2002 - 1

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

(Amended July 12, 1996)(Amended February 14, 1997) (Amended May 11, 2001)

(Amended January 7, 2005)(Amended November 5, 2010)

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 and adjustments to RTC holdings 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 and RTC holdings for each year after 2011 are equal to the

2011 Allocation and RTC holdings, as determined pursuant to 

subdivision (f) 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:
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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.
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(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 generated at the facility and 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 and shall have a rate of reduction 

for compliance year 2004 and subsequent years determined pursuant to 

paragraph (f)(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 
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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, and for compliance year 2004 and 

subsequent years allocations shall be determined pursuant to 

paragraph (f)(1) of this rule. The rate of reduction for the year 

2001 through year 2003 shall not be applied to new facilities 

initially totally permitted on or after January 7, 2005.

(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 
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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 existing 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 
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2002 - 6

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 NOxstarting 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 
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2002 - 7

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 
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2002 - 8

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 and Adjustments to NOx RTC Holdings

(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. SOx Allocations for each year after 2003 are equal to the 

facility’s 2003 Allocations, as determined pursuant to subdivision (e). 

NOx Allocations for 2004, 2005, and 2006 and SOx Allocations for 

2004 through 20112 are equal to the facility’s 2003 Allocation, as 

determined pursuant to subdivision (e). NOx RTC Allocations and 

holdings subsequent to the year 2006 and SOx Allocations and 

holdings subsequent to the year 20112 shall be adjusted to the nearest 

pound as follows:

(A) The Executive Officer will adjust NOx RTC holdings, as of 

January 7, 2005 for compliance years 2007 and thereafter by 

multiplying the amount of RTC holdings by the following 

adjustment factors for the relevant compliance year, to obtain 

tradable/usable and non-tradable/non-usable holdings:

Compliance

Tradable/Usable

NOx RTC

Adjustment 

Non-tTradable/

Non-uUsable NOx 
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2002 - 9

Year

2007

2008

2009

2010

2011 and after

Factor

0.883

0.856

0.829

0.802

0.775

RTC

Adjustment Factor

0

0.027

0.054

0.081

0.108

RTCs designated as non-tradable/non-usable pursuant to this 

subparagraph shall be held, but shall not be used or traded. The 

adjustment factors in this subparagraph are subject to change 

pursuant to paragraph (i)(5).

(B) Commencing on January 1, 2008 with NOx RTC prices 

averaged from January 1, 2007 through December 31, 2007, the 

Executive Officer will calculate the 12-month rolling average 

RTC price for all trades for the current compliance year. The 

Executive Officer will update the 12-month rolling average once 

per month. The computation of the rolling average prices will 

not include RTC transactions reported at no price or and RTC 

swap transactions. 

(C) Notwithstanding the requirements of non-tradable/non-usable 

credits specified in subparagraph (f)(1)(A), in the event that the 

NOx RTC prices exceed $15,000 per ton based on the 12-month 

rolling average calculated pursuant to subparagraph (f)(1)(B), 

the Executive Officer will report to the Governing Board. If the 

Governing Board finds that the 12-month rolling average RTC 

price exceeds $15,000 per ton, then the incremental NOx 

reductions as specified in subparagraph (f)(1)(D) shall be 

converted to Ttradable/Uusable NOx RTCs upon Governing 

Board concurrence. The Executive Officer’s report to the Board 

will be made at a public hearing at the earliest possible regularly 

scheduled Board Meeting, but no more than 60 days from 

Executive Officer determination.

(D) The incremental NOx RTCs restored shall be the difference 

between the Nnon-tradable/Nnon-usable Aadjustment Ffactors, 

as specified in subparagraph (f)(1)(A), of the current compliance 

year and the most recent prior year the adjustment factor was 

implemented.

(E) RTC conversion pursuant to subparagraph (f)(1)(C) shall only 
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2002 - 10

occur in the compliance year in which Cycle 1 facilities are 

operating.

(F) Notwithstanding the adjustment factors required pursuant to 

subparagraph (f)(1)(A), beginning with the following December 

and each year thereafter that the Governing Board finds the 

$15,000 per ton NOx RTC price is exceeded pursuant to 

subparagraph (f)(1)(C), the Executive Officer will publish the 

applicable adjustment factors for the next compliance year 

beginning January 1. The adjustment factors will be published 

at a public hearing during a regularly scheduled Board Meeting. 

