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)(Amended December 4, 2015)

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.

(5) Annual emission reports submitted pursuant to Rule 301 more than five 

years after the original due date shall not be considered by the Executive 

Officer in determining facility Allocations.
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2002 - 2

(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 
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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 NOxand 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 ERC. 
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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.
Rule 2002 (Cont.) (Amended December 4, 2015)

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(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 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 the refinery or facility 
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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 subparagraph may be inconsistent with any 

information or statement previously submitted on behalf of the 
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2002 - 7

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 
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2002 - 8

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 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. NOx Allocations for 2004,

2005, and 2006 and SOx Allocations for 2004 through 2012 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 2012 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 nontradable/non-usable holdings:

Compliance

Year

2007

2008

2009

2010

2011 and 

after

Tradable/Usable

NOx RTC

Adjustment Factor

0.883

0.856

0.829

0.802

0.775

(B) The Executive Officer shall adjust NOx RTCs held as of September 

22, 2015 by the RTC holders identified in Table 7 and their 

successors using the following adjustment factors to obtain 

Tradable/Usable and Non-Tradable/Non-Usable RTC Holdings:
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2002 - 9

Compliance

Year

2015

2016

2017

2018

2019

2020

2021

2022

2023 and 

after

Tradable/Usable

NOx RTC

Adjustment Factor

1.0

0.906

0.906

0.859

0.812

0.719

0.625

0.437

0.437

Non-tradable/

Non-usable NOx RTC

Adjustment Factor

0

0.094

0

0.047

0.047

0.093

0.094

0.188

0

RTC holdings traded from RTC holders in Table 7 on and after

September 22, 2015 and held by other RTC holders not listed in 

Table 7 shall be subjected to the above adjustment factors. The 

adjustment factor(s) for any RTC sold by an RTC holder that both 

purchased and sold RTCs between September 22, 2015 and 

December 4, 2015 shall be based on a last in/first out basis.

(C) The Executive Officer shall adjust NOx RTCs held as of September 

22, 2015 by the RTC holders identified in Table 8 and their 

successors using the following adjustment factors to obtain 

Tradable/Usable and Non-Tradable/Non-Usable RTC holdings:

Compliance

Year

2015

2016

2017

2018

2019

2020

2021

2022

2023 and 

after

Tradable/Usable

NOx RTC

Adjustment Factor

1.0

0.931

0.931

0.896

0.861

0.792

0.722

0.583

0.583

Non-tradable/

Non-usable NOx RTC

Adjustment Factor

0

0.069

0

0.035

0.035

0.069

0.070

0.139

0

RTC holdings traded from RTC holders in Table 8 on and after

September 22, 2015 and held by other RTC holders not listed in 

Table 8 shall be subjected to the above adjustment factors. The 

adjustment factor(s) for any RTC sold by an RTC holder that both 

purchased and sold RTCs between September 22, 2015 and 

December 4, 2015 shall be based on a last in/first out basis.
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2002 - 10

(D) RTCs designated as non-tradable/non-usable pursuant to 

subparagraphs (f)(1)(B) and (f)(1)(C) shall be held, but shall not be 

traded or used for reconciling emissions pursuant to Rule 2004.

(E) 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. Commencing on May 1, 

2016 with NOx RTC prices averaged from January 1, 2016 through 

March 31, 2016, the Executive Officer will calculate the 3-month 

rolling average NOx RTC price for all trades for the current 

compliance year NOx RTCs and the 12-month rolling average NOx 

RTC price for all trades for infinite year block NOx RTC as defined 

in subparagraph (f)(1)(I). The Executive Officer will update the 3-

month and 12-month rolling average once per month. The 

computation of the rolling average prices will not include RTC 

transactions reported at no price or RTC swap transactions. 

(F) The Executive Officer shall transfer to a Regional NSR Holding 

account the amount of NOx RTCs holdings listed in Table 9 of this 

Rule from the corresponding facilities identified in the same table.

(G) For purposes of meeting the NSR holding requirement as specified 

in subdivision (f) of Rule 2005, the facilities identified in Table 9 

may use a combination of their Tradable/Usable and Nontradable/Non-usable RTCs specified in subparagraph (f)(1)(C) and 

the amount listed for each facility in Table 9, which represents the 

RTCs in the Regional NSR Holding account.

