net MWH of electricity produced)



     Vi = Higher heating value of each type of fuel

The product (Di x Vi) must have units of millions of BTU per hour (106 BTU/hour)

2.6  The CEMS shall be operated and data recorded during all periods

     of operation of the affected boilers, units, and approved alternative

     or advanced combustion resources including periods of start-up,

     shutdown, malfunction or emergency conditions, except for CEMS

     breakdowns and repairs.  Calibration data shall be recorded during

     zero and span calibration checks, and zero and span adjustments.

     For periods of hot standby the utilities may enter a default

     value for NOx emissions.  Before using any default values the

     utilities must obtain the approval of the Executive Officer and

     must include in the CEMS applications or CEMS plans the estimates

     of NOx emissions, the NOx concentrations, the oxygen concentrations,

     and the fuel input rate or the stack gas volumetric flow rate

     during hot standby conditions.  The Executive Officer will approve

     only those emission values which he finds to correspond to hot

     standby conditions.



2.7  When less than 90% of valid nitrogen oxides emission data

     are collected by the CEMS, emission rate data shall be obtained

     using District Methods 7.1 or 100.1 (for NOx concentration in

     the stack gas) in conjunction with District Methods 1.1, 2.1,

     3.1, and 4.1 or by using District Methods 7.1 or 100.1 in conjunction

     with District Method 3.1 and EPA Method 19.  If the NOx concentrations

     are less than 20 ppm, use Special District Method 7.1 (IC Alternative)

     or Modified District Method 100.1 for Low NOx Concentrations.

     Descriptions of the last two methods can be found in Paragraphs

     3.3.1 and 3.3.2 of the Relative Accuracy Test Procedure.  For

     District Method 7.1 or Special District Method 7.1 (IC Alternative),

     a minimum of 12 samples, equally spaced over a one-hour period,

     shall be taken.  Each sample shall represent the five-minute period

     in which it was taken.



2.8  Load curves of NOx emission rates or other alternative means

     of NOx emission rate data generation may be used to obtain nitrogen

     oxides emission data, provided the utility has obtained the approval

     of the Executive Officer prior to using alternate means of NOx

     emission rate data generation.  The load curves and the alternate

     means of NOx emission rate data generation mentioned in this paragraph

     shall not be used more than 72 hours per calendar month and may

     only be used if no CEMS data or reference method data gathered

     under paragraph 2. 7 is available.  Load curves may be used on

     units which have air pollution control devices for the control

     of nitrogen oxides emissions provided the utilities submit a complete

     list of operating conditions that characterize the permitted operation.

     The conditions must be specified in the compliance plans and

     permits which the rule requires.  The process parameters specified

     in the conditions must be monitored by the CEMS.



2.9   At each affected boiler, unit, or approved alternative or

      advanced combustion resource the number of valid data points (N)

      during the day shall be greater than 90 percent of the number

      operating minutes during the day in order to obtain a valid daily

      emission rate for nitrogen oxides and the daily net MWH of electricity

      produced.  Valid data points are data points from the CEMS which

      meet the requirements of Paragraphs 2.18, 2.19, 2.19.1, 2.19.2,

      2.19.2, 2.19.4, 2.19.5, 2.19.6, 2.19.7, 2.19.8, and 2.20 or which

      are obtained by the methods indicated in Paragraphs 2.7 and 2.8.

      The utility is deemed to be out of compliance with rule 1135

      on a systemwide basis if one or more boilers, units, or approved

      alternative or advanced combustion resources do not comply with

      the 90 percent valid data requirement.



2.10  Full scale span ranges for the NOx analyzers at each unit

      shall be set on a unit-by-unit basis.  The full scale span range

      of the NOx analyzers shall be set so that all the data points

      gathered by the CEMS lie within 20-95 percent of the full-scale

      span range.



2.11  The CEMS design shall allow determination of calibration

      drift at zero and high-level (90 to 100 percent of full scale)

      values.  Alternative low-level and high-level span values may

      be allowed with the prior written approval of the Executive Officer.



2.12  The volumetric flow measurement system shall meet a relative

      accuracy requirement of being less than or equal to 10 percent

      of the mean value of the reference method test data in units of

      DSCFM.  Relative accuracy is calculated by the equations in Section

      8 of 40 CFR Part 60, Appendix B, Performance Specification 2.



