Cal. Code Regs. tit. 17, § 95113 – Petroleum Refineries.

(a) CO₂ from Fossil Fuel Combustion. When calculating CO₂ emissions from fuel combustion under subpart C as specified at 40 CFR § 98.252(a), the operator must use a method in 40 CFR § 98.33(a)(1) to § 98.33(a)(4) as specified by fuel type in section 95115 of this article. CO₂ emissions from refinery fuel gas combustion must be calculated using a Tier 3 or Tier 4 methodology of subpart C, as specified in 40 CFR § 98.252(a).
(b) Monitoring, Data and Records. For each emissions calculation method chosen under section 95113(a), the operator must meet the applicable requirements for monitoring, missing data procedures, data reporting, and records retention that are specified in 40 CFR § 98.34 to § 98.37, except as modified in sections 95113(k), 95115, and 95129 of this article.
(c) Refinery Fuel Gas Sampling. As required by 40 CFR § 98.34(b)(3)(ii)(E), in cases where equipment necessary to perform daily sampling and analysis of carbon content and molecular weight for refinery fuel gas is not in place, such equipment must be installed and procedures established to implement daily sampling and analysis no later than January 1, 2013.
(d) Calculating CO₂from Flares. For periods of normal flare operation, the operator must use Equation Y-1a, Y-1b, or Y-2 as specified in 40 CFR § 98.253(b)(ii)(A) or 98.253(b)(ii)(B). For periods of startup, shutdown, and malfunction (SSM) during which the operator was unable to measure the parameters required by Equations Y-1a, Y-1b, or Y-2, the operator must determine the quantity of gas discharged to the flare separately for each SSM, and calculate the CO₂ emissions as specified in the equation shown below. For SSM periods the operator must use engineering calculations and process knowledge to estimate the carbon content of flared gas as required by § 98.253(b)(iii)(A). The terms of the equation below are defined as they are for Equation Y-3 in 40 CFR § 98.253(b)(iii)(C).
(e) Calculating CO₂from FCCUs and Fluid Coking. The requirements of 40 CFR § 98.253(c)(2) apply under this article regardless of the rated capacity of a fluid catalytic cracking unit or a fluid coking unit. The operator may not use Equation Y-8 or the option provided under 40 CFR § 98.253(c)(3) for units with rated capacities of 10,000 barrels per stream day or less.
(f) Uncontrolled Blowdown Systems. When calculating CH₄ emissions for uncontrolled blowdown systems as required by 40 CFR § 98.253(k), the operator must use the methods for process vents in 40 CFR § 98.253(j).
(g) Data Reporting Requirements for Flares. When the operator has calculated flare emissions for SSM periods using the modified equation specified in section 95113(d), the operator reporting data under the requirements of 40 CFR § 98.256(e)(8) must report only the total number of SSM events, the volume of gas flared, and the average molecular weight and carbon content of the flare gas for each SSM event, using the units specified.
(h) Data Reporting Requirements for FCCUs and Coking Units. When the operator has calculated CO₂ from fluid catalytic cracking units or fluid coking units consistent with section 95113(e), the operator shall not report the data required by 40 CFR § 98.256(f)(9).
(i) Data Reporting Requirements for Uncontrolled Blowdown Systems. When the operator has calculated CH₄ from uncontrolled blowdown systems consistent with section 95113(g), the operator must report the information required for process vents in 40 CFR § 98.256(l), as applicable, in lieu of the information required by 40 CFR § 98.256(m)(2).
(j) Records that must be retained. In addition to the requirements of 40 CFR § 98.257, for each process vent for which the concentration of CO₂, N₂O and CH₄ are determined to be below the thresholds in 40 CFR § 98.253(j), the operator must maintain records of the method used to determine the CO₂, N₂O, and CH₄ concentrations, and all supporting documentation necessary to demonstrate that the thresholds in 40 CFR § 98.253(j) are not exceeded during the data year pursuant to the record keeping requirements of section 95105.
(k) Missing Data Substitution Procedures. The operator must comply with 40 CFR § 98.255 when substituting for missing data, except as otherwise provided in paragraphs (1)-(2) below.
1. (1) To substitute for missing data for emissions reported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems), the operator must follow the requirements of section 95129 of this article.
