SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

(Adopted October 15, 1993)(Amended March 10, 1995)(Amended December 7, 1995)

(Amended July 12, 1996)(Amended February 14, 1997)

RULE 2002. - ALLOCATIONS FOR OXIDES OF NITROGEN (NOx) AND OXIDES OF SULFUR (SOx)

(a) Purpose
The purpose of this rule is to establish the methodology for calculating facility Allocations for Oxides of Nitrogen (NOx) and Oxides of Sulfur (SOx).

(b) RECLAIM Allocations

  1. RECLAIM Allocations will begin in 1994.
  2. An annual Allocation will be assigned to each facility for each compliance year starting from 1994.
  3. Allocations for each year after 2003 are equal to the facility's ending Allocation, as determined pursuant to subdivision (e) unless, as part of the AQMP process, and pursuant to Rule 2015 (b)(1), (b)(3), (b)(4), or (c), the District Governing Board determines that additional reductions are necessary to meet air quality standards, taking into consideration the current and projected state of technology available and cost-effectiveness to achieve further emission reductions.
  4. The Facility Permit or relevant sections thereof shall be re-issued at the beginning of each compliance year to include allocations determined pursuant to subdivisions (c), (d), (e), and (f) and any RECLAIM Trading Credits (RTC) obtained pursuant to Rule 2007 - Trading Requirements for the next fifteen years thereafter and any other modifications approved or required by the Executive Officer.

(c) Establishment of Starting Allocations

  1. The starting Allocation for RECLAIM NOx and SOx facilities initially permitted by the District prior to October 15, 1993, shall be determined by the Executive Officer utilizing the following methodology:

    Starting Allocation=  [A X B1] + ERCs + External Offsets where:

     
    A = the throughput for each NOx and SOx source or process unit in the facility for the maximum throughput year from 1989 to 1992 inclusive; and
    B1 = the applicable starting emission factor for the subject source or process unit as specified in Table 1 or Table 2
  2. (A) Use of 1992 data is subject to verification and revision by the Executive Officer or designee to assure validity and accuracy.

    (B) The maximum throughput year will be determined by the Executive Officer or designee from throughput data reported through annual emissions reports submitted pursuant to Rule 301 - Permit Fees, or may be designated by the permit holder prior to issuance of the Facility Permit.

    (C) To determine the applicable starting emission factor in Table 1 or Table 2, the Executive Officer or designee will categorize the equipment at each facility based on information relative to hours of operation, equipment size, heating capacity, and permit information submitted pursuant to Rule 201 - Permit to Construct, and other relevant parameters as determined by the Executive Officer or designee. No information used for purposes of this subparagraph may be inconsistent with any information or statement previously submitted on behalf of the facility to the District, including but not limited to information and statements previously submitted pursuant to Rule 301 - Permit Fees, unless the facility can demonstrate, by clear and convincing documentation, that such information or statement was inaccurate.

    (D) Throughput associated with each piece of equipment or NOx or SOx source will be multiplied by the starting emission factors specified in Table 1 or Table 2. If a lower emission factor was utilized for a given piece of equipment or NOx or SOx source pursuant to Rule 301 - Permit Fees, than the factor in Table 1 or Table 2, the lower factor will be used for determining that portion of the Allocation.

    (E) Fuel heating values may be used to convert throughput records into the appropriate units for determining Allocations based on the emission factors in Table 1 or Table 2. If a different unit basis than set forth in Tables 1 and 2 is needed for emissions calculations, the Executive Officer shall use a default heating value to determine source emissions, unless the Facility Permit holder can demonstrate with substantial evidence to the Executive Officer that a different value should be used to determine emissions from that source.

  3. All NOx and SOx ERCs held by a RECLAIM Facility Permit holder shall be reissued as RTCs. RECLAIM facilities will have these RTCs added to their starting Allocations. RTCs generated from the conversion of ERCs shall have a zero rate of reduction for the year 1994 through the year 2000. Such RTCs shall have a cumulative rate of reduction for the years 2001, 2002, and 2003, equal to the percentage inventory adjustment factor applied to 2003 Allocations pursuant to paragraph (e)(1) of this rule.
  4. Non-RECLAIM facilities may elect to have their ERCs converted to RTCs and listed on the RTC Listing maintained by the Executive Officer or designee pursuant to Rule 2007 - Trading Requirements, so long as the written request is filed before July 1, 1994. Such RTCs will be assigned to the trading zone in which the generating facility is located. RTCs generated from the conversion of ERCs shall have a zero rate of reduction for the year 1994 through the year 2000. Such RTCs shall have a cumulative rate of reduction for the years, 2001, 2002, and 2003, equal to the percentage inventory adjustment factor applied to 2003 Allocations pursuant to paragraph (e)(1) of this rule.
  5. External offsets provided pursuant to Regulation XIII - New Source Review, not including any offsets in excess of a 1 to 1 ratio, will be added to the starting Allocation pursuant to paragraph (c)(1) provided:

    (A) The offsets were not received from either the Community Bank or the Priority Reserve.