(H) In the event that the NOx RTC prices exceed $22,500 per ton 

(current compliance year credits) based on the 12-month rolling 

average, or exceed $35,000 per ton (current compliance year 

credits) based on the 3-month rolling average calculated pursuant to 

subparagraph (f)(1)(E), the Executive Officer will report the 

determination to the Governing Board. If the Governing Board 

finds that the 12-month rolling average RTC price exceeds $22,500

per ton or the 3-month rolling average RTC price exceeds $35,000 

per ton, then the Non-tradable/Non-usable NOx RTCs, as specified 

in subparagraphs (f)(1)(B) and (f)(1)(C) valid for the period in 

which the RTC price is found to have exceeded the applicable 
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2002 - 11

threshold, shall be converted to Tradable/Usable NOx RTCs upon 

Governing Board concurrence.

(I) In the event that the infinite year block NOx RTC prices fall below 

$200,000 per ton based on the 12-month rolling average, calculated 

pursuant to subparagraph (f)(1)(E) beginning in 2019 for the 

compliance year in which Cycle 1 facilities are operating, the 

Executive Officer will report the determination to the Governing 

Board. 

For the purpose of this rule, infinite year block refers to trades 

involving blocks of RTCs with a specified start year and continuing 

into the future for ten or more years.

(J) Pursuant to subparagraphs (f)(1)(H) and (f)(1)(I) the Executive 

Officer’s report to the Board will also include a commitment and 

schedule to conduct a more rigorous control technology 

implementation, emission reduction, cost-effectiveness, market 

analysis, and socioeconomic impact assessment of the RECLAIM 

program. 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 90 days from Executive Officer 

determination.

(K) The NOx emission reductions associated with the RTC adjustment 

factors for compliance years 2016, and 2018 through 2022 shall not 

be submitted for inclusion into the State Implementation Plan until 

the adjustments have been in effect for one full compliance year. 

However, the amount of NOx RTCs adjustments specified in subparagraph (f)(1)(F) shall not be submitted for inclusion in the State 

Implementation Plan. 

(L) NOx Allocations for existing facilities that enter RECLAIM after 

December 4, 2015 for Compliance Year 2016 and all subsequent 

years shall be the amount determined pursuant to subparagraph 

(d)(1)(A) except the variable B2 shall be the lowest of:

(i) The applicable 2000 (Tier I) Ending Emission Factor for 

the subject source(s) or process unit(s), as specified in 

Table 1 multiplied by the percentage inventory adjustment 

pursuant to subdivision (e) (0.72);

(ii) The BARCT Emission factor for the subject source as 

specified in Table 3; and
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2002 - 12

(iii) The BARCT Emission factor for the subject source, as

specified in Table 6.

(M) SOx RTC Holdings as of November 5, 2010, for compliance years 

2013 and after shall be adjusted to achieve an overall reduction in 

the following amounts:

Compliance Year Minimum emission reductions

(lbs.)

2013 2,190,000

2014 2,920,000

2015 2,920,000 

2016 2,920,000 

2017 3,650,000

2018 3,650,000 

2019 and after 4,161,000 

(N) The Executive Officer shall determine Tradable/usable SOx RTC 

Adjustment Factor for each compliance year after 2012 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 2013

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

November 5, 2010, 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 

November 5, 2010, and not included in Ci

Ci = Total SOx RTCs held as of November 5, 2010 by facilities 

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

as determined pursuant to subdivision (e).

Xi = Amount to be reduced for compliance year i starting with 

2013 as listed in subparagraph (f)(1)(M).

(O) The Executive Officer shall determine Non-tradable/Non-usable 

SOx RTC Adjustment Factors for compliance years 2017 through

2019 as follows:

Ncompliance year j = Fcompliance year 2016 - Fcompliance year j

Where:

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

Adjustment Factor for compliance year j
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2002 - 13

Fcompliance year j = Tradable/Usable SOx RTC Adjustment Factor 

for compliance year j as determined pursuant to subparagraph 

(f)(1)(N)

j = 2017 through 2019 

Fcompliance year 2016 = Tradable/usable SOx RTC Adjustment 

Factor for compliance year 2016 as determined pursuant to 

subparagraph (f)(1)(N)

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

compliance years 2013, 2014, 2020, and all years after 2020 shall 

be 0.0.

