SJVUAPCD 4320 - 1 10/16/08

RULE 4320 ADVANCED EMISSION REDUCTION OPTIONS FOR B OILERS, STEAM

GENERATORS, AND PROCESS HEATERS GREATER THAN 5.0 MMBTU/HR (Adopted October 16, 2008)

1.0 Purpose

The purpose of this rule is to limit emissions of oxides of nitrogen (NOx), carbon monoxide (CO), oxides of sulfur (SO

2 ), and particulate matter 10 microns or less (PM10) from boilers, steam generators, and process heaters.

2.0 Applicability

This rule applies to any gaseous fuel or liquid fu el fired boiler, steam generator, or process heater with a total rated heat input greater than 5 million Btu per hour.

3.0 Definitions

3.1 Air Pollution Control Officer ( APCO): as defined in Rule 1020 (Definitions).

3.2 Air Resources Board (ARB): as defined in Rule 1020 (Definitions).

3.3 Annual Capacity Factor: the ratio of the amoun t of fuel burned by the unit in a calendar year to the amount of fuel that the unit c ould have burned if it had operated at its maximum rated capacity for 8,760 hours durin g the calendar year.

3.4 Annual Heat Input: the actual, total heat inpu t of fuels burned by a unit in a calendar year, as determined from the higher heatin g value and cumulative annual usage of each fuel.

3.5 Boiler or Steam Generator: any external combus tion equipment, fired with any fuel used to produce hot water or steam.

3.6 British Thermal Unit (Btu): the amount of heat required to raise the temperature of one pound of water from 59°F to 60°F at one atmosph ere.

3.7 California Public Utility Commission (PUC) Qua lity Natural Gas: any gaseous fuel, gas-containing fuel where the sulfur content is no more than one-fourth (0.25) grain of hydrogen sulfide per one hundred (100) standard cubic feet and no more than five (5) grains of total sulfur per one hundred (100) st andard cubic feet. PUC quality natural gas also means high methane gas of at least 80% methane by volume.

3.8 California PUC Quality Natural Gas Curtailment: means a shortage in the supply of California Public Utility Commission (PUC) quality natural gas, due solely to supply limitations or restrictions in distribution pipelines by the utility supplying the gas, and not due to the cost of natural gas.SJVUAPCD 4320 - 2 10/16/08

3.9 Dryer: any unit in which material is dried in direct contact with the products of

combustion.

3.10 EPA: United States Environmental Protection Agency.

3.11 Gaseous Fuel: any fuel which is a gas at stan dard conditions.

3.12 Gas Liquids Processing Facility: a facility t hat is engaged in the catalytic processing of gas liquids to produce finished products.

3.13 Heat Input: the heat (hhv basis) released due to fuel combustion in a unit, not including the sensible heat of incoming combustion air and fuel.

3.14 Higher Heating Value (hhv): the total heat li berated per mass of fuel burned (expressed as Btu per pound), when fuel and dry air at standard conditions undergo complete combustion and all resulting products are brought to their standard states

at standard conditions.

3.15 Liquid Fuel: any fuel which is a liquid at st andard conditions.

3.16 NOx Emissions: the sum of oxides of nitrogen expressed as NO

2 in the flue gas.

3.17 Oilfield Steam Generator: an external combust ion equipment which converts water to dry steam or to a mixture of water vapor and ste am, with an absolute pressure of more than 30 psia, and which is used exclusively in thermally enhanced crude oil production.

3.18 Parts Per Million by Volume (ppmv): the ratio of the number of gas molecules of a given species, or group of species, to the number o f millions of total gas molecules.

3.19 Process Heater: any combustion equipment fire d with liquid and/or gaseous fuel and which transfers heat from combustion gases to w ater or process streams. This definition excludes: kilns or ovens used for dryin g, baking, cooking, calcining, or vitrifying; and unfired waste heat recovery heaters used to recover sensible heat from the exhaust of combustion equipment.