    (B) External offsets will only be added to the starting Allocation to the extent that the Facility Permit holder demonstrates that they have not already been included in the starting Allocation or as an ERC. RTCs issued for external offsets shall not include any offsets in excess of a 1 to 1 ratio required under Regulation XIII - New Source Review.

    (C) RTCs generated from the conversion of external offsets shall have a zero rate of reduction for the year 1994 through the year 2000. These RTCs shall have a cumulative rate of reduction for the years 2001, 2002, and 2003, equal to the percentage inventory adjustment factor applied to 2003 Allocations pursuant to paragraph (e)(1) of this rule.

    (D) Existing facilities with units that have Permits to Construct issued pursuant to Regulation II - Permits, dated on or after January 1, 1992, or existing facilities which have, between January 1, 1992 and October 15, 1993, installed air pollution control equipment that was exempt from offset requirements pursuant to Rule 1304 (a)(5), shall have their starting Allocations increased by the total external offsets provided, or the amount that would have been offset if the exemption had not applied.

    (E) Existing facilities with units whose reported emissions are below capacity due to phased construction, and/or where the Permit to Operate issued pursuant to Regulation II - Permits, was issued after January 1, 1992, shall have their starting Allocations increased by the total external offsets provided.

  6. If a Facility Permit holder can demonstrate that its 1994 Allocation is less than the 1992 emissions reported pursuant to Rule 301 - Permit Fees, and that the facility was, in 1992, operating in compliance with all applicable District rules in effect as of December 31, 1993, the facility's starting Allocation will be equal to the 1992 reported emissions.
  7. For new facilities initially totally permitted on or after January 1, 1993 but prior to October 15, 1993, the starting Allocation shall be equal to the external offsets provided by the facility to offset emission increases at the facility pursuant to Regulation XIII - New Source Review, not including any offsets in excess of a 1 to 1 ratio.
  8. The Allocation for new facilities initially totally permitted on and after October 15, 1993, shall be equal to the total RTCs provided by the facility to offset emission increases at the facility pursuant to Rule 2005- New Source Review for RECLAIM.
  9. The starting Allocation for facilities which enter the RECLAIM program pursuant to Rule 2001 - Applicability, shall be determined by the methodology in paragraph (c)(1) of this rule. The most recent two years reported emission fee data filed pursuant to Rule 301 - Permit Fees, may be used if 1989 through 1992 emission fee data is not available. For facilities lacking reported emission fee data, the Allocation shall be equal to the external offsets provided pursuant to Regulation XIII - New Source Review, not including any offsets in excess of a 1 to 1 ratio. The Allocation shall not include any emission offsets received from either the Community Bank or the Priority Reserve.
  10. A facility may not receive more than one set of Allocations.
  11. A facility that is no longer holding a valid District permit on January 1, 1994 will not receive an Allocation, but may, if authorized by Regulation XIII, apply for ERCs.
  12. Clean Fuel Adjustment to Starting Allocation
    Any refiner who is required to make modifications to comply with CARB Phase II reformulated gasoline production (California Code of Regulations, Title 13, Sections 2250, 2251.5, 2252, 2260, 2261, 2262, 2262.2, 2262.3, 2262.4, 2262.5, 2262.6, 2262.7, 2263, 2264, 2266, 2267, 2268, 2269, 2270, and 2271) or federal requirements (Federal Clean Air Act, Title II, Part A, Section 211; 42 U.S.C. Section 7545) may receive (an) increase(s) in his Allocations except to the extent that there is an increase in maximum rating of the new or modified equipment. Each facility requesting an increase to Allocations shall submit an application for permit amendment specifying the necessary modifications and tentative schedule for completion. The Facility Permit holder shall establish the amount of emission increases resulting from the reformulated gasoline modifications for each year in which the increase in Allocations is requested. The increase to its Allocations will be issued contemporaneously with the modification according to a schedule approved by the Executive Officer or designee (i.e., 1994 through 1997 depending on the refinery). Each increase to the Allocations shall be equal to the increased emissions resulting from the modifications solely to comply with the state or federal reformulated gasoline requirements at the refinery or facility producing hydrogen for reformulated gasoline production, and shall be established according to present and future compliance limits in current District rules or permits. Allocation increases for each refiner pursuant to this paragraph, shall not exceed 5 percent of the refiner's total starting Allocation, unless any refiner emits less than 0.0135 tons of NOx per thousand barrels of crude processed, in which case the Allocation increases for such refiner shall not exceed 20 percent of that refiner's starting Allocation. The emissions per amount of crude processed will be determined on the basis of information reported to the District pursuant to Rule 301 - Permit Fees, for the same calendar year as the facility's peak activity year for their NOx starting Allocation.