The adjustment factors will be determined as follows:

(i) If the 12-month rolling average falls below $15,000 per 

ton for at least 6 consecutive months, then the emission

adjustment factors for the following compliance year shall 

equal the next more stringent adjustment factors listed in 

subparagraph (f)(1)(A) than the factors currently in effect; 

otherwise;

(ii) The next compliance year adjustment factors shall equal 

the compliance year adjustment factors currently in place.

The Executive Officer need no longer comply with the annual 

public hearing requirement once the adjustment factors for the 

2010 compliance year have been implemented for a 12-month 

period.

(G) The NOx RTC adjustment factors for compliance years 2008 

through 2010 shall not be submitted for inclusion into the State 

Implementation Plan until the adjustments have been in effect 

for one full compliance year. The 2011 NOx RTC adjustment 

factors shall not be submitted for inclusion into the State 

Implementation Plan until 12-months after the adjustments have 

been in effect for one full compliance year.

(H) NOx Allocations for facilities that enter RECLAIM after 

January 7, 2005 for compliance years 2007 and after shall be 

determined by applying the Tradable/Usable and NontTradable/Non-uUsable NOx RTC Adjustment Factors under 

subparagraph (f)(1)(A) to the facility’s Compliance Year 2006 

Allocation.
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2002 - 11

(I) SOx RTC Holdings as of (date of adoption) for compliance 

years 20132 and after shall be adjusted to achieve an overall 

reduction in the following amounts:

Compliance Year Minimum emission reductions

(lbs.)

2012 1,095,000

2013 2,190,000

2014 2,920,000 3,285,000

2015 2,920,000 3,518,600

2016 2,920,000 3,752,200

2017 3,650,000 3,985,800

2018 3,650,000 4,219,400

2019 and after 4,161,000 4,453,000

(J) The Executive Officer shall determine a Tradable/usable SOx 

RTC Adjustment Factors for each compliance years after 20121

as follows:

Fcompliance year i = 1 – [Xi / (Ai + Bi + Ci)]

Where:

Fcompliance year i = Tradable/usable SOx RTC Adjustment 

Factor for compliance year i starting with 20132

Ai = Total SOx RTCs for compliance year i held as of (rule 

adoption date) by all RTC holders, except those listed in 

Table 5

Bi = Total SOx RTCs for compliance year i credited to any

facilities listed in Table 5 between August 29, 2009 and 

(rule adoption date), and not includes in Ci

Ci = Total SOx RTCs held as of (rule adoption date) by 

facilities listed in Table 5 for compliance year i in excess of 

initial allocations as determined pursuant to subdivision (e).

Xi = Amount to be reduced for compliance year i starting 

with 20132 as listed in subparagraph (f)(1)(I).

(K) The Executive Officer shall determine Non-tradable/Nnonusable SOx RTC Adjustment Factors for each compliance years 

after 2014 2017 through 2019 as follows:

Ncompliance year j = Fcompliance year 20164 - Fcompliance year j

Where:

Ncompliance year j = Non-tradable/Nnon-usable SOx RTC 

Adjustment Factor for compliance year j

Fcompliance year j = Tradable/Uusable SOx RTC Adjustment 
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Factor for compliance year j as determined pursuant to 

subparagraph (f)(1)(JK)

j = 20175 through 2019

Fcompliance year 20164 = Tradable/usable SOx RTC Adjustment 

Factor for compliance year 20164 as determined pursuant to 

subparagraph (f)(1)( JK)

Non-tradable/Nnon-usable SOx RTC Adjustment Factors for 

compliance years 2012, 2013 through 2016, 2014, 2020, and all 

years after 2020 shall be 0.0.

