2002

- 1 (Adopted October 15, 1993)(Amended March 10, 1995)(Amended December 7, 1995) (Amended July 12, 1996)(Amended February 14, 1997)(Amended May 11, 2001)

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

RULE 2002. ALLOCATIONS FOR OXIDES OF NITROGEN (NO x ) AND

OXIDES OF SULFUR (SO x )

(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) RECL AIM 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 int o 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 inc lude 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 b y the Executive Officer.

(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 f ollowing methodology:Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 2 Starting Allocation=  [A X B 1 ]+ERCs+External Offsets

where

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 startin g 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 Ru le 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 t he 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 NO x or
SO x 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 NO x or SO x source pursuant to Rule 301

- Permit Fees, than the factor in Table 1 or Table 2, the lower factor will be used for determining that portion

of the Allocation.Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 3 (E) Fuel heating values may be used to convert throughput records into the appropria te 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 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 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 p ursuant 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 start ing Allocation or as anRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 4 ERC. RTCs issued for external offsets shall not include any offsets in excess of a 1 to 1 ratio required under Regulation XIII

- New Source Review. (C) RTCs generated from the conversion of external offsets shall have

a zero rat e 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) o f this rule

, and for compliance year 2004 and subsequent year s 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 pe rmitted 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, sh all 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 facil ity 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 afte r January 1, 1993 but prior to October 15, 1993, the starting Allocation shall be equal to the external offsets provided by the facility to offset emission increases at the facility pursuant to Regulation XIII

- New Source Review, not including any offsets in excess of a 1 to 1 ratio. (8) The Allocation for new facilities initially totally permitted on and afterRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 5 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

- N ew 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 r eported 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 purs uant 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 mo re 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 Alloc ation 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 modificatio n 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 atRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 6 the refinery or facility producing hydrogen for reformulated gasoline production, and shall be established according to present and future compliance limits in current District rules or permits. A llocation 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 NO x per thousand barrels of crude processed, in

which case the Allocat ion 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 t he 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,

where

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 rep orted 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 o r 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 E xecutive Officer or designee. No information used for purposes of thisRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 7 subparagraph may be inconsistent with any information or statement previously submitted on behalf of the facility to the District including but not limited to information and statement s 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
SO x 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 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 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 y ear 2000 Allocation is the sum of the resulting products for each piece of equipment or NO x or SO x 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 s hall 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 notRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 8 apply to RTCs generated from ERCs or external offsets.

(e) Allocations for the Year 2003 (1) The 2003 Allocations will be determined by the Executive Officer or designee applying a percentage inventory adjustment to reduce each facility's unadjusted year 2000 Alloca tion 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 th e 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 NO x and SO x and Adjustments 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

redu ction 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 fo r the relevant compliance year, to obtain

tradable /usable and non

- tradable/ non

- usable holdings :

Compliance Year 2007 2008 Tradable/Usable

NOx RTC Adjustment Factor 0.883 0.856 Non

- t radable/

Non

- u sable NO x RTC Adjustment Factor 0 0.027Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 9 2009 2010 2011 and after 0.829 0.802 0.775 0.054

0.081 0.108

RTCs designated as non

- tradable/ non

- usable pursuant to this subparagraph shall be held, but shall not be used or traded . The adjustment factors in this subparagraph are subject to change
pursuant to p aragraph (i)(5)

. (B) 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

. 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

. (C) Notwithstanding the requirements of non

- tradable/ non

- usable credits specified in subparagraph (f)(1)(A), i n the event that the NOx RTC prices exceed $15,000 per ton based on the 12

- month rolling average calculated pursuant to subparagraph (f)(1)(B), the Executive Officer will report to the Gover ning Board. If the Governing Board find s that the 12