(d) Establishment of Year 2000 Allocations

  1. (A) The year 2000 Allocations for RECLAIM NOx and SOx facilities will be determined by the Executive Officer or designee utilizing the following methodology:
    Year 2000 Allocation =  [A X B2] + RTCs created from ERCs + External Offsets,
    where

    A = the throughput for each NOx or SOx source or process unit in the facility for the maximum throughput year from 1987 to 1992, inclusive, as reported pursuant to Rule 301 - Permit Fees; and
    B2 = the applicable Tier I year Allocation emission factor for the subject source or process unit, as specified in Table 1 or Table 2.

    (B) The maximum throughput year will be determined by the Executive Officer or designee from throughput data reported through annual emissions reports pursuant to Rule 301 - Permit Fees, or may be designated by the permit holder prior to issuance of the Facility Permit.

    (C) To determine the applicable emission factor in Table 1 or Table 2, the Executive Officer or designee will categorize the equipment at each facility based on information on hours of operation, equipment size, heating capacity, and permit information submitted pursuant to Rule 201 - Permit to Construct, and other parameters as determined by the Executive Officer or designee. No information used for purposes of this subparagraph may be inconsistent with any information or statement previously submitted on behalf of the facility to the District including but not limited to information and statements previously submitted pursuant to Rule 301 - Permit Fees, unless the facility can demonstrate, by clear and convincing documentation, that such information or statement was inaccurate.

    (D) Throughput associated with each piece of equipment or NOx or SOx source will be multiplied by the Tier I emission factor specified in Table 1 or Table 2. If a factor lower than the factor in Table 1 or Table 2 was utilized for a given piece of equipment or NOx or SOx source pursuant to Rule 301, the lower factor will be used for determining that portion of the Allocation.

    (E) The fuel heating value may be considered in determining Allocations and will be set to 1.0 unless the Facility Permit holder demonstrates that it should receive a different value.

    (F) The year 2000 Allocation is the sum of the resulting products for each piece of equipment or NOx or SOx source multiplied by any inventory adjustment pursuant to paragraph (d)(4) of this rule.

  2. For facilities existing prior to October 15, 1993 which enter RECLAIM after October 15, 1993, the year 2000 Allocation will be determined according to paragraph (d)(1). The most recent two years reported emission fee data filed pursuant to Rule 301 - Permit Fees, may be used if 1989 through 1992 emission fee data is not available. For facilities lacking reported emission fee data, the Allocation shall be equal to their external offsets provided pursuant to Regulation XIII - New Source Review, not including any offsets in excess of a 1 to 1 ratio.
  3. No facility shall have a year 2000 Allocation [calculated pursuant to subdivision (d)] greater than the starting Allocation [calculated pursuant to subdivision (c)].
  4. If the sum of all RECLAIM facilities' year 2000 Allocations differs from the year 2000 projected inventory for these sources under the 1991 AQMP, the Executive Officer or designee will establish a percentage inventory adjustment factor that will be applied to adjust each facility's year 2000 Allocation. The inventory adjustment will not apply to RTCs generated from ERCs or external offsets.

(e) Allocations for the Year 2003

  1. The 2003 Allocations will be determined by the Executive Officer or designee applying a percentage inventory adjustment to reduce each facility's unadjusted year 2000 Allocation so that the sum of all RECLAIM facilities' 2003 Allocations will equal the 1991 AQMP projected inventory for RECLAIM sources for the year 2003, corrected based on actual facility data reviewed for purposes of issuing Facility Permits and to reflect the highest year of actual Basin-wide economic activity for RECLAIM sources considered as a whole during the years 1987 through 1992.
  2. No facility shall have a 2003 Allocation (calculated pursuant this subdivision) greater than the year 2000 Allocation [calculated pursuant to subdivision (d)].

(f) Annual Allocations for NOx and SOx

  1. Allocations for the years between 1994 and 2000, for RECLAIM NOx and SOx facilities shall be determined by a straight line rate of reduction between the starting Allocation and the year 2000 Allocation. For the years 2001 and 2002, the Allocations shall be determined by a straight line rate of reduction between the year 2000 and year 2003 Allocations. Allocations for each year after 2003 are equal to the facility's ending Allocation, as determined pursuant to subdivision (e) , unless as part of the AQMP process, and pursuant to Rule 2015 (b)(1), (b)(3), (b)(4), or (c), the District Governing Board determines that additional reductions are necessary to meet air quality standards, taking into consideration the current and projected state of technology available and cost-effectiveness to achieve further emission reductions.
  2. New facilities initially totally permitted, on and after October 15, 1993, shall not have a rate of reduction. The Facility Permit for such facilities will require the Facility Permit holder to, at the commencement of each compliance year, hold RTCs equal to the amount of RTCs provided as offsets pursuant to Rule 2005.
  3. Increases to Allocations for permits issued for Clean Fuel adjustments pursuant to paragraph (c)(12), shall be added to each year's Allocation.