(L) The Executive Officer shall adjust the SOx RTC holdings as of 

(date of adoption) for compliance years 20132 and after as 

follows:

(i) Apply the Tradable/Uusable SOx RTC Aadjustment 

Ffactor (Fcompliance year i ) and Non-tradable/Nnon-usable

SOx RTC Adjustment Factors (Ncompliance year j) for the 

corresponding compliance year as published under 

subparagraph (f)(1)(M) to SOx RTC holdings held by

any RTC holder except those listed in Table 5;

(ii) Apply no adjustment to SOx RTC holdings that are 

held as of August 29., 2009 by a facility listed in Table 

5, and that are less than or equal to the facility’s

allocations as determined pursuant to subdivision (e), 

and that were not credited between August 29, 2009 

and (rule adoption date);

(iii) Apply the Tradable/Uusable SOx RTC Aadjustment 

Ffactor (Fcompliance year i) and Non-tradable/Nnon-usable

SOx RTC Adjustment Factors (Ncompliance year j) for the 

corresponding compliance year as published under 

subparagraph (f)(1)(M) to any SOx RTC holding as of 

(rule adoption date), that is held by a facility that is 

listed in Table 5, and that is over the facility’s initial

allocations as determined pursuant to subdivision (e); 

and
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2002 - 13

(iv) Apply the Tradable/Uusable SOx RTC Aadjustment 

Ffactor (Fcompliance year i) and Non-tradable/non-usable

SOx RTC Adjustment Factors (Ncompliance year j) for the 

corresponding compliance year as published under 

subparagraph (f)(1)(M) to any SOx RTC holding that 

was acquired between August 29, 2009 and (rule 

adoption date) by a facility that is listed in Table 5.

(v) No SOx RTC holding shall be subject to the SOx RTC 

adjustments as published under subparagraph 

(f)(1)(M) more than once.

(M) The Executive Officer shall publish the SOx RTC Adjustment 

Factors determined according to subparagraphs (f)(1)(J) and 

(f)(1)(K) within 30 days after (date of adoption).

(N) Commencing on January 1, 20175 and ending on February 1, 

2020, the Executive Officer will calculate the 12-month rolling 

average SOx RTC price for all trades during the preceding 12 

months for the current compliance year. The Executive Officer 

will update the 12-month rolling average once per month. The 

computation of the rolling average prices will not include RTC 

transactions reported at no price or and as RTC swap 

transactions. 

(O) In the event that the SOx RTC prices exceed $50,000 per ton 

based on the 12-month rolling average calculated pursuant to 

subparagraph (f)(1)(N), the Executive Officer will report to the 

Governing Board at a duly noticed public hearing to be held no 

more than 60 days from Executive Officer determination. The 

Executive Officer will announce that determination on the 

SCAQMD website. At the public hearing, the Governing Board 

will decide whether or not to convert any portion of the Nontradable/Nnon-usable RTCs, as determined pursuant to 

subparagraphs (f)(1)(K) and (f)(1)(L), and how much to convert 

if any, to Tradable/Uusable RTCs. The portion of Nontradable/Nnon-usable RTCs available for conversion to 

Tradable/Uusable RTCs shall not include any portion of Nontradable/Nnon-usable RTCs that are designated for previous 

compliance years and has not already been converted by the

Governing Board, or that has been otherwise included in the 
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2002 - 14

State Implementation Plan pursuant to subparagraph (f)(1)(P). 

(P) The Executive Officer will not submit the emission reductions 

obtained through subparagraph (f)(1)(I) for commencing with

compliance years 20175 and through 2019 for inclusion into the 

State Implementation Plan until the adjustments for the RTC 

Holdings have been in effect for one full compliance year.

(Q) SOx Allocations for compliance years 20132 and after, for 

facilities that enter RECLAIM after (date of adoption) and for 

basic equipment listed in Table 4 shall be determined according 

to the BARCT level listed in Table 4 or the permitted emission 

limits, whichever is lower.

(R) By no later than July 1, 2012, SOx emissions at the exhaust of a 

Fluidized Catalytic Cracking Unit, as measured at the final stack 

venting gases originating from the facility’s FCC Regenerator, 

including after the CO Boiler or any additional controls in the 

system following the regenerator (the final stack shall constitute 

the only exhaust gas compliance point within the FCCU 

facility), shall not exceed a concentration of 25 ppmv dry @ 0% 

oxygen on a 365-day rolling average. The numeric 

concentration-based limit does not apply during time periods in 

which SOx data are determined to be incorrect due to analyzer 

calibration or malfunction. For the purpose of demonstrating 

compliance with this limit, the operator of a FCCU shall 

commence the use of SOx reducing additives in the FCCU no 

later than July 1, 2011, unless the operator has an existing wet 

gas scrubber in operation at BARCT levels prior to (date of 

adoption) or can demonstrate to the Executive Officer that the 

FCCU will achieve this limit by using other control methods.