2. (2) For all other data required for emissions calculations in this section, the operator must follow the requirements of paragraphs (A)-(C) below.
  1. (A) If the analytical data capture rate is at least 90 percent for the data year, the operator must substitute for each missing value using the best available estimate of the parameter, based on all available process data.
  2. (B) If the analytical data capture rate is at least 80 percent but not at least 90 percent for the data year, the operator must substitute for each missing value with the highest quality assured value recorded for the parameter during the given data year, as well as the two previous data years.
  3. (C) If the analytical data capture rate is less than 80 percent for the data year, the operator must substitute for each missing value with the highest quality assured value recorded for the parameter in all records kept according to section 95105(a).
(l) Additional Product and Process Data.
1. (1) Refinery Products. For each material in Table 2-1, as defined in the U.S. Energy Information Administration Glossary (May 27, 2016), which is hereby incorporated by reference, the operator must report the annual on-site production amount and the annual amount of product produced elsewhere and brought on-site. Amounts must be reported in standard cubic feet for gaseous products, barrels for liquid products, and short tons for solid products. The methods for reporting production and receipts on Part 5 of the federal Energy Information Agency's Form EIA-810 that are described by the Monthly Refinery Report Instructions for Form EIA-810 (Revised 2013), which is hereby incorporated by reference, must be used to report on-site production amounts and amounts produced elsewhere and brought on-site. These reported on-site production quantities and quantities of material produced elsewhere and brought on-site are not covered product data and will not be subject to review for material misstatement under the requirements of section 95131(b)(12).
2. (2) Calcined coke. The operator must report the annual mass (metric tons) of calcined coke produced on-site during the data year. The operator must specify whether the calciner is integrated with the petroleum refinery operation.
3. (3) Complexity Weighted Barrel (CWB) Calculation.
  1. (A) Reporting CWB Throughputs. The operator must report the annual throughput for each CWB unit in Table 2-2 of this section using the units specified in Table 2-2 of this section. Liquid throughput volumes must be reported at standard conditions of 60 °F and atmospheric pressure. The volume correction from nonstandard conditions must be calculated by the methods described in the American Petroleum Institute (API) Manual of Petroleum Measurement Standards Chapter 11 -- Physical Properties Data (May 2004), the American Society of Testing and Materials Standard Guide for Use of the Petroleum Measurement Tables, ASTM D1250-08 (Reapproved 2013)) or the American Petroleum Institute Technical Data Book (-- Petroleum Refining (Sixth Edition, April 1997), all three of which are hereby incorporated by reference, or by comparable means that can be demonstrated to a verifier to be consistent with these standard methods. Reported throughputs based on feed must include only fresh feed and exclude recycled streams, except for reported throughputs for the CWB units “C4 Isomer Production” and “C5/C6 Isomer Production -- including ISOSIV,” which may include recycled material. The coke-on-catalyst volume percent also must be reported for each catalytic cracking unit. Beginning with data year 2013, CWB throughputs are considered covered product data and subject to the accuracy requirements of section 95103(k).
  2. (B) Total facility CWB. The total facility CWB production must be calculated according to the following formula.
    CWB_Total = CWB_Process + CWB_Off-Sites + CWB_{Non-Crude Sensible Heat}
    Where CWB_Total is the total complexity weighted barrels for a petroleum refinery, and CWB_Process, CWB_Off-Sites, and CWB_{Non-Crude Sensible Heat} must be calculated as follows:
    CWB_Process = Σ(CWB_Factor x Throughput)
    CWB_Off-Sites = (0.327) x (Total Refinery Input in thousands of barrels per year) + (0.0085) x (CWB_Process)
    CWB_{Non-Crude Sensible Heat} = (0.44) x (Non-Crude Input in thousands of barrels per year)
    In these equations, CWB_Factor is the CWB Factor for a CWB unit from Table 2-2 of this section. Throughput is the process throughput for each CWB unit identified in Table 2-2 of this section reported pursuant to section 95113(l)(3)(A). Total Refinery Input and Non-Crude Input are the annual volumes of raw materials as defined in section 95102(c) and must be reported in units of thousands of barrels per year. Total facility CWB is covered product data and subject to material misstatement evaluation during verification.