(g) High Employment/Low Emissions (HILO) Facility
The Executive Officer or designee will establish a HILO bank funded with the following maximum total annual emission Allocations:

  1. 91 tons per year of NOx
  2. 91 tons per year of SOx
  3. After January 1, 1997, new facilities may apply to the HILO bank in order to obtain non-tradeable RTCs. Requests will be processed on a first-come, first-served basis, pending qualification.
  4. When credits are available, annual Allocations will be granted for the year of application and all subsequent years.
  5. HILO facilities receiving such Allocations from the HILO bank must verify their HILO status on an annual basis through their APEP report.
  6. Failure to qualify will result in all subsequent years' credits being returned to the HILO bank.
  7. Facilities failing to qualify for the HILO bank Allocations may reapply at any time during the next or subsequent compliance year when credits are available.

(h) Non-Tradeable Allocation Credits

  1. Any existing RECLAIM facility with reported emissions pursuant to Rule 301 - Permit Fees, in either 1987, 1988, or 1993, greater than its starting Allocation, shall be assigned non-tradeable credits for the first three years of the program which shall be determined according to the following methodology:
    Non-tradeable credit for NOx and SOx:

    Year 1

    =

    (  [A X B1])

    - 1995 Allocation;

    Where:

    A = the throughput for each NOx or SOx source or process unit in the facility from the single maximum throughput year from 1987, 1988, or 1993; and

    B1 = the applicable starting emission factor, as specified in Table 1 or Table 2.

    Year 2 = Year 1 non-tradeable credits X 0.667

    Year 3 = Year 1 non-tradeable credits X 0.333

    Year 4 and
    subsequent years
    = Zero non-tradeable credit.

  2. The use of non-tradeable credits shall be subject to the following requirements:

    (A) Non-tradeable credits may only be used for an increase in throughput over that used to determine the facility's starting Allocation. Non-tradeable credits may not be used for emissions increases associated with equipment modifications, change in feedstock or raw materials, or any other changes except increases in throughput. The Executive Officer or designee may impose Facility Permit conditions necessary to ensure compliance with this subparagraph.

    (B) The use of activated non-tradeable credits shall be subject to a non-tradeable RTC mitigation fee, as specified in Rule 301 subdivision (n).

    (C) In order to utilize non-tradeable credits, the Facility Permit holder shall submit a request to the Executive Officer or designee in writing, including a demonstration that the use of the non-tradeable credits complies with all requirements of this paragraph, pay any fees required pursuant to Rule 301 - Fees, and have received written approval from the Executive Officer or designee for their use. The Executive Officer or designee shall deny the request unless the Facility Permit holder demonstrates compliance with all requirements of this paragraph. The Executive Officer or designee shall, in writing, approve or deny the request within three business days of submittal of a complete request and notify the Facility Permit holder of the decision. If the request is denied, the Executive Officer or designee will refund the mitigation fee.

    (D) In the event that a facility transfers any RTCs for the year in which non-tradeable credits have been issued, the non-tradeable credit Allocation shall be invalid, and is no longer available to the facility.

