### 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 (NO x ) 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 G overning 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 Fac ility 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

- T rading 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 Allocation s

.

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

2002

- 2 (c) Establishment of Starting Allocations

(1) The starting Allocation for RECLAIM NO x and SO x 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 B 1 ]+ERCs+External Offsets

W here

A = the throughput for each NO x and SO x source or process unit in

the facility for the maximum throughput year from 1989 to 1992

inclusive; and

B 1 = 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 w ill 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 st atements 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 NO x 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

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

2002

- 3 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 sub stantial evidence to the Executive Officer that a different

value should be used to determine emissions from that source.

(3) All NO x and SO x 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 paragra ph (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 i s 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 sh all 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 X III

- 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.

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

2002

- 4 RTCs issued for external offsets shall not incl ude 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 o ffset 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 offset s 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

rul es 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 s hall 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)

2002

- 5 (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 existi ng 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, ma y 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 ho lding 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 req uirements (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 reque sting 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 design ee (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 refine ry or facility

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

2002

- 6 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, shal l not exceed 5 percent of the refiner's total starting

Allocation, unless any refiner emits less than 0.0135 tons of NO x per
thousand barrels of crude processed, in which case the Allocation increases

for such refiner shall not exceed 20 percent of that re finer'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 NO x starting Allocation.

(d) Establishment of Year 2000 Allocations

(1) (A) The year 2000 Allocations for RECLAIM NO x and SO x facilities

will be determined by the Executive Officer or designee utilizing

the following methodology:

Year 2000
Allocation =  [A X B 2 ] + RTCs created from ERCs + External Offsets,

W here

A = the throughput for each NO x or SO x 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

B 2 = 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 perm it 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 inconsiste nt with any

information or statement previously submitted on behalf of the

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

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 cle ar and convincing

documentation, that such information or statement was inaccurate.

(D) Throughput associated with each piece of equipment or NO x or

SO x source will be multiplied by the Tier I emission factor specified

in Table 1 or Table 2. If a facto r lower than the factor in Table 1 or

Table 2 was utilized for a given piece of equipment or NO x or SO x 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 consider ed 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 NO x or SO x sou rce 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 t o 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

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

2002

- 8 unadjusted year 2000 Allocation so that the sum of all RECLAIM facilities'

2003 Allocations will equal the 1991 AQMP pr ojected 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 wh ole 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 NO x and SOx and Adjust ments to RTC Holdings

(1) Allocations for the years between 1994 and 2000, for RECLAIM NO x and

SO x 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 201 2 are equal to the

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

RTC Allocation s and holdings subsequent to the year 2006 and SOx

Allocations and holdings subsequent to the year 20 1 2 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 holding s by the following adjustment factors for the

relevant compliance year, to obtain tradable /usable and non

tradable/ 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 :

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

2002

- 9 Compliance
Year
2015
20 16
20 17
20 18
201 9
2020
202 1
20 2 2
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
0.0 35
0. 035
0. 069
0. 07 0
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

pu rchased and sold RTCs between September 22, 2015 and

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

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

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 emission s pursuant to Rule 2004

. ( E ) Commencing on January 1, 2008 with NOx RTC prices averaged

from January 1, 2007 through December 31, 2007, t he 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

compl iance 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 t he amount of NOx RTCs holdings listed in Table 9 of this

Rule from the corresponding facilities identified in the same t able

. ( 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 Non

tradable/Non

- usable RTCs specified in subparagraph (f)(1) (C) and

the amount listed for each facility in Table 9

, which represent s the

RTCs in the Regional NSR Holding account

. ( H ) I n 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. I f the Governing Board

find s that the 12

- month rolling average RTC price exceeds $22,500

per ton or the 3

- month rolling average RTC price exceeds $3 5

, 0 00

per ton , then the Non

- tradable/Non

- usable NOx RTCs

, as specified

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

which the RTC price is found to have exceeded the applicable

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

2002

- 11 threshold, shall be converted to T radable / U sable 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

in to the future for ten or more years.

( J ) Pursuant to subparagraphs (f)(1)( H ) and (f)(1)( I ) t he 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 r egularly 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 20 1 6, and 2018 through 20 2 2 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 sub

paragraph (f)(1)( F ) shall not be submitted for in clusion in the State

Impl e mentation 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) ;
(i i ) The BARCT Emission factor for the subject source as

specified in Table 3 ; and

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

2002

- 12 (i ii ) 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

201 3 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

A djustment F actor for each compliance year after 201 2 as follows:

F compliance year i 

### = 1

– [ Xi / (Ai + Bi + Ci) ]

Where:

F compliance year i 

### = Tradable/usable SOx RTC Adjustment Factor

for compliance year i starting with 201 3

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 l isted in Table 5 between August 29, 2009 and

November 5, 2010 , and not include d 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 allocation s

as determined pursuant to subdivision (e)

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

201 3 as listed in subparagraph (f)(1)( M ).