3.20 Qualified Technician: a stationary source emp loyee or any personnel contracted by a stationary source operator who has a documented t raining and a demonstrated experience performing tune-ups on a unit to the sat isfaction of the APCO. The documentation of tune-up training and experience sh all be made available to the APCO upon request.

3.21 Rated Heat Input (expressed as million Btu per hour): the heat input capacity specified on the nameplate of the unit.SJVUAPCD 4320 - 3 10/16/08

3.22 Refinery Unit: a unit that is permanently ins talled and operated at a petroleum refinery or a gas liquids processing facility.

3.23 Re-ignition: the relighting of a unit after a n unscheduled and unavoidable interruption or shut off of the fuel flow or electr ical power, for a period of less than 30 minutes, due to reasons outside the control of the operator.

3.24 Seasonal Source: as defined in District Rule 2201 (New And Modified Stationary Source Review Rule)

3.25 Shutdown: the period of time during which a u nit is taken from an operational to a non-operational status by allowing it to cool dow n from its operating temperature to ambient temperature as the fuel supp ly to the unit is completely

turned off.

3.26 Solid Fuel: any fuel which is a solid at stan dard conditions.

3.27 Small Producer: as defined in District Rule 1 020 (Definitions)

3.28 Standard Conditions: standard conditions as d efined in Rule 1020 (Definitions).

3.29 Start-up: the period of time during which a u nit is brought from a shutdown status to its operating temperature and pressure, includin g the time required by the unit’s emission control system to reach full operation.

3.30 Unit: any boiler, steam generator or process heater as defined in this rule.

4.0 Exemptions

4.1 This rule shall not apply to:

4.1.1 Solid fuel fired units.

4.1.2 Dryers and glass melting furnaces.

4.1.3 Kilns and smelters where the products of co mbustion come into direct

contact with the material to be heated.

4.1.4 Unfired or fired waste heat recovery boiler s that are used to recover or

augment heat from the exhaust of combustion turbine s or internal combustion engines.

4.2 The requirements of Sections 5.2 shall not appl y to a unit when burning any fuel other than California PUC quality natural gas durin g California PUC quality natural gas curtailment provided all of the following condi tions are met:SJVUAPCD 4320 - 4 10/16/08

4.2.1 Fuels other than California PUC quality nat ural gas are burned no more than

168 cumulative hours in a calendar year plus 48 hou rs per calendar year for equipment testing, as limited by Permit to Operate.

4.2.2 NOx emission shall not exceed 150 ppmv or 0.2 15 lb/MMBtu. Demonstration of compliance with this limit shall b e made by either source testing, continuous emission monitoring system (CEM S), an APCO approved Alternate Monitoring System, or an APCO ap proved portable NOx analyzer.

5.0 Requirements

5.1 An operator of a unit(s) subject to this rule shall comply with all applicable

requirements of the rule and one of the following, on a unit-by-unit basis:

5.1.1 Operate the unit to comply with the emission limits specified in Sections 5.2 and 5.4; or

5.1.2 Pay an annual emissions fee to the District as spec ified in Section 5.3 and comply with the control requirements specified in S ection 5.4; or

5.1.3 Comply with the applicable Low-use Unit requirement s of Section 5.5.

5.2 NOx and CO Emission Limits

5.2.1 On and after the indicated Compliance Deadlin e, units shall not be operated in a manner which exceeds the applicable NOx emissi ons limit specified in Table 1. On and after October 1, 2008, units shall not be operated in a manner to which exceeds a carbon monoxide (CO) emis sions limit of 400

ppmv.