    Table 1

    RECLAIM NOx Emission Factors

    Nitrogen Oxides
    Basic Equipment

    Fuel

    "Throughput" Units

    Starting Ems Factor *

    Ending Ems Factor *

    Afterburner (Direct Flame and Catalytic) Natural Gas mmcf

    130.000

    39.000
    Afterburner (Direct Flame and Catalytic) LPG, Propane, Butane 1000 Gal RV

    3.840

    Afterburner (Direct Flame and Catalytic) Diesel 1000 Gal RV

    5.700

    Agr Chem-Nitric Acid Process-Absrbr Tailgas/Nw tons pure acid produced RV

    1.440

    Agricultural Chem - Ammonia Process tons produced RV

    1.650

    Air Ground Turbines Air Ground Turbines (unknown process units) RV

    1.860

    Ammonia Plant Neutralizer Fert, Ammon Nit tons produced RV

    2.500

    Asphalt Heater, Concrete Natural Gas mmcf

    130.000

    65.000
    Asphalt Heater, Concrete Fuel Oil 1000 gals RV

    9.500

    Asphalt Heater, Concrete LPG 1000 gals RV

    6.400

    Boiler, Heater R1109 (Petr Refin) Natural Gas mmbtu

    0.100

    0.030
    Boiler, Heater R1109 (Petr Refin) Fuel Oil mmbtu

    0.100

    0.030
    Boiler, Heater R1146 (Petr Refin) Natural Gas mmbtu

    0.045

    0.045
    Boiler, Heater R1146 (Petr Refin) Fuel Oil mmbtu

    0.045

    0.045
    Boiler, Heater R1146 (Petr Refin) Refinery Gas mmbtu

    0.045

    0.045
    Boilers, Heaters, Steam Gens Rule 1146 and 1146.1 Natural Gas mmcf

    49.180

    47.570
    Boilers, Heaters, Steam Gens Rule 1146 and 1146.1 LPG, Propane, Butane 1000 gals

    4.400

    4.260
    Boilers, Heaters, Steam Gens Rule 1146 and 1146.1 Diesel Light Dist. (0.05% S) 1000 gals

    6.420

    6.210
    Boilers, Heaters, Steam Gens Rule 1146 and 1146.1 Refinery Gas mmcf

    51.520

    49.840
    Boilers, Heaters, Steam Gens Bituminous Coal tons burned RV

    4.800

    Boiler, Heater, Steam Gen (Rule 1146.1) Natural Gas mmcf

    130.000

    39.460
    Boiler, Heater, Steam Gen (Rule 1146.1) Refinery Gas mmcf RV

    41.340

    * RV = Reported Value
    ** Does not include ceramic, clay, cement or brick kilns or metal melting, heat treating or glass melting furnaces.
    *** Applies retroactively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.

    Nitrogen Oxides
    Basic Equipment

    Fuel

    "Throughput" Units

    Starting Ems Factor *

    Ending Ems Factor *

    Boiler, Heater, Steam Gen (Rule 1146.1) LPG, Propane, Butane 1000 gallons RV

    3.530

    Boiler, Heater, Steam Gen (Rule 1146.1) Diesel Light Dist (0.05%) 1000 gallons RV

    5.150

    Boiler, Heater, Steam Gen (Rule 1146) Natural Gas mmcf

    47.750

    47.750
    Boiler, Heater, Steam Gen (Rule 1146) Refinery Gas mmcf

    50.030

    50.030
    Boiler, Heater, Steam Gen (Rule 1146) LPG, Propane, Butane 1000 gallons

    4.280

    4.280
    Boiler, Heater, Steam Gen (Rule 1146) Diesel Light Dist (0.05%) 1000 gallons

    6.230

    6.230
    Boiler, Heater, Steam Gen (R1146, <90,000 Therms) Natural Gas mmcf RV

    47.750

    Boiler, Heater, Steam Gen (R1146, <90,000 Therms) Refinery Gas mmcf RV

    50.030

    Boiler, Heater, Steam Gen (R1146, <90,000 Therms) LPG, Propane, Butane 1000 gallons RV

    4.280

    Boiler, Heater, Steam Gen (R1146, <90,000 Therms) Diesel Light Dist (0.05%) 1000 gallons RV

    6.230

    Boiler, Heater, Steam Gen (R1146.1, <18,000 Therms) Natural Gas mmcf RV

    39.460

    Boiler, Heater, Steam Gen (R1146.1, <18,000 Therms) Refinery Gas mmcf RV

    41.340

    Boiler, Heater, Steam Gen (R1146.1, <18,000 Therms) LPG, Propane, Butane 1000 gallons RV

    3.530

    Boiler, Heater, Steam Gen (R1146.1, <18,000 Therms) Diesel Light Dist (0.05%) 1000 gallons RV

    5.150

    Boiler, Heater R1109 (Petr Refin) Refinery Gas mmbtu

    0.100

    0.030
    Boilers, Heaters, Steam Gens, (Petr Refin) Natural Gas mmcf

    105.000

    31.500
    Boilers, Heaters, Steam Gens, (Petr Refin) Refinery Gas mmcf

    110.000

    33.000
    Boilers, Heaters, Steam Gens, Unpermitted Natural Gas mmcf

    130.000

    32.500
    Boilers, Heaters, Steam Gens, Unpermitted LPG, Propane, Butane 1000 gallons RV

    3.200

    Boilers, Heaters, Steam Gens (New or Modified, and subject to BACT, after the start year as determined pursuant to Rule 2002(c)(1)) Natural Gas mmcf

    38.460

    38.460

    * RV = Reported Value
    ** Does not include ceramic, clay, cement or brick kilns or metal melting, heat treating or glass melting furnaces.
    *** Applies retroactively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.

    Nitrogen Oxides

    Basic Equipment

    Fuel

    "Throughput" Units

    Starting Ems Factor *

    Ending Ems Factor *

    Boilers, Heaters, Steam Gens (New or Modified, and subject to BACT, after the start year as determined pursuant to Rule 2002(c)(1)) Refinery Gas mmbtu

    0.035

    0.035
    Boilers, Heaters, Steam Gens (New or Modified, and subject to BACT, after the start year as determined pursuant to Rule 2002(c)(1)) LPG, Propane, Butane 1000 gallons

    3.55

    3.55
    Boilers, Heaters, Steam Gens (New or Modified, and subject to BACT, after the start year as determined pursuant to Rule 2002(c)(1)) Diesel Light Dist (0.05%), Fuel Oil No. 2 mmbtu