2.13  The emission rate measurement shall meet a relative accuracy

      requirement of being less than or equal to 20 percent of the mean

      value of the reference method test data in units of lb/hr.  Relative

      accuracy is calculated  by the equations in Section 8 of 40 CFR

      Part 60, Appendix B, Performance Specification 2.



2.14  The portion of the CEMS which samples, conditions, analyzes,

      and records the nitrogen oxides and oxygen concentrations in the

      stack gas shall be certified according to the specifications in

      District Rule 218.



2.15  Each boiler, unit, and approved alternative or advanced combustion

      resource shall have test facilities which meet the "Guidelines

      for Construction of Sampling and Testing Facilities" in the

      District Source Test Manual.  If an alternate location (not conforming

      to the criteria of eight duct diameters downstream and two diameters

      upstream from a flow disturbance) is used, the absence of flow

      disturbance and stratification shall be demonstrated using District

      Source Test Methods.



2.16  The CEMS sample line from the CEMS probe to the sample conditioning

      system shall be heated to maintain the sample temperature above

      the dew point of the sample.



2.17  The District shall reevaluate the monitoring systems at any

      affected boiler, unit, or approved alternative or advanced combustion

      resource, where changes to the basic process equipment or air

      pollution control equipment occur, to determine the proper full

      span range of the monitors. Any monitor system requiring change

      to its full span range in order to meet the criteria in Paragraph

      2.10 shall be recertified according to all the specifications

      in Rule 218 including the relative accuracy tests, the calibration

      drift tests, and the calibration error tests.  A new CEMS plan

      shall be submitted for each CEMS which is reevaluated.



2.18  Procedure 1 of 40 CFR Part 60, Appendix F is incorporated

      by reference for the nitrogen oxides and oxygen monitors.  The

      quality assurance plans required by 40 CFR Part 60, Appendix F

      shall be submitted to the District for the approval of the Executive

      Officer before the CEMS is certified.  The reference method tests

      are those methods in Section 3 (RELATIVE ACCURACY TEST METHODS)

      of this guideline.  Any CEMS which is deemed out-of-control by

      40 CFR Part 60, Appendix F shall be corrected, retested by the

      appropriate audit procedure, and restored to in-control within

      24 hours after being deemed out-of-control.  If the CEMS is not

      in-control at the end of the 24-hour period, the CEMS data shall

      be gathered using the methods in paragraphs 2.7 and 2.8 of these

      requirements.  All data which is gathered in order to comply with

      40 CFR Part 60, Appendix F shall be maintained for two years and

      be made available to the Executive Officer upon request.  Any

      such data which is invalidated shall be identified and reasons

      provided for any data invalidation.



2.19  Each volumetric flow measurement system shall be audited

      at least once each calendar quarter.  Successive audits shall

      occur no closer than two months.  The audits shall be conducted

      as follows:



2.19.1  The Relative Accuracy Test Audit (RATA) shall be conducted

        at least once every four quarters.  Conduct the RATA as described

        in Section 3 (RELATIVE ACCURACY TEST METHODS).



2.19.2  The Relative Accuracy Audit may be conducted three of four

        calendar quarters, but no more than three quarters in succession.

        To conduct an RAA, follow the procedure described in Section

        3 (RELATIVE ACCURACY TEST METHODS) for the relative accuracy test,

        except that only three sets of measurement data are required.



2.19.3  Follow the equations described in Section 8 of 40 CFR Part

        60, Appendix B, Performance Specification 2 to calculate the relative

        accuracy for the RATA.  The RATA shall be calculated in units

        of dry standard cubic feet per minute (DSCFM).



2.19.4  Follow this equation to calculate the accuracy for the

        RAA:

FORMULA

where A = Accuracy of the volumetric flow measurement system.



     Fm = Average response of the volumetric flow measurement system

          in units of DSCFM.



     Fa = Average reference method audit value in units of DSCFM.

2.19.5  If the relative accuracy using the RATA exceeds 20 percent

        of the mean reference method value, the CEMS shall be considered

        out-of-control.  If the relative accuracy exceeds ±15 percent

        using the RAA, the CEMS shall be considered out-of-control.  If

        the CEMS is out-of-control, take necessary corrective action to

        eliminate the problem.  Following corrective action, audit the

        CEMS accuracy with an RAA or an RATA to determine if the CEMS

        is operating properly.  An RATA shall be used following an out-of-control

        period resulting from an RATA.  If the audit shows the CEMS to

        be out-of-control, the CEMS operator shall report the results

        of the audit showing the CEMS to be out-of-control, any subsequent

        audit showing the CEMS to remain out-of-control following corrective

        action, and the audit showing the CEMS to be operating within

        specifications following corrective action.