(2) New facilities initially totally permitted, on and after October 15, 1993, 

but prior to January 7, 2005, and entering the RECLAIM program after 

January 7, 2005 shall not have a rate of reduction until 2001. 

Reductions from 2001 to 2003, inclusive, shall be implemented 

pursuant to subdivision (e). New facilities initially totally permitted on 

or after January 7, 2005 using external offsets shall have a rate of 

reduction for such offsets pursuant to subparagraph (c)(5)(C). New 

facilities initially totally permitted on or after January 7, 2005 using 

RTCs shall have no rate of reduction for such RTCs, provided that 
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2002 - 15

RTCs obtained have been adjusted according to paragraph (f)(1), as 

applicable. 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-tradable 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-Tradable 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-tradable credits for the first 

three years of the program which shall be determined according to the 

following methodology:

Non-tradable credit for NOx and SOx:

Year 1 = ( [A X B1]) - 1994 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 
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2002 - 16

1993; and 

B1 = the applicable starting emission factor, as specified 

in Table 1 or Table 2.

Year 2 = Year 1 non-tradable credits X 0.667

Year 3 = Year 1 non-tradable credits X 0.333

Year 4 and 

subsequent 

years

= Zero non-tradable credit.

(2) The use of non-tradable credits shall be subject to the following 

requirements:

(A) Non-tradable credits may only be used for an increase in 

throughput over that used to determine the facility's starting 

Allocation. Non-tradable 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-tradable credits shall be subject to a nontradable RTC mitigation fee, as specified in Rule 301 subdivision 

(n).

(C) In order to utilize non-tradable 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-tradable

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-tradable credits have been issued, the non-tradable

credit Allocation shall be invalid, and is no longer available to the 

facility.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 17

(i) RTC Reduction Exemption

(1) A facility may file an application for Executive Officer approval to be 

exempted from all or a portion of the requirements pursuant to 

subparagraph (f)(1)(A) with the exception of RTC holdings as of January 

7, 2005 for compliance year 2007 and thereafter in excess of the initial 

allocation. For the purposes of this rule, initial allocation refers to the 

RTCs issued by the District to a facility upon entering the RECLAIM 

program. The application shall contain sufficient data to demonstrate to 

the satisfaction of the Executive Officer that the facility meets the 

following criteria:

(A) the facility has been in the program since the start of RECLAIM,

or existed prior to 1994, but subsequently entered RECLAIM 

pursuant to Rule 2001 because facility emissions exceeded 4 tons 

per year;

(B) at least 99 percent of the facility’s emissions reported for the most 

recent completed compliance year prior to the date of filing an 

application is from equipment not listed in Table 3 and the 

achieved emission rates for each and every piece of equipment at 

the facility is less than or equal to the 2000 (Tier I) Ending 

Emission Factor listed in Table 1 or the emission factor listed in 

Table 3, whichever is lower, for the corresponding equipment 

type;

(C) RTCs that were part of the total initial allocation for the facility 

have never been transferred or sold by the facility for year 2007 

or later compliance years; and

(D) the cumulative NOx compliance costs incurred by the facility up 

to the submittal date of the application as specified in paragraph 

(i)(3) to comply with the RECLAIM Allocation as required under 

Rule 2004(b) and (d)(1) exceed the compliance costs that 

otherwise would have occurred to meet and maintain emission 

limits specified in Table 1 for each and every piece of equipment

at the facility. The compliance costs shall be based on the 

following parameters:
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 18

(i) cost of controlling emissions using the parameters and 

procedures for determining total direct and indirect capital 

investment and total annual costs as specified in the most 

recent edition of the Control Cost Manual published by 

the U.S. EPA Office of Air Quality and Planning 

Standards, excluding control costs for any equipment 

listed in Table 3, if any;