  3. (C) Correction to CWB_Factorfor Fluid Catalytic Cracking. The following equation must be used to adjust CWB_Factor for Fluid Catalytic Cracking (FCC) units and mild residual FCC units that result in coke on the catalyst:
    CWB_Factor,FCC = CWB_Factor + (A x COC)
    Where:
    CWB_Factor,FCC = The corrected CWB factor used to calculate the contribution to CWB_Process for a fluid catalytic cracking unit.
    CWB_Factor = The uncorrected CWB factor for a catalytic cracking unit from Table 2-2 of this section.
    A = The coke-on-catalyst factor for a fluid catalytic cracking unit listed in the fourth column of Table 2-2 of this section.
    COC = The coke-on-catalyst volume percent reported to three significant figures and calculated by:
    COC = 100 x (Volume of coke consumed in the FCC)/(Volume of fresh feed to the FCC)
  4. (D) Density. In cases where a density measurement is needed for purposes of converting a throughput from barrel to mass units, the following applies:
    1. 1. For a throughput with a known density, utilize the applicable default value from Section 3-1, Physical Constants of Organic Compounds, of the CRC Handbook of Chemistry and Physics, CRC Press Inc., Boca Raton 83^rd Edition, 2002 - 2003, incorporated herein by reference;
    2. 2. If the throughput density is not known, it must be determined following the requirements of section 95103(k).
  5. (E) Measurement Accuracy. All throughputs must follow the accuracy requirements outlined in sections 95103(k)(1)-(10). No single refinery activity may be reported under more than one CWB function.
(m) Reporting to Support the Cost of Implementation Fee Regulation. The operator must report the volume of:
1. (1) CARBOB, as defined by “California reformulated gasoline blendstock for oxygenate blending” in section 95202 of the AB 32 Cost of Implementation Fee Regulation, produced and imported for use in California and the designated volume of oxygenate associated with the reported CARBOB;
2. (2) Finished California gasoline, as defined by “California gasoline” in section 95202 of the AB 32 Cost of Implementation Fee Regulation, produced and imported for use in California; and
3. (3) California Diesel, as defined by “California diesel fuel” in section 95202 of the AB 32 Cost of Implementation Fee Regulation, produced and imported for use in California and the volume of biodiesel and/or renewable diesel associated with the reported fuels.
  Table 2-1. Refinery Products
  Product
  EIA Product Code
  Petroleum Coke, Marketable
  021
  Still Gas
  045
  NGPL and LRG - Ethane/Ethylene, TOTAL (includes EIA Product Codes 631 and 641)
  108
  Finished Aviation Gasoline
  111
  Aviation Gasoline Blending Components
  112
  Motor Gasoline Blending Components - Gasoline Treated as Blendstock
  117
  Motor Gasoline Blending Components - Reformulated Blendstock for Oxygenate Blending (RBOB)
  118
  Finished Motor Gasoline - Reformulated, Blended with Fuel Ethanol
  125
  Finished Motor Gasoline - Reformulated, Other
  127
  Finished Motor Gasoline - Conventional, Other
  130
  Motor Gasoline Blending Components - All Other Motor Gasoline Blending Components
  138
  Motor Gasoline Blending Components - Conventional Blendstock for Oxygenate Blending (CBOB)
  139
  Renewable Fuels - Fuel Ethanol
  141
  Finished Motor Gasoline - Conventional, Blended with Fuel Ethanol (Greater than Ed55)
  149
  Finished Motor Gasoline - Conventional, Blended with Fuel Ethanol (Ed55 and Lower)
  166
  Renewable Fuels - Biomass-Based Diesel Fuel
  203
  Renewable Fuels - Other Renewable Diesel Fuel
  205