2.19.6  The beginning of the out-of-control period shall be the

        time corresponding to the completion of the sampling of the RAA

        or RATA.  The end of the out-of-control period shall be the time

        corresponding to the completion of the sampling of the subsequent

        successful RAA or RATA.



2.19.7  During the period the CEMS is out-of-control, the CEMS

        data shall not be used in calculating emission compliance nor

        be counted towards meeting minimum data availability.



2.19.8  Whenever out-of-control periods occur for two consecutive

        quarters, the owner or operator shall revise the quality control

        procedures contained in the quality assurance plans, or modify

        and replace the CEMS.  If the CEMS is modified or replaced, the

        new CEMS shall be recertified by the Executive Officer.



2.20  The nitrogen oxides emission rate (lb NOx/hr) portion of

      the CEMS at each boiler, unit or approved alternative or advanced

      combustion resource shall have a relative accuracy of no greater

      than 20 percent of the mean value of the reference method test

      data in terms of lb NOx/hr.  This relative accuracy test shall

      be conducted during the certification test of each CEMS, and shall

      be conducted  at least once every four quarters as an RATA for

      each CEMS. An RAA may be conducted three of four calendar quarters

      as described in Paragraph 2.19.1.  The definition of an out-of-control

      CEMS is the same as Paragraph 2.19.5, except that the RAA shall

      exceed ±20 percent before the CEMS is considered out-of control.

      The definition of out-of-control period is the same as Paragraph

      2.19.6.The CEMS status during an out-of-control period is the

      same as Paragraph 2.19.7.  The criteria for acceptable procedures

      is the same as Paragraph 2.19.8.

3. RELATIVE ACCURACY TEST METHODS

3.1  Conduct the reference method (RM) tests in such a way that

     they will yield results representative of the emissions from the

     source and can be correlated to the CEMS data.



3.2  Conduct a minimum of nine sets of all necessary reference

     method (RM) tests.  Conduct each set within a period of 30 to

     60 minutes.



3.3  Unless the expected concentrations of NOx are less than 20

     ppm, District Methods 7.1 or 100.1 are the reference methods for

     NOx concentrations.



3.4  Use the Special District Method 7.1 (IC Alternative) or the

     Modified District Method 100.1 to determine NOx stack gas concentrations

     of less than 20 ppm.



3.4.1  Modified District Method 100.1 for Low NOx Concentrations

District Method 100.1 may be used to measure low NOx concentrations if the following additional quality control measures are taken on the reference method monitor:

a. Perform NO2 system bias checks in addition to the regular system bias check in District Method 100.1. Use approximately 10 ppm NO2 span gas for this system bias check. Perform these checks at the beginning, the middle, and the end of each test day. The checks made in the middle and the end of the test day must be made before emptying the condensate from the sampling system (if applicable).

b. Determine the NOx to NO concentration readings during at least one test run.

c. Determine the NO2 to NO conversion efficiency by running a known NO2 calibration gas (about 10 ppm) through the NO2 convertor and comparing the calibrated monitor response to the NO2 concentration.

d. The calibration error limits and the calibration gas specifications are the same as those in District Method 100.1. However, the tester may use calibration gas certified to an analytical accuracy of ±2 percent if calibration gases with analytical accuracies of ±1 percent are not available.

e. Conduct an NH3 interference test if NH3 is present. Use NH3 calibration gas at 80-100 percent of the allowed NH3 concentration.

f. Conduct Special District Method 7.1 (IC Alternative) tests simultaneously with the Modified District 100.1 tests during at least two runs. Collect at least six NOx bulbs during each run. Take at least two field blanks each testing day.

3.5  District Method 2.1 shall be used to determine the stack gas

     volumetric flow rate.



3.6  For District Method 2.1, District Method 1.1 shall be used

     to select the sampling site and the number of traverse points.



3.7  District Method 3.1 shall be used for diluent gas (O2 or CO3)

     concentration and stack gas density determination.



3.8  District Method 4.1 shall be used for moisture determination

     of the stack gas.



3.9  The NOx emissions shall be determined by using the results

     of paragraph 3.3 or 3.4 along with the results of paragraphs 3.5,

     3.6, 3.7, and 3.8.