5.2.2 No unit fired on liquid fuel shall be operat ed in a manner to exceed emissions of 40 ppmv NOx and 400 ppmv CO.

5.2.3 All ppmv emission limits specified in this se ction are referenced at dry stack gas conditions and 3.00 percent by volume stack gas oxygen. Emission concentrations shall be corrected to 3.00 percent o xygen in accordance with

Section 8.1.SJVUAPCD 4320 - 5 10/16/08 Table 1: NOx Emission Limits

Category NOx Limit Authority to

Construct Compliance

Deadline
a) Standard Schedule 9 ppmv or 0.011 lb/MMBtu; or July 1, 2011 July 1, 2012 A. Units with a total rated heat input > 5.0 MMBtu/hr to < 20.0 MMBtu/hr, except for Categories C through G units b) Enhanced Schedule 6 ppmv or 0.007

lb/MMBtu January 1, 2013 January 1, 2014

a) Standard Schedule 7 ppmv or 0.008 lb/MMBtu; or July 1, 2009 July 1, 2010 B. Units with a total rated heat input > 20.0 MMBtu/hr, except for Categories C through G units b) Enhanced Schedule 5 ppmv or 0.0062

lb/MMBtu January 1, 2013 January 1, 2014

C. Oilfield Steam Generators

a) Standard Schedule 9 ppmv or 0.011 lb/MMBtu; or July 1, 2011 July 1, 2012 1. Units with a total rated heat input > 5.0 MMBtu/hr to

< 20.0 MMBtu/hr b) Enhanced Schedule 6 ppmv or 0.007

lb/MMBtu January 1, 2013 January 1, 2014

a) Standard Schedule 7 ppmv or 0.008 lb/MMBtu; or July 1, 2009 July 1, 2010

b) Staged Enhanced

Schedule

Initial Limit 9 ppmv or 0.011 lb/MMBtu; and July 1, 2011 July 1, 2012 2. Units with a total rated heat input >20.0 MMBtu/hr

Final Limit 5 ppmv or 0.0062

lb/MMBtu January 1, 2013 January 1, 2014

Staged Enhanced

Schedule

Initial Limit 12 ppmv or 0.014 lb/MMBtu; and July 1, 2010 July 1, 2011 3. Units firing on less than 50%, by volume, PUC quality gas.

Final Limit 9 ppmv or 0.011

lb/MMBtu January 1, 2013 January 1, 2014SJVUAPCD 4320 - 6 10/16/08 Table 1 NOx Emission Limits (continued)

Category NOx Limit Authority to

Construct Compliance

Deadline

D. Refinery units

a) Standard Schedule 9 ppmv or 0.011 lb/MMBtu; or July 1, 2011 July 1, 2012 1. Units with a total rated heat input > 5.0 MMBtu/hr to <

20.0 MMBtu/hr b) Enhanced Schedule 6 ppmv or 0.007

lb/MMBtu January 1, 2013 January 1, 2014

a) Standard Schedule 6 ppmv or 0.007 lb/MMBtu; or July 1, 2010 July 1, 2011

b) Staged Enhanced

Schedule

Initial Limit 9 ppmv or 0.011 lb/MMBtu; and July 1, 2011 July 1, 2012 2. Units with a total rated heat input >20.0 MMBtu/hr to <

110.0 MMBtu/hr

Final Limit 5 ppmv or 0.0062

lb/MMBtu January 1, 2013 January 1, 2014

3. Units with a total rated heat input > 110.0 MMBtu/hr Standard Schedule 5 ppmv or 0.0062

lb/MMBtu N/A June 1, 2007

Staged Enhanced

Schedule

Initial Limit 12 ppmv or 0.014 lb/MMBtu; and July 1, 2010 July 1, 2011 4. Units firing on less than 50%, by volume, PUC quality gas.

Final Limit 9 ppmv or 0.011

lb/MMBtu January 1, 2013 January 1, 2014

E. Units, from any Category, that were installed prior to January 1, 2009 and limited by a Permit to Operate to an annual heat input >1.8 billion Btu/year but < 30 billion Btu/year. Standard Schedule 9 ppmv or 0.011

lb/MMBtu Twelve months

before the next unit replacement but no later than January 1, 2013. At the next unit

replacement but

no later than January 1, 2014SJVUAPCD 4320 - 7 10/16/08 Table 1 NOx Emission Limits (continued)