  Renewable Fuels - Other Renewable Fuels
  207
  Kerosene-Type Jet Fuel, TOTAL (includes EIA Product Codes 217 and 218)
  213
  NGPL and LRG^* - Pentanes Plus
  220
  NGPL and LRG^* - Butane/Butylene, TOTAL (includes EIA Product Codes 249, 633, and 643)
  244
  NGPL and LRG^* - Isobutane/Isobutylene, TOTAL (includes EIA Product Codes 247, 634 and 644)
  245
  NGPL and LRG^* - Propane/Propylene, TOTAL (includes EIA Product Codes 632 and 642)
  246
  Kerosene
  311
  Distillate Fuel Oil - Ultra Low Sulfur (sulfur content < 15 ppm)
  465
  Distillate Fuel Oil - Low Sulfur (15 ppm ≤ sulfur content ≤ 500 ppm)
  466
  Distillate Fuel Oil - High Sulfur (sulfur content > 500 ppm)
  467
  Residual Fuel Oil, TOTAL (includes EIA Product Codes 508, 509, and 510)
  511
  Unfinished Oils - Naphthas and Lighter
  820
  Petrochemical Feedstocks - Naphtha, end-point < 401 °F
  822
  Petrochemical Feedstocks - Other Oils, end-point ≥ 401 °F
  824
  Unfinished Oils - Kerosene and Light Gas Oils
  830
  Unfinished Oils - Heavy Gas Oils
  840
  Unfinished Oils - Residuum
  850
  Lubricants, TOTAL (includes EIA Product Codes 852 and 853)
  854
  Asphalt and Road Oil
  931
  * NGPL and LRG = Natural Gas Plant Liquids and Liquefied Refinery Gases
  Table 2-2. CWB Units and Factors
  CWB Unit
  Throughput Basis
  Unit of Measure
  CWB Factor
  EIA Number
  Process Subtypes
  Atmospheric Crude Distillation
  Feed
  thousands of barrels/year
  1
  401
  Mild Crude Unit, Standard Crude Unit
  Vacuum Distillation
  Feed
  thousands of barrels/year
  0.91
  402
  Mild Vacuum Fractionation, Standard Vacuum Column, Vacuum Fractionating Column, Vacuum Flasher Column,
  Heavy Feed Vacuum Unit
  Visbreaker
  Feed
  thousands of barrels/year
  1.6
  403
  Processing Atmospheric Residual (w/o a Soaker Drum), Processing Atmospheric Residual (with a Soaker Drum), Processing Vacuum Bottoms Feed (w/o a Soaker Drum), Vacuum Bottoms Feed (with a Soaker Drum)
  Delayed Coker
  Feed
  thousands of barrels/year
  2.55
  405
  Delayed Coking
  Fluid Coker
  Feed
  thousands of barrels/year
  10.3
  404
  Fluid Coking
  Flexicoker
  Feed
  thousands of barrels/year
  23.6
  Flexicoking
  1.150,
  Fluid Catalytic Cracking
  Feed
  thousands of barrels/year
  Coke-on-Catalyst Factor = 1.041
  407
  Fluid Catalytic Cracking (Feed ConCarbon <2.25 wt%)
  0.6593,
  Mild Residual FCC
  Feed
  thousands of barrels/year
  Coke-on-Catalyst Factor = 1.1075
  Mild Residualuum Catalytic Cracking (Feed ConCarbon 2.25-3.5 wt %)
  Other FCC
  Feed
  thousands of barrels/year
  4.65
  Houdry Catalytic Cracking
  Other FCC
  Feed
  Thermofor Catalytic Cracking
  Thermal Cracking
  Feed
  thousands of barrels/year
  2.95
  406
  Thermal Cracking
  Naphtha/Distillate Hydrocracker
  Feed
  thousands of barrels/year
  3.15
  439/440
  Mild Hydrocracking (Normally less than 1,500 psig and consumes between 100 and 1,000 SCF H2)
  Severe Hydrocracking
  Naphtha Hydrocracking
  Residual Hydrocracker (H-Oil; LC-Fining and Hycon)
  Feed
  thousands of barrels/year
  4.4
  441
  H-Oil
  LC-Fining^TM and Hycon
  Naphtha Hydrotreater
  Feed
  thousands of barrels/year
  0.91
  420/425/426
  Benzene Saturation
  Desulfurization of C4-C6 Feeds
  Conventional Naphtha Hydrotreating
  Diolefin to Olefin Saturation of Gasoline
  FCC Gasoline Hydrotreating with Minimum Octane Loss
  Olefinic Alkylation of Thio Sulfur
  Selective Hydrotreating of Pyrolysis Gasoline/Naphtha Combined with Desulfurization
  Pyrolysis Gasoline/Naphtha Desulfurization
  Selective Hydrotreating of Pyrolysis Gasoline/Naphtha Combined with Desulfurization
  Reactor for Selective Hydrotreating