3.10  Suitable methods may be used to measure the net MWH produced

      at each boiler, unit, or approved alternative or advanced combustion

      resource provided the following conditions are met:

a. The owner or operator of each affected boiler, unit, or approved alternative or advanced combustion resource shall submit details of suitable methods to measure the net MWH of electricity produced of each boiler, unit, or approved alternative or advanced combustion resource. At a minimum, these details shall include a description of the principle of measurement and calculations used to calculate the net MWH of electricity produced, and the technique and procedures used to calibrate each net MWH measurement device. Each net MWH meter shall be calibrated against standards which are traceable to National Institute of Standards and Technology (NIST) standards or to a higher authority if no NIST standards exist. The calibration accuracy tolerance of each net MWH measurement device shall be ±0.5 percent of all measured values. The methods submitted to the District shall be subject to the approval of the Executive Officer before they are used to determine the net MWH of electricity produced.

b. Each net MWH measurement device shall be calibrated a minimum of once every six months.

4. REPORTING PROCEDURES

4.1  Interim Reporting Procedures



4.1.1  From July 19, 1991 until December 31, 1992, the owner or

       operator will be allowed to use an interim procedure for data

       reporting and storage.  The owner or operator shall submit as

       part of the required CEMS plan, a plan for interim data reporting

       and storage.  The plan shall be subject to the approval of the

       Executive Officer and shall, at a minimum, meet the requirements

       of Paragraphs 4.1.2, 4.1.3, and 4.1.4.



4.1.2  All the data required in Paragraphs 4.1.3 and 4.1.4 shall

       be available at an identified location to the Executive Officer,

       upon request.  This location shall be subject to the approval

       of the Executive Officer.



4.1.3  For each affected boiler, unit, or approved alternative

       or advanced combustion resource the following information shall

       be provided to the Executive Officer:

a. Calendar dates covered in the reporting period.

b. Each daily emission rate (lb NOx/day) and each hourly emission rate (lb NOx/hour).

c. Identification of the boiler, unit, or approved alternative or advanced combustion resource operating days for which a sufficient number of valid data points has not been taken; reasons for not taking sufficient data; and a description of corrective action taken.

d. Identification of Fd factor for each type of fuel used for calculations and the type of fuel burned.

e. Identification of times when daily averages have been obtained by manual sampling methods.

f. Identification of times when daily averages have been obtained by alternate means of NOx emission rate data generation.

g. Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with the performance specifications in Rule 218.

h. Results of daily CEMS drift tests and quarterly accuracy assessments, as required under 40 CFR Part 60, Appendix F, Procedure 1.

i. Identification of the times when the pollutant concentration exceeded full span of the CEMS.

j. The daily net MWH of electricity produced.

k. The hourly unit-specific emission limit (lb NOx/net MWH of electricity produced.

l. The hourly lb NOx/net MWH of electricity produced.

4.1.4  The following information for the entire utility system

       shall be provided to the Executive officer on a monthly basis:

a. Calendar dates covered in the reporting period.

b. The sum of the daily emission rates (lb NOx/day) from all affected boilers, units, and approved alternative or advanced combustion resources.

c. The sum of the net MWH of electricity produced from all affected boilers, units, and approved alternative or advanced combustion resources.

d. The systemwide daily NOx emission rate (lb NOx per net MWH of electricity produced) expressed as a ratio of the sum of the daily emission rates from all boilers, units, and approved alternative or advanced combustion resources divided by the sum of the net MWH produced from all affected boilers, units, and approved alternative or advanced combustion resources.

4.1.5  All data required by Paragraphs 2.1, 2.2, 2.3, 2.4, 2.5,

       4.1.3, and 4.1.4 shall be recorded and transmitted to the District

       in a format specified by the Executive Officer.



4.2  Final Reporting Procedures



4.2.1  On and after January 1, 1993, the RTU installed at each

       location shall constitute the reporting requirements.



4.2.2  On and after January 1, 1993, all or part of the interim

       data storage systems shall remain as continuous backup systems.



4.2.3  An alternate backup data storage system may be implemented,

       upon request.  The owner or operator shall submit an Alternate

       Backup Data Storage Plan for the approval of the Executive Officer.