(ii) realized and anticipated revenues and expenditures of the 

Facility Permit holder resulting from buying and selling 

any RTCs that are or were held by the facility where the 

contract of sale or purchase was executed prior to the date 

of application for exemption pursuant to paragraph (i)(1);

(iii) costs associated with compliance with the New Source 

Review provisions of Rule 2005, Rule 2012(c), or other 

applicable state or federal requirements shall not be 

included;

(iv) costs that result only in improving process efficiency or 

product quality, costs of projects that were initiated before 

the date the facility was subject to RECLAIM 

requirements, or legal costs or any other costs that do not 

directly reduce NOx emissions shall not be included; and

(v) any cost savings that resulted in implementing any NOx 

emissions strategy, such as fuel savings, increased 

production or sale; or

(2) A facility may file an application for Executive Officer approval to be 

exempted from all or a portion of the requirements pursuant to 

subparagraph (f)(1)(A) for the initial allocations portion of a facility’s 

RTC holdings provided that the facility meets all of the following:

(A) The facility’s starting and year 2000 Allocations were calculated 

using the same emission factors that are equal to or lower than the 

2000 (Tier 1) emission factors listed in Table 1;

(B) Emission rate achieved for each source at the facility is less than 

or equal to the emission factors listed in Table 3 for the 

corresponding equipment type; and

(C) RTCs for 2007 or later compliance years for the facility have 

never been transferred or sold.

(3) A facility shall submit the applications specified pursuant to paragraphs 
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 19

(i)(1) or (i)(2) no later than July 7, 2005 or between January 1 and March 

31, 2006, pay the appropriate evaluation fee pursuant to Rule 306, and 

accept enforceable permit conditions to ensure compliance with the 

provisions of this subdivision, in order for the Executive Officer to 

approve the exemption. If approved, the facility’s initial RTC allocation 

shall be designated as non-tradable and additional RTCs purchased above 

the initial allocation shall be subject to the RTC adjustments specified in 

subparagraph (f)(1)(A), as appropriate. The Executive Officer shall deny 

an application that is not filed within the time periods specified in this 

paragraph, lacks any information specified under paragraph (i)(7), or fails

to demonstrate that it meets the requirements in paragraphs (i)(1) or 

(i)(2).

(4) Upon approval the exemption shall:

(A) be limited to the adjustment factors specified in subparagraph 

(f)(1)(A);

(B) begin the next compliance year following the exemption 

approval; and

(C) not apply to reductions resulting from future periodic BARCT 

review.

(5) RTC adjustments exempted pursuant to this subdivision shall be 

distributed proportionally among the remainder of the RTC holders and 

implemented two years from the compliance year of the applicable

exemption and are subject to applicable paragraph (f)(1) provisions. 

Public notification of the distributed reductions shall occur at least one

year prior to implementation.

(6) A Facility Permit holder has the right to appeal the denial of the 

exemption application to the Hearing Board in the same manner as a 

permit denial as specified in Health and Safety Code Section 42302.

(7) An application submitted to request an exemption from the RTCs 

reduction pursuant to paragraphs (i)(1) or (i)(2) shall include the 

following information. 

(A) Detailed description of each project and itemized listing of how it 

relates to meeting the RECLAIM reduction requirements; 

(B) Date of start and completion of each project listed in (A);
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 20

(C) Detailed calculations or emissions data demonstrating NOx

emission reductions resulting from each project or combination of 

projects directly resulting in reductions. The emission levels 

achieved shall be based on actual CEMS data or source tests 

results;

(D) Itemized revenue and expenditures for each RTC trading activity 

since participation in the RECLAIM program; 

(E) Itemized costs for each project and corresponding receipts or 

other equivalent documentation as approved by the Executive 

Officer for such expenditures; and

(F) Cost savings resulting from each project(s) (e.g. fuel savings, 

improved productivity, increased sales, etc.) and documentation

of the values of such savings.