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

November 5, 2010, for compliance years 2013 and after as follows:

(i) Apply the Tradable/Usable SOx RTC Adjustment Factor 

(Fcompliance year i) and Non-tradable/Non-usable SOx RTC 

Adjustment Factor (Ncompliance year j) for the corresponding 

compliance year as published under subparagraph 

(f)(1)(Q) 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 November 5, 2010;

(iii) Apply the Tradable/Usable SOx RTC Adjustment Factor 

(Fcompliance year i) and Non-tradable/Non-usable SOx RTC 

Adjustment Factor (Ncompliance year j) for the corresponding 

compliance year as published under subparagraph 

(f)(1)(Q) to any SOx RTC holding as of November 5, 

2010, that is held by a facility that is listed in Table 5, and 

that is over the facility’s allocations as determined 

pursuant to subdivision (e); and
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2002 - 14

(iv) Apply the Tradable/Usable SOx RTC Adjustment Factor 

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

Adjustment Factor (Ncompliance year j) for the corresponding 

compliance year as published under subparagraph 

(f)(1)(Q) to any SOx RTC holding that was acquired 

between August 29, 2009 and November 5, 2010, by a 

facility that is listed in Table 5.

No SOx RTC holding shall be subject to the SOx RTC adjustments 

as published under subparagraph (f)(1)(Q) more than once.

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

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

(f)(1)(O) within 30 days after November 5, 2010.

(R) Commencing on January 1, 2017 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 RTC swap transactions. 

(S) 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)(R), 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/Non-usable RTCs, as determined pursuant to 

subparagraphs (f)(1)(O) and (f)(1)(P), and how much to convert if 

any, to Tradable/Usable RTCs. The portion of Non-tradable/Nonusable RTCs available for conversion to Tradable/Usable RTCs 

shall not include any portion of Non-tradable/Non-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 State Implementation Plan pursuant to subparagraph 

(f)(1)(T). 
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2002 - 15

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

obtained through subparagraph (f)(1)(M) for compliance years

2017 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.

(U) SOx Allocations for compliance years 2013 and after, for facilities 

that enter RECLAIM after November 5, 2010, 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.

(V) 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 ppm 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 

November 5, 2010 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 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, 
Rule 2002 (Cont.) (Amended December 4, 2015)

2002 - 16

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.

(4) During a State of Emergency declared by the Governor related to electricity 

demand or power grid stability within the SCAQMD jurisdictional 

boundaries, the current compliance year Non-tradable/Non-usable NOx 

RTCs held by electricity generating facilities as defined in Rule 2001(g)(1)

that generate and distribute electricity to the grid system(s) affected by the 

State of Emergency may be used to offset their emissions after completely 

exhausting their own Tradable/Usable NOx RTCs.

If such a facility has completely exhausted their Non-tradable/Non-usable 

NOx RTCs, the owner or operator of the facility may apply for the use of the 

NOx RTCs in the Regional NSR Holding Account. The use of such RTCs 

in this Account shall be based on availability at the end of each quarter. The 

owner or operator of each electricity generating facility requesting NOx 

RTCs from the Regional NSR Holding Account shall submit a written 

request to the Executive Officer specifying the amount of RTCs needed and 

the basis for requesting the required amount. 

The Executive Officer will determine the amount and distribution of the NOx 

RTCs from the Regional NSR Holding Account based on the requesting 

facility meeting the following criteria:

(i) The State of Emergency related to electricity demand or power 

grid stability within the SCAQMD jurisdictional boundaries, as 

declared by the Governor, was the direct cause of the excess 

emissions;

(ii) The facility has been ordered to generate electricity in an 

increased amount and/or frequency due to the State of 

Emergency;

(iii) The facility has adequately demonstrated their need for the 

specific amount of RTCs from the Regional NSR Holding 

Account; and

(iv) The facility owner or operator has not sold any part of their RTC 

holdings for the subject compliance year.

If the total RTCs requested exceed the supply of RTCs in this Account, the 

RTCs will be distributed proportionately according to the offset needs of the 
Rule 2002 (Cont.) (Amended December 4, 2015)

2002 - 17

facilities on a quarterly basis. These RTCs will be non-tradable, but usable 

to offset emissions.

(5) The Executive Officer will report to the Governing Board within 60 days of 

the end of the quarter in which a State of Emergency was declared by the 

Governor related to electricity demand or power grid stability within the 

SCAQMD jurisdictional boundaries. Included in this report will be, as 

applicable:

(i) the quantity of RTCs from the Regional NSR Holding Account 

that were distributed for compliance with the requirement to 

reconcile quarterly and annual emissions;

(ii) any adverse impacts that the State of Emergency is having on the 

RECLAIM program; and

(iii) any potential changes to the RECLAIM program that will be 

needed to help correct these impacts.