( O ) The Exe cutive Officer shall determine N on

- tradable/ N on

- usable

SOx RTC Adjustment Factors for compliance years 2017 through

2019 as follows:

N compliance year j 

### = F compliance year 201 6



### - F compliance year j



### Where:

N compliance year j 

### = N on

- tradable/ N on

- usable SOx RTC

Adjustment Factor for compliance year j

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

2002

- 13 F compliance year j 

### = T radable/ U sable SOx RTC Adjustment Factor

for compliance year j as determined pursuant to s ubparagraph

(f)(1)( N )

j = 201 7 through 2019

F compliance year 201 6 

### = Tradable/usable SOx RTC Adjustment

Factor for compliance year 201 6 as determined pursuant to

s ubparagraph (f)(1)( N )

Non

- tradable/ N on

- usable SOx RTC Adjustment Factor s 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 201 3 and after as follows:

(i) Apply the Tradable/ U sable SOx RTC A djustment F actor

(F compliance year i 

### ) and N on

- tradable/ N on

- usable SOx RTC

Adjustment Factor (N compliance 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 holding s 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 ;
(ii i ) Apply the Tradable/ U sable SOx RTC A djustment F actor

(F compliance year i 

### ) and Non

- tradable/ N on

- usable SOx RTC

Adjustment Factor (N compliance year j 

### ) for the corresponding

compliance year as published under subparagraph

(f)(1)( Q ) to any S O x 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 allocation s as determined

pursuant to subdi vision (e); and

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

2002

- 14 (iv) Apply the Tradable/ U sable SOx RTC A djustment F actor

(F compliance year i 

### ) and Non

- tradable/non

- usable SOx RTC

Adjustment Factor (N compliance 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 subparagraph s (f)(1)( N ) and

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

. ( R ) Commencing on January 1, 201 7 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 computatio n of the

rolling average prices will not include RTC transactions reported at

no price or RTC swap transactions

. ( S ) I n 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 du ly 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 N on

tradable/ N on

- usable RTCs

, as determined pursuant to

subparagraph s (f)( 1 )( O ) and (f)(1)( P )

, and how much to convert if

any, to Tradable/ U sable RTCs

. The portion of Non

- tradable/ N on

usable RTCs available for conversion to Tradable/ U sable RTCs

shall not include any portion of Non

- tradable/ N on

- usable RTCs that

are designated for previous compliance year s 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 ).

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

2002

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

obtained through subparagraph (f)(1)( M ) for compliance year s

201 7 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 201 3 and after, for facilities

that enter RECLAIM after November 5, 2010, and for basic

equipment li s ted in Table 4 s hall 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

Fl uidized 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 constitut e 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 deter mined 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 operat or 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 eac h 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 o r 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 com pletely 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 ea ch 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 Office r 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 fo llowing 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 the ir need for the

specific amount of RTCs from the Regional NSR Holding

Account ; and

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

holding s for the subject compliance year.

If the total RTC s 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 complia nce 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 NO x (2) 91 tons per year of S o x (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 fo r 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 determ ined according to the following

methodology:

Non

- tradable credit for NO x and SO x :

Year 1 = (  [A X B 1 ])

- 1994 Allocation;

Where:

A = the throughput for each NO x or SO x source or process

unit in the facility from the single maximum throughput year from 1987, 1988, or 1993; and

B 1 = 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

materi als, 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 non

tradable 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 t he 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 desig nee 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 com plete 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 NO x 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 Process

Absrbr Tailgas/Nw tons pure acid

produced RV 1.440

Agricultural Chem

- Ammonia Process tons produced RV 1.650

Air Ground Turbines Air Ground

Turbines (unknown

process units) RV 1.860

Ammonia Plant Neutralizer Fert, Ammon

Nit tons produced RV 2.500

Asphalt Heater, Concrete Natural Gas mmcf 130.000 65.000 Asphalt Heater, Concrete Fuel Oil 1000 gals RV 9.500 Asphalt Heater, Concrete LPG 1000 gals RV 6.400 Boiler, Heater R1109 (Petr Refin) Natural Gas mmbtu 0.100 0.030

Boiler, Heater R1109 (Petr Refin) Fuel Oil mmbtu 0.100 0.030

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

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

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

Boilers, Heaters, Steam Gens

Rule 1146 and 1146.1 Natural Gas mmcf 49.180 47.570

Boilers, Heaters, Steam Gens

Rule 1146 and 1146.1 LPG, Propane,

Butane 1000 gals 4.400 4.260

Boilers, Heaters, Steam Gens

Rule 1146 and 1146.1 Diesel Light Dist. (0.05% S) 1000 gals 6.420 6.210

Boilers, Heaters, Steam Gens

Rule 1146 and 1146.1 Refinery Gas mmcf 51.520 49.840

Boilers, Heaters, Steam Gens Bituminous
Coal tons burned RV 4.800

Boiler, Heater, Steam Gen (Rule 1146.1) Natural Gas mmcf 130.000 39.460

Boiler, Heater, Steam Gen (Rule 1146.1) Refinery Gas mmcf RV 41.340

* RV = Reported Value

** Does not include ceramic, clay, cement or brick kilns or metal melting, heat treating or glass melting furnaces.

*** Applies retroactively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.

**** 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 B ACT 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 max imum 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 SO x 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 NO x 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

R ECLAIM 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/mmscf t )

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 Subp aragraph s (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 NO x 2 022 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%O 2 

### 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 Subp aragraph (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 Subp aragraph (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 l bs)

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 1,85 4 1,854 1,85 4 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