(8) A facility qualifying for exemption shall report as part of its Annual 

Permit Emission Program (APEP) report, submitted pursuant to Rule 

2004(b)(4), whether or not emissions from equipment listed in Table 3, if 

any, remain less than or equal to 1 percent of the total facility emissions 

on an annual basis for the duration of the exemption. If the emissions 

exceed 1 percent, the facility shall be in violation of the rule for each and 

every day of the compliance year and the Executive Officer shall reduce 

the facility’s initial allocation for the next compliance year to the 

emissions level specified for that year pursuant to subparagraph (f)(1)(A).

(9) A facility applying for exemption shall have 1 percent of its initial 

allocations subject to the requirements pursuant to subparagraph 

(f)(1)(A).

(10) Non-tradable RTC allocations designated pursuant to paragraph (i)(3) 

shall become tradable in the event the facility permanently ceases to 

operate.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 21

Table 1

RECLAIM NOx Emission Factors

Nitrogen Oxides

Basic Equipment Fuel "Throughput" Units

Starting 

Ems 

Factor *

2000 (Tier I) 

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 ProcessAbsrbr 

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.

**** Newly installed or Modified after the year selected for maximum throughput for determining starting allocations pursuant to 

Rule 2002(c)(1), and meeting BACT limits in effect at the time of installation.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 22

Nitrogen Oxides

Basic Equipment Fuel "Throughput" Units

Starting 

Ems 

Factor *

2000 (Tier I) 

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 ****

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.

**** Newly installed or Modified after the year selected for maximum throughput for determining starting allocations pursuant 

to Rule 2002(c)(1), and meeting BACT limits in effect at the time of installation.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 23

Nitrogen Oxides

Basic Equipment Fuel "Throughput" Units

Starting 

Ems 

Factor *

2000 (Tier I)

Ending Ems 

Factor *

Boilers, Heaters, Steam 

Gens ****

Refinery Gas mmbtu 0.035 0.035

Boilers, Heaters, Steam 

Gens  

LPG, Propane, 

Butane

1000 gallons 3.55 3.55

Boilers, Heaters, Steam 

Gens ** **

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 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.

**** Newly installed or Modified after the year selected for maximum throughput for determining starting allocations pursuant 

to Rule 2002(c)(1), and meeting BACT limits in effect at the time of installation.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 24

Nitrogen Oxides Basic 

Equipment Fuel "Throughput" Units

Starting 

Ems Factor 

*

2000 (Tier I)

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**** All Fuels Equivalent 

to permitted 

BACT limit

Equivalent to 

permitted 

BACT limit

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

* 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.

**** Newly installed or Modified after the year selected for maximum throughput for determining starting 

allocations pursuant to Rule 2002(c)(1), and meeting BACT limits in effect at the time of installation.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 25

Nitrogen Oxides 

Basic Equipment Fuel "Throughput"Units

Starting 

Ems 

Factor*

2000 (Tier I)

Ending Ems 

Factor *

Industrial Dist.Oil/Diesel 1000 gallons RV 33.650

Inorganic Chemicals, 

H2SO4 Chamber

General tons pure acid 

produced

RV 0.266

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.

**** Newly installed or Modified after the year selected for maximum throughput for determining starting allocations pursuant 

to Rule 2002(c)(1), and meeting BACT limits in effect at the time of installation.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 26

Nitrogen Oxides 

Basic Equipment Fuel "Throughput" Units

Starting 

Ems 

Factor*

2000 (Tier I)

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 (micro-) Natural Gas mmcf 54.4 54.4

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.

**** Newly installed or Modified after the year selected for maximum throughput for determining starting allocations 

pursuant to Rule 2002(c)(1), and meeting BACT limits in effect at the time of installation.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 27

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.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 28

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

Petroleum Refining 

(scc30600602)

Column Condenser RV 1.557

Petroleum 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 0.080

Turbines Residual Oil 1000 gallons 8.00 0.090

Utility Boilers Diesel Light Dist. 