- month rolling average RTC price exceeds $15,000 per ton, then the incremental NOx reductions as specified in subparagraph (f)(1)(D) shall be

converted to T radable / U sable NOx RTCs upon Governing Board

c oncurrence . The Executive Officer’s report to the Board will

be made at a public hearing at the earliest possible regularly

scheduled Board Meeting , but no more than 60 days from

Executive Officer determination. (D) The incremental NOx RTCs restored sh all be the difference

between the N on

- tradable/ N on

- usable A djustment F actors, as specified in subparagraph (f)(1)(A), of the current compliance year and the most recent prior year the adjustment factor was implemented. (E) RTC conversion pursuant to sub paragraph (f)(1)(C) shall only

occur in the compliance year in which Cycle 1 facilities are operating. (F) Notwithstanding the adjustment factors required pursuant toRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 10 subparagraph (f)(1)(A)

, beginning with the following December and each year thereafte r that the Governing Board finds the $15,000 per ton NOx RTC price is exceeded pursuant to subparagraph (f)(1)(C), the Executive Officer will publish the applicable adjustment factors for the next compliance year beginning January 1. The adjustment factor s will be published at a public hearing during a regularly scheduled Board Meeting. The adjustment factors will be determined as follows: (i) If the 12

- month rolling average falls below $15,000 per

ton for at least 6 consecutive months, then the emiss ion adjustment factors for the following compliance year shall equal the next more stringent adjustment factors listed in subparagraph (f)(1)(A) than the factors currently in effect ;
otherwise ; (ii) The next compliance year adjustment factor s shall equ al the compliance year adjustment factor s currently in place

. The Executive Officer need no longer comply with th e annual public hearing requirement once the adjustment factors for the 2010 compliance year have been implemented for a 12

- month period

. (G) The NOx RTC adjustment factors for compliance years 2008 through 2010 shall not be submitted for inclusion into the State Implementation Plan until the adjustments have been in effect for one full compliance year . The 2011 NOx RTC adjustment

factors shall not be submitted for inclusion into the State Implementation Plan until 12

- month s after the adjustments have been in effect for one full compliance year

. ( H ) NOx Allocations for facilities that enter RECLAIM after January 7, 2005 for compliance y ears 2007 and after shall be determined by applying the Tradable /Usable and Non

t radable/ Non

- u sable NOx RTC Adjustment Factors under

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

Allocation

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

2002

- 11 (I) SOx RTC Holdings as of November 5, 2010, f or compliance

year s 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 3,65 0,000 2019 and after 4,161 ,000 ( J ) The Executive Officer shall determine T radable/usable SOx

RTC A djustment F actor s for each compliance year s after 201 2

as follows:

F compliance year i = 1

– [ X i / (A i + B i + C i ) ]

Where:

F compliance year i = T ra dable/usable SOx RTC Adjustment Factor for compliance year i starting with 201 3

A i = Total SOx RTCs for compliance year i held as of November 11, 2010, by all RTC holders , except those listed

in Table 5

B i = Total SOx RTCs for compliance year i credited to any facilities listed in Table 5 between August 29, 2009 and (rule adoption date) , and not includes in C i C i = Total SOx RTCs held as of (r ule adoption date) by facilities listed in Table 5 for compliance year i in excess of

allocation s as determined purs uant to subdivision (e)

. X i = Amount to be reduced for compliance year i starting

with 201 3 as listed in subparagraph (f)(1)(I). (K) The Exe cutive Officer shall determine N on

- tradable/ N on

- usable SOx RTC Adjustment Factors for compliance years 2017

throu gh 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

F compliance year j = T radable/ U sable SOx RTC Adjustment

Factor f or compliance year j as determined pursuant toRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 12 s ubparagraph (f)(1)( J ) j = 201 7 through 201 9

F compliance year 201 6 = Tradable/usable SOx RTC Adjustment Factor for compliance year 201 6 as determined pursuant to

s ubparagraph (f)(1)( J )

Non

- tradable/ N on

- usab le SOx RTC Adjustment Factor s for compliance years 2013, 2014 , 2020

, and all years after 2020

shall be 0.0. (L) 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 T radable/ 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)( M ) to SOx RTC holdings held by

any R TC 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 subdivis ion (e),

and that were not credited between August 29, 2009

and November 5, 2010 ; (ii i ) Apply the T radable/ 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

correspo nding compliance year as published under subparagraph (f)(1)( M ) 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 subdivision (e);

an dRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 13 (i v ) Apply the T radable/ 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)( M ) to any SOx RTC ho lding 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)(M) more

than once. ( M ) The Executive Officer shall publish the SOx RTC Adjustment Factors determined according to subparagraph s (f)(1)(J) and (f)(1)(K) within 30 days after November 5, 2010