5. INTERIM MEASUREMENT PROCEDURES

5.1  Until December 31, 1992, the requirements of Paragraphs 2.19,

     2.19.1, 2.19.2, 2.19.3, 2.19.4, 2.19.5, 2.19.6, 2.19.7, 2.19.8,(volumetric

     flow rate audit methods) 3.5, 3.6, 3.7, 3.8, and 3.9 (relative

     accuracy test methods) will be waived until such time as the required

     source testing facilities meeting the requirements of Paragraph

     2.14 have been installed.  The owner or operator shall submit

     as a part of the required CEMS plan, construction plans and a

     schedule for the installation of each new testing facility.  The

     plan shall be submitted for the approval of the Executive Officer

     prior to installation.  Prior to the completion of the testing

     facility for each emission source, the owner or operator shall

     submit a test plan for flow rate relative accuracy testing.  Within

     30 days after completion of the testing facilities (or 30 days

     of initial start-up thereafter), the required relative accuracy

     tests shall be completed.  Sixty days thereafter, the owner or

     operator shall meet the requirements of Paragraphs 2.19, 2.19.1,

     2.19.2, 2.19.3, 2.19.4, 2.19.5, 2.19.6, 2.19.7, and 2.19.8 using

     the reference methods in Paragraphs 3.5, 3.6, 3.7, 3.8, and 3.9

     for relative accuracy test methods.



5.2  From July 19, 1991 to December 31, 1992, the data recorded

     by the system approved for Paragraph 4.1 shall be the data of

     record to determine if the CEMS meets the required performance

     specifications.

 

5.3  After December 31, 1992, the backup data system shall be the

     data of record to determine if the CEMS meets the required performance

     specifications.  The backup system and the RTU system shall produce

     identical data.



5.4  Each orifice used to measure the fuel gas flow rate shall

     be removed from the gas supply line for an inspection once every

     15 months.  The following items shall be subject to inspection:

a. Each orifice shall be visually inspected for any nicks, dents, corrosion, erosion, or any other signs of damage according to the orifice manufacturer's specifications.

b. The diameter of each orifice shall be measured using the method recommended by the orifice manufacturer.

c. The flatness of the orifice shall be checked according to the orifice manufacturer's instructions. The departure from flatness of an orifice plate shall not exceed 0.010 inch per inch of dam height (D-d/2) along any diameter. Here D is the inside pipe diameter and d is the orifice diameter at its narrowest constriction.

d. The pressure gauge or other device measuring pressure drop across the orifice shall be calibrated against a manometer, and shall be replaced if it deviates more than ±2 percent across the range.

e. The surface roughness shall be measured using the method recommended by the orifice manufacturer. The surface roughness of an orifice plate shall not exceed 50 microinches.

f. The upstream edge of the measuring orifice shall be square and sharp so that it will not show a beam of light when checked with an orifice gauge.

g. In centering orifice plates, the orifice shall be concentric with the inside of the meter tube or fitting. The concentricity shall be maintained within 3 percent of the inside diameter of the tube or fitting along all diameters.

h. Any other calibration tests specified by the orifice manufacturer shall be conducted at this time.

5.5  If an orifice fails to meet any of the manufacturer's specifications,

     it shall be replaced within two weeks.

6. ALTERNATIVE PROCEDURES

6.1 Emission Stack Flow Rate Determination

In the event that more than one boiler vents to a common stack, the alternative reference method for determining individual boiler flow rates shall be EPA Method 19. This method may be used for applicable boilers before and after the interim period mentioned in Section 4.1. The orifice plates used in every boiler vented to a common stack shall meet the requirements in Paragraph 5.4.

7. COGENERATION SYSTEMS

7.1  Cogeneration units must also measure and record the useful

     thermal energy along with the other measurements required in previous

     sections of this document.  The measurements must meet the following

     conditions:

a. The owner or operator of each affected cogeneration unit must submit details of suitable methods to measure the useful thermal energy. At a minimum, these details shall include a description of all the measurement devices, including but not limited to flow meters, pressure measurement devices, and temperature measurement devices, the calculations used to calculate the useful thermal energy, and the technique and procedures used to calibrate each measurement device. Each measurement device shall be calibrated against standards which are traceable to NIST standards or to a higher authority if no NIST standards exist. The calibration accuracy tolerance of each measurement device shall be ± 1 per cent of all measured values. All measurement devices shall measure and record one data point each minute. The methods submitted to the District shall be subject to the approval of the Executive Officer before they are used for NOx emission deductions mentioned in (b)(2)(B).

b. Each measurement device shall be calibrated a minimum of once every six months.