(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, firstserved 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 
Rule 2002 (Cont.) (Amended December 4, 2015)

2002 - 18

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 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. Nontradable 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.
Rule 2002 (Cont.) (Amended December 4, 2015)

2002 - 19

(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 December 4, 2015)

2002 - 20

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 December 4, 2015)

2002 - 21

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 December 4, 2015)

2002 - 22

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 December 4, 2015)

2002 - 23

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 December 4, 2015)

2002 - 24

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 December 4, 2015)

2002 - 25

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 December 4, 2015)

2002 - 26

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 December 4, 2015)

2002 - 27

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 December 4, 2015)

2002 - 28

Table 3

RECLAIM NOx 2011 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 December 4, 2015)

2002 - 29

Table 4

RECLAIM SOx Tier III Emission Standards

Basic Equipment BARCT Emission Standard

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 ppm by weight 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 December 4, 2015)

2002 - 30

Table 5

List of SOx RECLAIM Facilities Referenced in Subparagraphs (f)(1)(M) 

and (f)(1)(O)

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.
Rule 2002 (Cont.) (Amended December 4, 2015)

2002 - 31

Table 6

RECLAIM NOx 2022 Ending Emission Factors

Nitrogen Oxides

Basic Equipment

BARCT

Emission Factor

Boiler, Heater R1109 (Petr 

Refin) >40 mmbtu/hr

2 ppm

Cement Kilns 0.5 lbs per ton clinker

Fluid Catalytic Cracking Unit 2 ppm

Gas Turbines 2 ppm

Glass Melting Furnaces –

Container Glass

80% reduction 

(0.24 lb/ton glass produced)

ICEs, Permitted (Rule 1110.2)

(Non-OCS)

11 ppm @15%O2

0.041 lb/MMBTU

43.05 lb/mmcf

Metal Heat Treating Furnace 

>150 mmbtu/hr

0.011 lb/mmbtu (9 ppm)

Petroleum Refining, Calciner 10 ppm

Sodium Silicate Furnace 80% reduction 

(1.28 lb/ton glass pulled)

SRU/Tail Gas Unit 95% reduction

2ppm
Rule 2002 (Cont.) (Amended December 4, 2015)

2002 - 32

Table 7

List of NOx RECLAIM Facilities Referenced in Subparagraph (f)(1)(B)

FACILITY PERMIT HOLDER AQMD ID NO.

CHEVRON PRODUCTS CO. 800030

EXXONMOBIL OIL CORPORATION 800089

PHILLIPS 66 CO/LA REFINERY WILMINGTON PL 171107

PHILLIPS 66 COMPANY/LOS ANGELES REFINERY 171109

TESORO REF & MKTG CO LLC,CALCINER 174591

TESORO REFINING & MARKETING CO, LLC 174655

TESORO REFINING AND MARKETING CO, LLC 151798

TESORO REFINING AND MARKETING CO, LLC 800436

ULTRAMAR INC 800026

NOx RTC holders not designated as Facility Permit 

Holders as of September 22, 2015, except any NOx 

RTC holders listed in Table 8 Multiple
Rule 2002 (Cont.) (Amended December 4, 2015)

2002 - 33

Table 8

List of NOx RECLAIM Facilities Referenced in Subparagraph (f)(1)(C)

FACILITY PERMIT HOLDER AQMD ID NO.