  S-Zorb™ Process
  Aromatic Saturation of Kerosene
  Kerosene Hydrotreater
  Feed
  thousands of barrels/year
  0.75
  421
  Conventional Hydrotreating of Kerosene/Jet Fuel
  High Severity Hydrotreating Kerosene/Jet Fuel
  Aromatic Saturation of Distillates
  Conventional Distillate Hydrotreating
  High Severity Distillate Hydrotreating
  Diesel/Selective Hydrotreater
  Feed
  thousands of barrels/year
  0.9
  422/423
  Ultra-High Severity Hydrotreating
  Middle Distillate Dewaxing
  S-Zorb™ Process
  Diolefin to Olefin Saturation of Alkylation Feed
  Selective Hydrotreating of C3-C5 Streams for Alkylation
  Residual Hydrotreater
  Feed
  thousands of barrels/year
  1.8
  424
  Desulfurization of Atmospheric Residual
  Desulfurization of Vacuum Residual
  VGO Hydrotreater
  Feed
  thousands of barrels/year
  1
  413
  Hydrodesulfurization/denitrification
  Hydrodesulfurization
  Reformer - including AROMAX
  Feed
  thousands of barrels/year
  3.5
  430/431
  Continuous Regeneration, Cyclic, Semi-Regenerative, and AROMAX
  Solvent Deasphalter
  Feed
  thousands of barrels/year
  2.8
  432
  Conventional Solvent, Supercritical Solvent
  C5+ Alkylate
  Alkylation with Hydrofluoric Acid
  Alkylation with Sulfuric Acid
  Alkylation/Poly/Dimersol
  C5+ Product
  thousands of barrels/year
  5
  415
  Polymerization C3 Olefin Feed
  Polymerization C3/C4 Feed
  Dimersol
  C4 Isomer Production
  Feed
  thousands of barrels/year
  1.25
  615/644
  C4 Isomerization
  C5/C6 Isomer Production - including ISOSIV
  Feed
  thousands of barrels/year
  1.8
  438
  C5/C6 Isomerization
  ISOSIV
  POX Syngas for Fuel
  Product
  millions of standard cubic feet/year¹
  2.75
  POX Syngas for Fuel
  POX Syngas for Fuel
  Air Separation Unit
  Sulfur Recovery
  Product Sulfur
  thousands of long tons/year
  140
  435
  Sulfur Recovery Unit
  Tail Gas Recovery Unit
  Sulfur Sprung
  H2S Springer Unit
  Aromatics Solvent Extraction: Extraction Distillation
  Aromatics Solvent Extraction: Liquid/Liquid Extraction
  Aromatics Production (All)
  Feed
  thousands of barrels/year
  3.3
  437
  Aromatics Solvent Extraction: Liq/Liq w/ Extr. Distillation
  Benzene Column
  Toluene Column
  Xylene Rerun Column
  Heavy Aromatics Column
  Hydrodealkylation
  Feed
  thousands of barrels/year
  2.5
  Hydrodealkylation
  Toluene Disproportionation/Transalkylation
  Feed
  thousands of barrels/year
  1.9
  Toluene Disproportionation / Transalkylation
  Cyclohexane production
  Cyclohexane Product
  thousands of barrels/year
  2.8
  Cyclohexane
  Xylene Isomerization
  Feed
  thousands of barrels/year
  1.9
  Xylene Isomerization
  Paraxylene Production
  Paraxylene Product
  thousands of barrels/year
  6.5
  Paraxylene Adsorption
  thousands of barrels/year
  Paraxylene Crystallization
  Feed
  thousands of barrels/year
  Xylene Splitter
  thousands of barrels/year
  Orthoxylene Rerun Column
  Ethylbenzene Production
  Ethylbenzene Product
  thousands of barrels/year
  1.6
  Ethylbenzene Manufacture
  Feed
  thousands of barrels/year
  Ethylbenzene Distillation
  Cumene Production
  Cumene Product
  thousands of barrels/year
  5
  Cumene
  Lubricant Solvent Extraction
  Feed
  thousands of barrels/year
  2.2
  815/854
  Extraction: Solvent is Duo-Sol, Furfural, NMP, Phenol, or SO2
  Lubricant Solvent Dewaxing
  Feed
  thousands of barrels/year
  4.55
  Dewaxing: Solvent is Chlorocarbon, MEK/Toluene, MEK/MIBK, or Propane
  Lubricant Catalytic Dewaxing
  Feed
  thousands of barrels/year
  1.6
  Catalytic Wax Isomerization and Dewaxing, Selective Wax Cracking
  Lubricant Hydrocracking
  Feed