. ( N ) Commencing on January 1, 201 7 and ending on February 1,

2020

, the Executive Officer will calcu late 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 wi ll not include RTC transactions reported at no price or RTC swap transactions

. ( O ) I n the event that the S Ox RTC prices exceed $5 0 ,000 per ton

based on the 12

- month rolling average calculated pursuant to subparagraph (f)(1)(N) , the Executive Officer w ill 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 Bo ard

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 )( K ) and (f)(1)(L)

, and how much to convert if any, to Tradable/ U sable RTCs

. The portion of Non

tradable/ N on

- usable RTC s 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 include d in the State Implementation Plan pursuant to subparagraph (f)(1)(P).Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 14 ( P ) The Executive Officer will not submit the emission reductions obtained through subparagraph (f)(1)(I) for compliance year s
201 7 through 2019 for inclusion into the State Impleme ntation Plan until the adjustments for the RTC Holdings have been in effect for one full compliance year. ( Q ) S Ox Allocations for compliance years 201 3 and after, for

facilities that enter RECLAIM after November 5, 2010, and for basic equipment li s ted i n Table 4 s hall be determined according

to the BARCT level listed in Table 4 or the permitted emission limits, whichever is lower. (R) By no later than July 1, 2012, SOx emissions at the exhaust of a Fluidized Catalytic Cracking Unit, as measured at the final stack venting gases originating from the facility’s FCC Regenerator, including after the CO Boiler or any additional controls in the system following the regenerator (the final stack shall constitute the only exhaust gas compliance point within the FCCU facility), shall not exceed a concentration of 25 ppmv dry @ 0% oxygen on a 365

- day rolling average. The numeric

concentration

- based limit does not apply during time periods in which SOx data are determined to be incorrect due to analyzer

calibration or malfunction. For the purpose of demonstrating compliance with this limit, the operator of a FCCU shall commence the use of SOx reducing additives in the FCCU no later than July 1, 2011, unless the operator has an existing wet gas scrubber in operation at BARCT levels prior to 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 Janua ry 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 RTC s, provided that RTCs obtained have been adjusted according to paragraph (f)(1), asRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 15 applicable. The Facility Permit for such facilities will require the Facility Permit holder to, at the commencement of each compliance year, hold RTCs equal to the amount of RTCs provided as offsets pursuant to Rule 2005. (3) Increases to Allocations for permits issued for Clean Fuel adjustments pursuant to paragraph (c)(12), shall be added to each year's Allocation.

(g) High Employment/Low Emissions (HILO) Facility

Th e 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 SO x (3) After January 1, 1997, new facilities may apply to the HILO ba nk in

order to obtain non

- tradable RTCs. Requests will be processed on a

first

- come, first

- served basis, pending qualification. (4) When credits are available, annual Allocations will be granted for the year of application and all subsequent years. (5 ) HILO facilities receiving such Allocations from the HILO bank must verify their HILO status on an annual basis through their APEP report. (6) Failure to qualify will result in all subsequent years' credits being

returned to the HILO bank. (7) Facilit ies failing to qualify for the HILO bank Allocations may reapply at any time during the next or subsequent compliance year when

credits are available.

(h) Non

- Tradable Allocation Credits (1) Any existing RECLAIM facility with reported emissions pursuant to
Rule 301

- Permit Fees, in either 1987, 1988, or 1993, greater than its starting Allocation, shall be assigned non

- tradable credits for the first three years of the program which shall be determined according to the following methodology:

Non

- tradabl e 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; andRule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 16 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 requirement s: (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

f eedstock 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 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 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 Exec utive Officer or designee shall deny the request unless the Facility Permit holder demonstrates compliance with all requirements of this paragraph. The Executive Officer or designee shall, in writing, approve or deny the request within three business days of submittal of a complete request and notify the Facility Permit holder of the decision. If the request is denied, the Executive Officer or designee will refund the mitigation fee. (D) In the event that a facility transfers any RTCs for the year in

w hich non

- tradable credits have been issued, the non

- tradable credit Allocation shall be invalid, and is no longer available to the facility.Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 17 (i) RTC Reduction Exemption (1) A facility may file an application for Executive Officer approval to be exempted from all or a portion of the requirements pursuant to subparagraph (f)(1)(A) w ith the exception of RTC holdings as of January 7, 2005 for compliance year 2007 and thereafter in excess of the initial

allocation . For the purposes of this rule, initial allo cation refers to the RTCs issued by the District to a facility upon entering the RECLAIM program. The application shall contain sufficient data to demonstrate to the satisfaction of the Executive Officer that the facility meets the following criteria: (A) the facility has been in the program since the start of RECLAIM

, or existed prior to 1994

, but subsequently entered RECLAIM pursuant to Rule 2001 because facility emissions exceeded 4 tons

per year; (B) at least 9 9 percent of the facility’s emission s reported for the most recent completed compliance year prior to the date of filing an application is from equipment not listed in Table 3 and the achieved emission rates for each and every piece of equipment at the facility is less than or equal to the 2 000 (Tier I) Ending

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

Table 3 , whichever is lower, for the corresponding equipment
type; (C) RTCs that were part of the total initial allocation for the facility

have never been transferre d or sold by the facility for year 2007 or later compliance years; and (D) the cumulative NOx compliance costs incurred by the facility up

to the submittal date of the application as specified in paragraph (i)(3) to comply with the RECLAIM Allocation as required under Rule 2004(b) and (d)(1) exceed the compliance costs that

otherwise would have occurred to meet and maintain emission

limits specified in Table 1 for each and every piece of equipment at the facility . The compliance costs shall be based on the following parameters:Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 18 (i) cost of controlling emissions using the parameters and procedures for determining total direct and indirect capital investment and total annual costs as specified in the most recent edition of the Control Cost Manual publi shed by the U.S. EPA Office of Air Quality and Planning

Standards , excluding control costs for any equipment listed in Table 3, if any ; (ii) realized and anticipated revenue s and expenditures of the Facility Permit holder resulting from buying and sell ing

any RTCs that are or were held by the facility where the contract of sale or purchase was executed prior to the date of application for exemption pursuant to paragraph (i)(1) ; (iii) costs associated with compliance with the New Source Review provis ions of Rule 2005, Rule 2012(c), or other applicable state or federal requirements shall not be

included ; ( i v) costs that result only in improving process efficiency or product quality

, cost s of projects that were initiated before the date the facility was subje ct to RECLAIM requirements

, or legal costs or any other costs that do not directly reduce NOx emissions shall not be included ; and (v) any cost savings that resulted in implementing any NOx emissions strategy, such as fuel savings, increased production or sale; or (2) A facility may file an application for Executive Officer approval to be exempted from all or a portion of the requirements pursuant to subparagraph (f)(1)(A) for the initial allocations portion of a facility’s RTC holdings prov ided that the facility meets all of the following: (A) The facility’s starting and year 2000 Allocations were calculated using the same emission factors that are equal to or lower than the 2000 (Tier 1) emission factors listed in Table 1 ; (B) Emissio n rate achieved for each source at the facility is less than or equal to the emission factors listed in Table 3 for the corresponding equipment type ; and (C) RTCs for 2007 or later compliance years for the facility have

never been transferred or sold

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

2002

- 19 ( i )(1) or ( i )(2) no later than July 7, 2005 or between January 1 and March
31, 2006 , pay the appropriate evaluation fee pursuant to Rule 306, and accept enforceable permit condi tions to ensure compliance with the provisions of this subdivision , in order for the Executive Officer to approve the exemption . If approved, the facility’s initial RTC allocation shall be designated as non

- tradable and additional RTCs purchased above

the initial allocation shall be subject to the RTC adjustments specified in subparagraph (f)(1)(A), as appropriate. The Executive Officer shall deny an application that is not filed within the time periods specified in this paragraph

, lacks any information s pecified under paragraph (i)(7) , or fail s
to demonstrate that it meets the requirements in paragraphs (i)(1) or (i)(2)