    0.03847

    0.03847
    Boilers, Heaters, Steam Gens, Unpermitted Diesel Light Dist (0.05%) 1000 gallons RV

    4.750

    Catalyst Manufacturing Catalyst Mfg tons of catalyst produced RV

    1.660

    Catalyst Manufacturing Catalyst Mfg tons of catalyst produced RV

    2.090

    Cement Kilns Natural Gas mmcf

    130.000

    19.500
    Cement Kilns Diesel Light Dist. (0.05% S) 1000 gals RV

    2.850

    Cement Kilns Kilns-Dry Process tons cement produced RV

    0.750

    Cement Kilns Bituminous Coal tons burned RV

    4.800

    Cement Kilns Tons Clinker tons clinker RV

    2.73***

    Ceramic and Brick Kilns (Preheated Combustion Air) Natural Gas mmcf

    213.000

    170.400
    Ceramic and Brick Kilns (Preheated Combustion Air) Diesel Light Distillate (.05%) 1000 gallons RV

    24.905

    Ceramic and Brick Kilns (Preheated Combustion Air) LPG 1000 gallons RV

    16.778

    Ceramic Clay Mfg Drying tons input to process RV

    1.114

    CO Boiler Refinery Gas mmbtu

    0.030

    Cogen, Industr Coke tons burned RV

    3.682

    Electric Generation, Commercial Institutional Boiler Distillate Oil 1000 gallons

    6.420

    6.210
    Composite Internal Combustion Waste Fuel Oil 1000 gals burned RV

    31.340

    Curing and Drying Ovens Natural Gas mmcf

    130.000

    32.500

    * RV = Reported Value
    ** Does not include ceramic, clay, cement or brickkilns or metal melting, heat treating or glass melting furnaces.
    *** Applies retroactively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.

    Nitrogen Oxides Basic Equipment

    Fuel

    "Throughput" Units

    Starting Ems Factor *

    Ending Ems Factor *

    Curing and Drying Ovens LPG, Propane, Butane 1000 gals RV

    3.200

    Delacquering Furnace Natural Gas mmcf 182.2*** 182.2***
    Fiberglass Textile-Type Fibr tons of material processed RV

    1.860

    Fluid Catalytic Cracking Unit Fresh Feed 1000 BBLS fresh feed RV

    RV*0.3 ***

    Fluid Catalytic Cracking Unit with Urea Injection Fresh Feed 1000 BBLS fresh feed RV

    (RV*0.3) / (1-control efficiency) ***

    Fugitive Emission Not Classified tons product RV

    0.087

    Furnace Process Carbon Black tons produced RV

    38.850

    Furnace Suppressor Furnace Suppressor unknown RV

    0.800

    Glass Fiber Furnace Mineral Products tons product produced RV

    4.000

    Glass Melting Furnace Flat Glass tons of glass pulled RV

    4.000

    Glass Melting Furnace Tableware Glass tons of glass pulled RV

    5.680

    Glass Melting Furnaces Container Glass tons of glass produced

    4.000

    1.2***
    ICEs, Permitted (Rule 1110.1 and 1110.2) Natural Gas mmcf

    2192.450

    217.360
    ICEs Permitted (Rule 1110.2) Natural Gas mmcf RV

    217.360

    ICEs, Permitted (Rule 1110.1 and 1110.2) LPG, Propane, Butane 1000 gals RV

    19.460

    ICEs, Permitted (Rule 1110.1 and 1110.2) Gasoline 1000 gals RV

    20.130

    ICEs, Permitted (Rule 1110.1 and 1110.2) Diesel Oil 1000 gals RV

    31.340

    ICEs, Exempted per Rule 1110.2 All Fuels

    RV RV
    ICEs, Exempted per Rule 1110.2 and subject to Rule 1110.1 All Fuels

    RV RV
    ICEs, Unpermitted All Fuels

    RV RV
    In Process Fuel Coke tons burned RV

    24.593

    Incinerators Natural Gas mmcf

    130.000

    104.000
    Industrial Propane 1000 gallons RV

    20.890

    Industrial Gasoline 1000 gallons RV

    21.620

    Industrial Dist.Oil/Diesel 1000 gallons RV

    33.650

    Inorganic Chemicals, H2SO4 Chamber General tons pure acid produced RV

    0.266

    * RV = Reported Value
    ** Does not include ceramic, clay, cement or brick kilns or metal melting, heat treating or glass melting furnaces.
    *** Applies retroactively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.