Category NOx Limit Authority to

Construct Compliance

Deadline Staged Enhanced

Schedule

Initial Limit 12 ppmv or 0.014 lb/MMBtu; and July 1, 2010 July 1, 2011 F. Units at a wastewater treatment facility firing on less than 50%, by volume, PUC quality gas. Final Limit 9 ppmv or 0.011

lb/MMBtu January 1, 2013 January 1, 2014

G. Units operated by a small producer in which the rated heat input of each burner is less than or equal to 5

MMBtu/hr but the total rated heat input of all the burners in

a unit is rated between 5 MMBtu/hr and 20 MMBtu/hr, as specified in the Permit to Operate, and in which the products of combustion do not

come in contact with the products of combustion of any

other burner. Standard Schedule 9 ppmv or 0.011

lb/MMBtu Twelve months

before the next unit replacement but no later than January 1, 2013. At the next unit

replacement but

no later than January 1, 2014

5.2.4 When a unit is operated on combinations of ga seous fuel and liquid fuel, the NOx limit shall be the heat input weighted average of the applicable limits specified in Sections 5.1.1, as calculated by the f ollowing equation:

L G )L x fuel liquid for limit NOx ( ) G x fuel gaseous for limit NOx ( Limit Average Weighted

+ +

=

Where: G = annual heat input from gaseous fuel

L = annual heat input from liquid fuel

5.2.5 Prior to January 1, 2014, if a unit was desi gnated to comply with a Staged Enhanced Schedule, an operator may redesignate the unit for compliance under Section 5.1.2, provided the unit meets the In itial NOx Limit; emission fees are paid, at time of the application for redesignation, for all past emissions from the unit since January 1, 2009 through the calendar year prior to the calculation date; and the total a nnual fee is paid from that date forward. The past emissions fee shall be calc ulated using the equations in Section 5.3 and the Fee Rate in place at the time of thatSJVUAPCD 4320 - 8 10/16/08 calculation. The future total annual fees shall be calculated and paid according to Section 5.3.

5.3 Annual Fee Calculation

5.3.1 On and after January 1, 2010, an operator, wi th units that will comply under Section 5.1.2, shall pay a total annual fee to the District based on the total

NOx emissions from those units. That fee shall be calculated in the following manner.

5.3.1.1 The operator shall calculate the total emis sions for all units operating at a stationary source that will comply w ith Section

5.1.2. The total NOx emissions shall be calculated in accordance

with Section 5.3.1.3.

5.3.1.2 The total annual emissions fee shall be cal culated in accordance

with Section 5.3.1.4. These calculations include o nly the units that have been identified to comply under Section 5.1.2.

5.3.1.3 Total Emissions (TE) Calculation

Total TE = ∑ E(unit)

Where: ∑ E(unit) = Sum of all NOx emissions from each unit , in tons

per year.

E(unit) =

ton per lb Unit AFU x Unit EF

000 ,2 )

( ) (

Where: E(unit) = Annual NOx emissions for each uni t, in tons/year.

EF(Unit) = NOx Emission Limit for the Permit to O perate, in

lb/MMBtu

AFU(Unit) = actual amount of fuel, in MMBTU, used b y each

unit during the previous calendar year.

5.3.1.4 Total Annual Fee Calculation

Total Annual Fee = (Total TE x FR) + Administrativ e Fee

Where: FR (Fee Rate) = The cost of NOx reductions , in dollars per ton, as established pursuant to Sections 7.2 and 7.6 of District Rule 9510, as adopted on December 15, 2005. Under no circumstances shall the cost

of NOx reductions exceed the cost effectivenessSJVUAPCD 4320 - 9 10/16/08 threshold for the Carl Moyer Cost Effectiveness as established by the applicable state law.

Administrative Fee = 4% x (Total TE x FR)

5.3.1.5 The operator shall pay the total annual fee to the District, no later than July 1 of each year, for the emissions of the previous calendar year. The first payment is due to the District no later than July 1, 2010. Should July 1 fall on a day when the Distric t is closed, the payment shall be made by the next District working day after July

1.