. (4) Upon approval the exemption shall: (A) be limited to the adjustment factors specified in subparagraph (f)(1)(A); (B) begin t he next compliance year following the exemption approval ; and (C) not apply to reductions resulting from future periodic BARCT

review. (5) RTC adjustment s exempted pursuant to this subdivision shall be

distributed proportionally among the remainder of the RTC holders and implemented two years from the compliance year of the applicable exemption and are subject to applicable paragraph (f)(1) provisions

. Public notification of the distributed reductions shall occur at least one year prior to implementat ion. (6) A Facility Permit holder has the right to appeal the denial of the exemption application to the Hearing Board in the same manner as a permit denial as specified in Health and Safety Code Section 42302. (7) An application submitted to request a n exemption from the RTCs reduction pursuant to paragraphs (i)(1) or (i)(2) shall include the following information. (A) Detailed description of each project and itemized listing of how it relates to meeting the RECLAIM reduction requirements; (B) Date of start and completion of each project listed in (A);Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 20 (C) Detailed calculations or emissions data demonstrating NOx

emission reduction s resulting from each project or combination of projects directly resulting in reductions . The emission levels

achieved shall be based on actual CEMS data or source tests results; (D) Itemized revenue and expenditures for each RTC trading activity since participation in the RECLAIM program; ( E ) Itemized costs for each project and corresponding receipts or
other equivalent documentation as approved by the Executive

Officer for such expenditures; and ( F ) Cost savings result ing from each project ( s ) (e.g. fuel savings, improved productivity, increased sale s , etc.) and documentation

of the values of such savi ngs. (8) A facility qualifying for exemption shall report as part of its Annual Permit Emission Program (APEP) report, submitted pursuant to Rule 2004(b)(4), whether or not emissions from equipment listed in Table 3 , if

any, remain less than or equal to 1 percent of the total facility emissions on an annual basis for the duration of the exemption . If the emissions exceed 1 percent, the facility shall be in violation of the rule for each and every day of the compliance year and the Executive Officer shall reduce the facility’s initial allocation for the next compliance year to the emissions level specified for that year pursuant to subparagraph (f)(1)(A). (9) A facility applying for exemption shall have 1 percent of its initial allocations subject to the requirements pursuant to subparagraph (f)(1)(A). ( 10 ) Non

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

shall become tradable in the event the facility permanently ceases to
operate

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

2002

- 21 Table 1

RECLAIM 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 3.8 40

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 (unk nown

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

B oiler, 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, Heater s, 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, Ste am 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 furn aces.

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

**** Newly installed or Modified after the year selected for maximum throughput for determining starting allocations pursuant to Rule 2002( c)(1), and meeting BACT limits in effect at the time of installation.Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 22 Nitrogen Oxides Basic Equipment Fuel "Throughput" Units Starting

Ems Factor * 2000 (Tier I)

Ending Ems Factor * Boiler, Heater, Steam Gen (Rule 1146.1) LPG, Propane, Butane 1000 gal lons 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, Hea ter, 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 3.53 0

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, H eaters, Steam Gens, (Petr Refin) Refinery Gas mmcf 110.000 33.000

Boilers, Heaters, Steam Gens, Unpermitted Natural Gas mmcf 130.000 32.500

Boilers, Heaters, Steam Gens, Unpermitted LPG, Propane, Butane 1000 gallons RV 3.200

Boilers, Heaters, Steam Gens **** Natural Gas mmcf 38.460 38.460

* RV = Reported Value

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

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

**** Newly installed or Modified after the year selected for maximum throughput for determining starting allocations pursuant to Rule 2002(c)(1), and meeting BACT limits in effect at the time of installation.Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 23 Nitrogen Oxi des 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

Boil ers, 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 Ki lns 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 (.0 5%) 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 Gene ration, 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 ce ramic, 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 sel ected for maximum throughput for determining starting allocations pursuant to Rule 2002(c)(1), and meeting BACT limits in effect at the time of installation.Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 24 Nitrogen Oxides Basic Equipment Fuel "Throughput" Units Starting