    Nitrogen Oxides Basic Equipment

    Fuel

    "Throughput"Units

    Starting Ems Factor*

    Ending Ems Factor *

    Inorganic Chemicals, H2SO4 Contact Absrbr 98.0% Conv tons 100% H2S04 RV

    0.376

    Iron/Steel Foundry Steel Foundry, Elec Arc Furn tons metal processed RV

    0.045

    Metal Heat Treating Furnace Natural Gas mmcf

    130.000

    104.000
    Metal Heat Treating Furnace Diesel Light Distillate (.05%) 1000 gallons RV

    15.200

    Metal Heat Treating Furnace LPG 1000 gallons RV

    10.240

    Metal Forging Furnace (Preheated Combustion Air) Natural Gas mmcf

    213.000

    170.400
    Metal Forging Furnace (Preheated Combustion Air) Diesel Light Distillate (.05%) 1000 gallons RV

    24.905

    Metal Forging Furnace (Preheated Combustion Air) LPG 1000 gallons RV

    16.778

    Metal Melting Furnaces Natural Gas mmcf

    130.000

    65.000
    Metal Melting Furnaces LPG, Propane, Butane 1000 gals RV

    6.400

    Miscellaneous

    bbls-processed RV

    1.240

    Natural Gas Production Not Classified mmcf gas RV

    6.320

    Nonmetallic Mineral Sand/Gravel tons product RV

    0.030

    NSPS Refinery Gas mmbtu RV

    0.030

    Other Bact Heater (24F-1) Natural Gas mmcf RV RV
    Other Heater (24F-1) Pressure Swing Absorber Gas mmcf RV RV
    Ovens, Kilns, Calciners, Dryers, Furnaces** Natural Gas mmcf

    130.000

    65.000
    Ovens, Kilns, Calciners, Dryers, Furnaces** Diesel Light Dist. (0.05% S) 1000 gals RV

    9.500

    Paint Mfg, Solvent Loss Mixing/Blending tons solvent RV

    45.600

    Petroleum Refining Asphalt Blowing tons of asphalt produced RV

    45.600

    Petroleum Refining, Calciner Petroleum Coke Calcined Coke RV

    0.971***

    Plastics Prodn Polyester Resins tons product RV

    106.500

    Pot Furnace Lead Battery lbs Niter

    0.077***

    0.062***
    Process Specific ID# 012183 (unknown process units) RV

    240.000

    Process Specific SCC 30500311 tons produced RV

    0.140

    * RV = Reported Value
    ** Does not include ceramic, clay, cement or brick kilns or metal melting, heat treating or glass melting furnaces.
    *** Applies retroactively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.

    Nitrogen Oxides Basic Equipment

    Fuel

    "Throughput" Units

    Starting Ems Factor*

    Ending Ems Factor *

    Process Specific ID 14944 (unknown process units) RV

    0.512

    SCC 39090003

    RV

    170.400

    Sec. Aluminum Sweating Furnace tons produced RV

    0.300

    Sec. Aluminum Smelting Furnace tons metal produced RV

    0.323

    Sec. Aluminum Annealing Furnace mmcf

    130.000

    65.000
    Sec. Aluminum Boring Dryer tons produced RV

    0.057

    Sec. Lead Smelting Furnace tons metal charged RV

    0.110

    Sec. Lead Smelting Furnace tons metal charged RV

    0.060

    Sodium Silicate Furnace Water Glass Tons Glass Pulled RV

    6.400

    Steel Hot Plate Furnace Natural Gas mmcf

    213.000

    106.500
    Steel Hot Plate Furnace Diesel Light Distillate (.05%) 1000 gallons

    31.131

    10.486
    Steel Hot Plate Furnace LPG, Propane, Butane 1000 gallons

    20.970

    10.486
    Surface Coal Mine Haul Road tons coal RV

    62.140

    Tail Gas Unit

    hours of operation RV RV
    Turbines Butane 1000 Gallons RV

    5.700

    Turbines Diesel Oil 1000 gals RV

    8.814

    Turbines Refinery Gas mmcf RV

    62.275

    Turbines Natural Gas mmcf RV

    61.450

    Turbines - Peaking Unit Natural Gas mmcf RV RV
    Turbines - Peaking Unit Dist. Oil/Diesel 1000 gallons RV RV
    Utility Boiler Digester/Landfill Gas mmcf

    52.350

    10.080
    Turbine Natural Gas mmcf RV

    61.450

    Turbine Fuel Oil 1000 gallons RV

    8.810

    Turbine Dist.Oil/Diesel 1000 gallons RV

    3.000

    Utility Boiler Burbank Natural Gas mmcf

    148.670

    17.200
    Utility Boiler Burbank Residual Oil 1000 gallons

    20.170

    2.330
    Utility Boiler, Glendale Natural Gas mmcf

    140.430

    16.000
    Utility Boiler, Glendale Residual Oil 1000 gallons

    20.160

    2.290
    Utility Boiler, LADWP Natural Gas mmcf

    86.560

    15.830
    Utility Boiler, LADWP Residual Oil 1000 gallons

    12.370

    2.260
    Utility Boiler, LADWP Digester Gas mmcf

    52.350

    10.080
    Utility Boiler, LADWP Landfill Gas mmcf

    37.760

    6.910
    Utility Boiler, Pasadena Natural Gas mmcf

    195.640

    18.500
    Utility Boiler, Pasadena Residual Oil 1000 gallons

    28.290

    2.670
    Utility Boiler, SCE Natural Gas mmcf

    74.860

    15.600
    Utility Boiler, SCE Residual Oil 1000 gallons

    10.750

    2.240

    * RV = Reported Value
    ** Does not include ceramic, clay, cement or brick kilns or metal melting, heat treating or glass melting furnaces.
    *** Applies retroactively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.