5.3.2 Payments shall continue annually until the un it either is permanently removed from use in the San Joaquin Valley Air Basi n and the Permit to Operate is surrendered or the operator demonstrates compliance with applicable NOx emissions limits shown in Table 2:

Table 2 Applicable NOx Emission Limits for Section 5.3.2

Category Date of Compliance

Demonstration Applicable NOx Emissions

Limit from Table 1

A. Units with only a Standard

Schedule in Table 1. Either prior to or after

the Standard Compliance Deadline Standard NOx Limit

Prior to the Enhanced Compliance Deadline Standard NOx Limit B. Units with both Standard and

Enhanced Schedules in Table

1. After the Enhanced Compliance Deadline Enhanced NOx Limit

Prior to the Initial Limit Compliance Deadline Standard NOx Limit

After the Initial Limit

Deadline but before the

Final Limit Deadline Initial NOx Limit then the Final NOx Limit by the applicable Compliance Deadline C. Units with both Standard and Staged Enhanced

Schedules in Table 1.

After the Final Limit

Deadline Final NOx Limit

5.3.2.1 The emissions fee for units that operate fo r less than the full calendar year before demonstrating compliance under Section 5.3.2, shall be based on the actual fuel used durin g the portion of the calendar year prior to demonstrating that compl iance orSJVUAPCD 4320 - 10 10/16/08 removing the unit from operation within the San Joa quin Valley

Air Basin.

5.3.3 Operators of units for which an annual emissi ons fee is provided must also certify that the units meet federal RACT control re quirements at the time the annual fee is provided.

5.4 Particulate Matter Control Requirements

5.4.1 To limit particulate matter emissions, an op erator shall comply with one of

the following requirements:

5.4.1.1 On and after the applicable NOx Compliance Deadline specified

in Section 5.2 Table 1, operators shall fire units exclusively on PUC-quality natural gas, commercial propane, butane , or liquefied petroleum gas, or a combination of such g ases;

5.4.1.2 On and after the applicable NOx Compliance Deadline specified

in Section 5.2 Table 1, operators shall limit fuel sulfur content to no more than five (5) grains of total sulfur per on e hundred (100) standard cubic feet; or

5.4.1.3 On and after the applicable NOx Compliance Deadline specified in Section 5.2 Table 1, operators shall install and properly operate an emission control system that reduces SO

2 emissions by at least 95% by weight; or limit exhaust SO

2 to less than or equal to 9 ppmv corrected to 3.0% O2.

5.4.1.4 Notwithstanding the compliance deadlines in dicated in Sections

5.4.1.1 through 5.4.1.3, refinery units, which requ ire modification of refinery equipment to reduce sulfur emissions, shall be in compliance with the applicable requirem ent in Section 5.4.1 no later than July 1, 2013.

5.4.2 Liquid fuel shall be used only during PUC qua lity natural gas curtailment periods, provided the requirements of Sections 4.2 and 6.1.5 are met and the fuel contains no more than 15 ppm sulfur, as determ ined by the test method specified in Section 6.2.SJVUAPCD 4320 - 11 10/16/08

5.5 Low-use Unit

For each unit that was installed prior to January 1, 2009 and is limited to less than or equal to 1.8 billion Btu per calendar year heat inp ut pursuant to a District Permit to Operate, the operator shall comply with the require ment of Sections 5.7 and 7.3 and one of the following:

5.5.1 Tune the unit at least twice per calendar y ear, (from four to eight months

apart) by a qualified technician in accordance with the procedure described in Rule 4304 (Equipment Tuning Procedure for Boiler s, Steam Generators, and Process Heaters). If the unit does not operate throughout a continuous six-month period within a calendar year, only one t une-up is required for that calendar year. No tune-up is required for any unit that is not operated during that calendar year; this unit may be test fi red to verify availability of the unit for its intended use, but once the test fi ring is completed the unit shall be shutdown; or

5.5.2 Operate the unit in a manner that maintains exhaust oxygen concentrations

at less than or equal to 3.00 percent by volume on a dry basis.