  thousands of barrels/year
  2.5
  Lube Hydrocracker with Multifraction Distillation, Lube Hydrocracker with Vacuum Stripper
  Lubricant Wax Deoiling
  Product
  thousands of barrels/year
  11.8
  Deoiling: Solvent is Chlorocarbon, MEK/Toluene, MEK/MIBK, or Propane
  Lube Hydrofinishing with Vacuum Stripper
  Lubricant and Wax Hydrofining
  Feed
  thousands of barrels/year
  1.15
  Lube Hydrotreating with Multi-Fraction Distillation, Lube Hydrotreating Vacuum Stripper
  Wax Hydrofinishing with Vacuum Stripper, Wax Hydrotreating with Multi-Fraction Distillation, Wax Hydrotreating with Vacuum Stripper
  Asphalt Production
  Total Asphalt Production
  thousands of barrels/year
  2.7
  931
  Asphalt Production
  Distillation Units
  Oxygenates
  Product
  thousands of barrels/year
  4.9
  Extraction Units
  ETBE
  TAME
  Methanol Synthesis
  Product
  thousands of barrels/year
  -36
  Methanol Synthesis
  Desalination
  Product
  millions of gallons/year
  32.7
  Desalination
  (Water)
  Special Fractionation
  Feed
  thousands of barrels/year
  0.8
  All Special Fractionation ex Solvents, Propylene, and Aromatics
  Propane/Propylene Splitter (Propylene Production)
  Feed
  thousands of barrels/year
  2.1
  Chemical Grade
  Polymer Grade
  Fuel Gas Sales Treating & Compression (hp)
  Horsepower
  hp
  0.92
  Fuel Gas Sales Treating & Compression
  Ammonia Recovery Unit
  Product
  thousands of short tons/year
  453
  Ammonia Recovery Unit: PHOSAM
  Cryogenic LPG Recovery
  Feed
  millions of standard cubic feet/year
  0.25
  Cryogenic LPG Recovery
  Flare Gas Recovery
  Feed
  millions of standard cubic feet/year
  0.13
  Flare Gas Recovery
  Flue Gas Desulfurizing
  Feed
  millions of standard cubic feet/year
  0.02
  Flue Gas Desulfurizing
  CO2 Liquefaction
  CO2 product
  thousands of short tons/year
  -160
  .
  CO2 Liquefaction
  ¹ Standard cubic feet are dry @ 60° F and 14.696 psia or 15 °C and 1 atmosphere.

The operator of a facility who is required to report under section 95101 of this article, and who is not eligible for abbreviated reporting under section 95103(a), must comply with Subpart Y of 40 CFR Part 98 (40 CFR §§ 98.250 to 98.258) in reporting emissions and other data from petroleum refineries to ARB, except as otherwise provided in this section. Petroleum refinery operators and refiners are considered separate reporting entities for the purposes of this article.

Note: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health and Safety Code.

History

1. New section filed 12-2-2008; operative 1-1-2009 (Register 2008, No. 49).

2. Amendment of section heading, section and Note filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).

3. Amendment of subsection (l)(1), new subsection (l)(1)(A) and amendment of subsection (l)(2) filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).

4. Amendment filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).

5. Repealer of subsections (l)(1)(A) and (l)(3)(C), new subsections (l)(1)-(2), subsection renumbering, amendment of newly designated subsections (l)(3)(A) and (l)(5)-(l)(5)(B), new subsections (l)(5)(C)-(m)(3) and amendment of Table 1 filed 12-31-2014; operative 1-1-2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).

6. Amendment of subsections (k)(2), (l)(1)-(2), repealer of subsections (l)(3)-(4), subsection relettering, amendment of newly designated subsections (l)(3)(A)-(C) and (l)(3)(E), and amendment of subsections (m)-(m)(3), including new table 2-1 and renumbering and amendment of former table 2-1 as table 2-2, filed 9-1-2017; operative 1-1-2018 (Register 2017, No. 35).