(0.05% S)

1000 gallons 7.00 0.080

Utility Boilers Residual Oil 1000 gallons 8.00 0.090

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.
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 29

Table 3

RECLAIM NOx 20102011 Ending Emission Factors

Nitrogen Oxides

Basic Equipment

BARCT

Emission 

Factor

Asphalt Heater, Concrete 0.036 lb/mmbtu

(30 ppm)

Boiler, Heater R1109 (Petr 

Refin) >110 mmbtu/hr

0.006 lb/mmbtu

(5 ppm)

Boilers, Heaters, Steam Gens, 

(Petr Refin) >110 mmbtu/hr

0.006 lb/mmbtu

(5 ppm)

Boiler, Heater, Steam Gen 

(Rule 1146.1) 2-20 mmbtu/hr

0.015 lb/mmbtu

(12 ppm)

Boiler, Heater, Steam Gen 

(Rule 1146) >20 mmbtu/hr

0.010 lb/mmbtu

(9 ppm)

CO Boiler 85% Reduction

Delacquering Furnace 0.036 lb/mmbtu

(30 ppm)

Fluid Catalytic Cracking Unit 85% Reduction

Iron/Steel Foundry 0.055 lb/mmbtu

(45 ppm)

Metal Heat Treating Furnace 0.055 lb/mmbtu

(45 ppm)

Metal Forging Furnace 

(Preheated Combustion Air)

0.055 lb/mmbtu

(45 ppm)

Metal Melting Furnaces 0.055 lb/mmbtu

(45 ppm)

Other Heater (24F-1) 0.036 lb/mmbtu

(30 ppm)

Ovens, Kilns, Calciners, 

Dryers, Furnaces

0.036 lb/mmbtu

(30 ppm)

Petroleum Refining, Calciner 0.036 lb/mmbtu

(30 ppm)

Sec. Aluminum 0.055 lb/mmbtu

(45 ppm)

Sec. Lead 0.055 lb/mmbtu

(45 ppm)

Steel Hot Plate Furnace 0.055 lb/mmbtu

(45 ppm)

Utility Boiler 0.008 lb/mmbtu

(7 ppm)
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 30

Table 4

RECLAIM SOx Tier III Emission Standards

Basic Equipment BARCT Emission Standard

(As Adopted on Adoption Date)

Calciner, Petroleum Coke 10 ppmv (0.11 lbs/ton coke)

Cement Kiln 5 ppmv (0.04 lbs/ton clinker)

Coal-Fired Boiler 5 ppmv (95% reduction)

Container Glass Melting Furnace 5 ppmv (0.03 lbs/ton glass)

Diesel Combustion 15 ppmv as required under Rule 431.2

Fluid Catalytic Cracking Unit 5 ppmv (3.25 lbs/thousand barrels feed)

Refinery Boiler/Heater 40 ppmv (6.76 lbs/mmscft)

Sulfur Recovery Units/Tail Gas 5 ppmv for combusted tail gas (5.28 lbs/hour)

Sulfuric Acid Manufacturing 10 ppmv (0.14 lbs/ton acid produced)
Rule 2002 (Cont.) (Amended November 5, 2010)

2002 - 31

Table 5

List of SOx RECLAIM Holders Facilities Referenced in Paragraph (f)(1)

FACILITY PERMIT HOLDER AQMD ID NO.

AES HUNTINGTON BEACH, LLC* 115389

AIR LIQUIDE LARGE INDUSTRIES U.S., LP 148236

ANHEUSER-BUSCH INC., (LA BREWERY) 16642

CALMAT CO 119104

CENCO REFINING CO 800373

EDGINGTON OIL COMPANY 800264

EQUILON ENTER. LLC, SHELL OIL PROD. US 800372

EXIDE TECHNOLOGIES 124838

INEOS POLYPROPYLENE LLC 124808

KIMBERLY-CLARK WORLDWIDE INC.-FULT. MILL 21887

LUNDAY-THAGARD COMPANY 800080

OWENS CORNING ROOFING AND ASPHALT, LLC 35302

PABCO BLDG PRODUCTS LLC,PABCO PAPER, DBA 45746

PARAMOUNT PETR CORP* 800183

QUEMETCO INC 8547

RIVERSIDE CEMENT CO 800182

TECHALLOY CO., INC. 14944

TESORO REFINING AND MARKETING CO* 151798

THE PQ CORP 11435

US GYPSUM CO 12185

WEST NEWPORT OIL CO 42775

*SOx RECLAIM facilities that have RTC Holdings larger than initial 

allocations as of August 29, 2009.