AES ALAMITOS, LLC 115394

AES HUNTINGTON BEACH, LLC 115389

AES REDONDO BEACH, LLC 115536

BERRY PETROLEUM COMPANY 119907

BETA OFFSHORE 166073

BICENT (CALIFORNIA) MALBURG LLC 155474

BORAL ROOFING LLC 1073

BURBANK CITY, BURBANK WATER & POWER 25638

BURBANK CITY,BURBANK WATER & POWER,SCPPA 128243

CALIFORNIA PORTLAND CEMENT CO 800181

CALIFORNIA STEEL INDUSTRIES INC 46268

CANYON POWER PLANT 153992

CPV SENTINEL LLC 152707

DISNEYLAND RESORT 800189

EDISON MISSION HUNTINGTON BEACH, LLC 167432

EL SEGUNDO POWER, LLC 115663

EXIDE TECHNOLOGIES 124838

GENERAL ELECTRIC COMPANY 700126

HARBOR COGENERATION CO, LLC 156741

INLAND EMPIRE ENERGY CENTER, LLC 129816

LA CITY, DWP HAYNES GENERATING STATION 800074

LA CITY, DWP SCATTERGOOD GENERATING STN 800075

LA CITY, DWP VALLEY GENERATING STATION 800193

LONG BEACH GENERATION, LLC 115314

NEW- INDY ONTARIO, LLC 172005

NRG CALIFORNIA SOUTH LP, ETIWANDA GEN ST 115315

OWENS-BROCKWAY GLASS CONTAINER INC 7427

OXY USA INC 169754

PACIFIC CLAY PRODUCTS INC 17953

PARAMOUNT PETR CORP 800183

PASADENA CITY, DWP 800168

PQ CORPORATION 11435

QUEMETCO INC 8547

SAN DIEGO GAS & ELECTRIC 4242

SNOW SUMMIT INC 43201

SO CAL EDISON CO 4477

SO CAL GAS CO 800128

SO CAL GAS CO 800127

SO CAL GAS CO 5973

SO CAL GAS CO/PLAYA DEL REY STORAGE FACI 8582

SOLVAY USA, INC. 114801
Rule 2002 (Cont.) (Amended December 4, 2015)

2002 - 34

FACILITY PERMIT HOLDER AQMD ID NO.

SOUTHERN CALIFORNIA EDISON 160437

TABC, INC 3968

TAMCO 18931

US GOVT, NAVY DEPT LB SHIPYARD 800153

WALNUT CREEK ENERGY, LLC 146536

WHEELABRATOR NORWALK ENERGY CO INC 51620

WILDFLOWER ENERGY LP/INDIGO GEN., LLC 127299
Rule 2002 (Cont.) (Amended December 4, 2015)

2002 - 35

Table 9

List of NOx RECLAIM Facilities for the Regional NSR Holding Account with Balances (in lbs)

FACILITY PERMIT HOLDER AQMD 

ID NO. 

2016 2017 2018 2019 2020 2021 2022 2023+ 

Dec 

2016 

Jun 

2017 

Dec 

2017 

Jun 

2018 

Dec 

2018 

Jun 

2019 

Dec 

2019 

Jun 

2020 

Dec 

2020 

Jun 

2021 

Dec 

2021 

Jun 

2022 

Dec 

2022 

Jun 

2023 

Dec 

2023+ 

Jun 

2023+ 

BICENT (CALIFORNIA) MALBURG LLC 155474 0 0 1,854 1,854 1,854 1,854 2,794 2,794 3,735 3,734 5,588 5,588 7,469 7,469 11,204 11,203

BURBANK CITY, BURBANK WATER & 

POWER, SCPPA 

128243 0 0 1,604 5,159 1,604 5,159 2,418 7,775 3,232 10,392 4,836 15,551 6,464 20,784 9,695 31,177

CANYON POWER PLANT 153992 0 0 3,248 2,548 3,248 2,548 4,896 3,840 6,543 5,133 9,792 7,680 13,087 10,265 19,630 15,398

CPV CENTINEL LLC 152707 0 0 9,645 6,981 9,645 6,981 14,538 10,522 19,430 14,063 29,075 21,044 38,860 28,127 58,290 42,190

GENERAL ELECTRIC 

COMPANY/INLAND EMPIRE 

ENERGY CENTER 

700126/ 

129816 0 0 9,065 6,573 9,065 6,573 13,664 9,907 18,262 13,241 27,327 19,815 36,524 26,484 54,785 39,725

LONG BEACH GENERATION, LLC 115314 0 0 0 5,962 0 5,962 0 8,986 0 12,010 0 17,971 0 24,019 0 36,029

SOUTHERN CALIFORNIA EDISON 160437 0 0 13,227 6,758 13,227 6,758 19,937 10,184 26,646 13,612 39,874 20,370 53,293 27,225 79,940 40,837

WALNUT CREEK ENERGY, LLC 146536 0 0 3,690 4,242 3,690 4,242 5,562 6,393 7,434 8,544 11,124 12,786 14,867 17,089 22,301 25,633

WILDFLOWER ENERGY LP/INDIGO GEN., 

LLC 

127299 0 0 0 3,483 0 3,483 0 5,250 0 7,016 0 10,499 0 14,033 0 21,049