    Table 2

    RECLAIM SOx Emission Factors

    Sulfur Oxides
    Basic Equipment

    Fuel

    "Throughput" Units

    Starting Emission Factor *

    Ending Emission Factor *

    Air Blown Asphalt

    hours of operation

    RV

    RV
    Asphalt Concrete Cold Ag Handling tons produced

    RV

    0.032
    Calciner Petroleum Coke Calcined Coke

    RV

    0.000
    Catalyst Regeneration

    hours of operation

    RV

    RV
    Cement Kiln Distillate Oil 1000 gallons

    RV

    RV
    Cement Mfg Kilns, Dry Process tons produced

    RV

    RV
    Claus Unit

    pounds

    RV

    RV
    Cogen Coke pounds per ton

    RV

    RV
    Non Fuel Use

    hours of operation

    RV

    RV
    External Combustion Equipment / Incinerator Natural Gas mmcf

    RV

    0.830
    External Combustion Equip/Incinerator LPG, Propane, Butane 1000 gallons

    RV

    4.600
    External Combustion Equip/Incinerator Diesel Light Dist. (0.05% S) 1000 gallons

    7.00

    5.600
    External Combustion Equip/Incinerator Residual Oil 1000 gallons

    8.00

    6.400
    External Combustion Equip/Incinerator Refinery Gas mmcf

    RV

    6.760
    Fiberglass Recuperative Furn, Textile-Type Fiber tons produced

    RV

    2.145
    Fluid Catalytic Cracking Units

    1000 bbls refinery feed

    RV

    13.700
    Glass Mfg, Forming/Fin Container Glass

    RV

    RV
    Grain Milling Flour Mill tons Grain Processed

    RV

    RV
    ICEs Natural Gas mmcf

    RV

    0.600
    ICEs LPG, Propane, Butane 1000 gallons

    RV

    0.350
    ICEs Gasoline 1000 gallons

    RV

    4.240
    ICEs Diesel Oil 1000 gallons

    6.24

    4.990
    Industrial Cogeneration, Bituminous Coal tons produced

    RV

    RV
    Industrial (scc 10200804) Cogeneration, Coke tons produced

    RV

    RV
    Inorganic Chemcals General, H2SO4 Chamber tons produced

    RV

    RV
    Inorganic Chemcals Absrbr 98.0% Conv, H2SO4 Contact tons produced

    RV

    RV

    * RV = Reported Value
    *** Applies retroactively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.

    Sulfur Oxides
    Basic Equipment

    Fuel

    "Throughput" Units

    Starting Emission Factor *

    Ending Emission Factor *

    Inprocess Fuel Cement Kiln/Dryer, Bituminous Coal tons produced

    RV

    RV
    Iron/Steel Foundry Cupola, Gray Iron Foundry tons produced

    RV

    0.720
    Melting Furnace, Container Glass

    tons produced

    RV

    RV
    Mericher Alkyd Feed

    hours of operation

    RV

    RV
    Miscellaneous Not Classified tons produced

    RV

    0.080
    Miscellaneous Not Classified tons produced

    RV

    0.399
    Natural Gas Production Not Classified mmcf

    RV

    527.641
    Organic Chemical (scc 30100601)

    tons produced

    RV

    RV
    Petroluem Refining (scc30600602) Column Condenser

    RV

    1.557
    Petroluem Refining (scc30600603) Column Condenser

    RV

    1.176
    Refinery Process Heaters LPG fired 1000 gal

    RV

    2.259
    Pot Furnace Lead Battery lbs Sulfur

    0.133***

    0.106***
    Sec. Lead Reverberatory, Smelting Furnace tons produced

    RV

    RV
    Sec. Lead Smelting Furnace, Fugitiv tons produced

    RV

    0.648
    Sour Water Oxidizer

    hours of operation

    RV

    RV
    Sulfur Loading

    1000 bbls

    RV

    RV
    Sour Water Oxidizer

    1000 bbls fresh feed

    RV

    RV
    Sour Water Coker

    1000 bbls fresh feed

    RV

    RV
    Sodium Silicate Furnace

    tons of glass pulled

    RV

    RV
    Sulfur Plant

    hours of operation

    RV

    RV
    Tail gas unit

    hours of operation

    RV

    RV
    Turbines Refinery Gas mmcf

    RV

    6.760
    Turbines Natural Gas mmcf

    RV

    0.600
    Turbines Diesel Oil 1000 gal

    6.24

    4.990
    Other Heater ( 24F-1) Pressure Swing Absorber Gas mmcf

    RV

    RV

    * RV = Reported Value
    *** Applies retroactively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.