Ems Factor

* 2000 (Tier I) En ding 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 BBL S 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) Die sel 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 G as mmcf 130.000 104.000 Industrial Propane 1000 gallons RV 20.890 Industrial Gasoline 1000 gallons RV 21.620

* RV = Reported Value

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

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

**** Newly installed or Modified after the year selected for maximum throughput for determining starting allocations pursuant to Rule 2002(c)(1), and meeting BACT limits in effect at the time of installation.Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 25 Nitrogen Oxides Basic Equipment Fuel "Throughput" Units Starting

Ems Factor* 2000 (Tier I)

Ending Ems Factor *
Industrial Dist.Oil/Diesel 1000 gallons RV 33.650 Inorganic Chemicals, H2SO4 Cham ber 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 (P reheated 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 bri ck 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 throughp ut for determining starting allocations pursuant

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

2002

- 26 Nitrogen Oxides Basic Equipment Fuel "Throughput" Units Starting

Ems Factor* 2000 (Tier I)

Ending Ems Factor *
Process Specific ID 14944 (unknown process units) RV 0.512

SCC 39090003 RV 170.400 Sec. Aluminum Sweating Furnace tons produced RV 0.300 Sec. Aluminum Smelting Furnace tons metal produced RV 0.323

Sec. Aluminum Annealing Furnace mmcf 130.000 65.000 Sec. Al uminum 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 Uti lity 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 G as 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, cla y, cement or brick kilns or metal melting, heat treating or glass melting furnaces.

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

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

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

2002

- 27 Table 2

RECLAIM SO x Emission Factors

Sulfur Oxides Basic Equipment Fuel "Throughput" Units Starting

E mission 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 D istillate 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

Extern al 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 Mi lling 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 produ ced 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 retroact ively to January 1, 1994 for Cycle 1 facilities and July 1, 1994 for Cycle 2 facilities.Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 28 Sulfur Oxides Basic Equipment Fuel "Throughput" Units Starting

Emission Factor * Ending

Emission Factor * Inprocess Fuel Cement Kiln/Dryer, Bituminous Coal tons pr oduced 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 Oxi dizer 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 Ta il 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 gallon s 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 faci lities.Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 29 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. Lea d 0.055 lb/mmbtu (45 ppm) Steel Hot Plate Furnace 0.055 lb/mmbtu (45 ppm) Utility Boiler 0.008 lb/mmbtu (7 ppm)Rule 2002 (Cont.) ( Amended November 5 , 2010)

2002

- 30 Table 4 R ECLAIM SOx Tier III Emission Standards

Basic Equipment BARCT Emission Standard

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

Cement Kiln 5 ppmv (0.04 lbs/ton clinker)

Coal

- Fired Boiler 5 ppmv (95% reduction)
Container Glass Melting Furnace 5 ppmv (0.03 lbs/ton glass)

Diesel Combustion 15 ppmv as required under Rule 431.2
Fluid Catalytic Cracking Unit 5 ppmv (3.25 lbs/thousand barrels feed)
Refinery Boiler/Heater 40 ppmv (6.76 lbs/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 November 5 , 2010)

2002

- 31 Table 5 List of S Ox RECLAIM Facilities Referenced in Paragraph (f)(1)

FACILITY PERMIT HOLDER AQMD ID NO. AES HUNTINGTON BEACH, LLC * 115389 AIR LIQUIDE LARGE INDUSTRIES U.S., LP 148236
ANHEUSER

- BUSCH INC., (LA BREWERY) 16642
CALMAT CO 119104
CENCO REFINING CO 800373
EDGINGTON OIL COMPANY 800264 EQUILON ENTER. LLC, SHELL OIL PROD. US 800372
EXIDE TECHNOLOGIES 124838
INEOS POLYPROPYLENE LLC 124808
KIMBERLY

- CLARK WORLDWIDE INC.

- FULT. MILL 21887
LUNDAY

- THAGARD COMPANY 800080 OWENS CORNING ROOFING AND ASPHALT, LLC 3 5302 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 C O 42775

* SOx RECLAIM facilities that have RTC Holdings larger than initial allocations as of August 29, 2009.