5.6 Start-up and Shutdown Provision

On and after the Compliance Deadline specified in S ection 5.0, the applicable

emission limits of Sections 5.2 Table 1 and 5.5.2 s hall not apply during start-up or shutdown, provided an operator complies with the re quirements specified below.

5.6.1 The duration of each start-up or each shutdow n shall not exceed two hours, except as provided in Section 5.6.3.

5.6.2 The emission control system shall be in opera tion and emissions shall be minimized insofar as technologically feasible durin g start-up or shutdown.

5.6.3 Notwithstanding the requirement of Section 5 .6.1, an operator may submit an application for a Permit to Operate condition to allow more than two hours for each start-up or each shutdown provided t he operator meets all of the conditions specified in Sections 5.6.3.1 throug h 5.6.3.3.

5.6.3.1 The maximum allowable duration of start-up or shutdown will

be determined by the APCO. The allowable duration of start-up

shall not exceed twelve hours and the allowable dur ation of

shutdown shall not exceed nine hours.

5.6.3.2 The APCO will only approve start-up or shu tdown duration

longer than two hours when the application meets th e following

conditions:SJVUAPCD 4320 - 12 10/16/08

5.6.3.2.1 Clearly identifies the control techn ologies or strategies to be utilized; and

5.6.3.2.2 Describes what physical conditions pr evail during start-up or shutdown periods that prevent the controls from being effective; and

5.6.3.2.3 Provides a reasonably precise estimat e as to when the physical conditions will have reached a state

that allows for the effective control of emissions

.

5.6.3.3 The operator shall submit to the APCO a ny information deemed necessary by the APCO to determine the appropriate length of start-up or shutdown. The information shall includ e, but is not limited to the following:

5.6.3.3.1 A detailed list of activities to be perfo rmed during

start-up or shutdown and a reasonable explanation for the length of time needed to complete each activity; and

5.6.3.3.2 A description of the material proce ss flow rates

and system operating parameters, etc., the operator plans to evaluate during the process optimization; and an explanation of how the activities and process flow affect the operation of the emissions control equipment; and

5.6.3.3.3 The basis for the requested addit ional duration of

start-up or shutdown.

5.6.4 Permit to Operate (PTO) modifications solely to conditions to comply with the provisions of this rule may be exempt from Best Available Control Technology (BACT) and emission offset requi rements if the PTO modifications meet the requirements of Rule 2201 (N ew and Modified Stationary Source Review Rule) Section 4.2 (BACT Ex emptions) and Rule 2201 Section 4.6 (Emission Offset Exemptions).

5.6.5 For existing facilities, a replacement unit i nstalled for the sole purpose of complying with the requirements of this rule shall be considered to be an emission control technique and may be exempt from t he Best Available Control Technology (BACT) and Offsets requirements of District Rule 2201 (New and Modified Stationary Source Review Rul e) provided that all other requirements of Rule 2201 are met.

5.7 Monitoring ProvisionsSJVUAPCD 4320 - 13 10/16/08

5.7.1 The operator of any unit subject to the app licable emission limits in Sections

5.2 shall install and maintain an operational APCO approved Continuous Emissions Monitoring System (CEMS) for NOx, CO, and oxygen, or implement an APCO-approved Alternate Monitoring Sys tem. An APCO approved CEMS shall comply with the requirements of 40 Code of Federal Regulations (CFR) Part 51, 40 CFR Parts 60.7 and 60 .13 (except subsection h), 40 CFR Part 60 Appendix B (Performance Specific ations) and 40 CFR Part 60 Appendix F (Quality Assurance Procedures), and applicable provisions of Rule 1080 (Stack Monitoring). An APC O-approved Alternate Monitoring System shall monitor one or more of the following:

5.7.1.1 Periodic NOx and CO exhaust emission co ncentrations, 5.7.1.2 Periodic exhaust oxygen concentration, 5.7.1.3 Flow rate of reducing agent added to ex haust, 5.7.1.4 Catalyst inlet and exhaust temperature,

5.7.1.5 Catalyst inlet and exhaust oxygen concentra tion, 5.7.1.6 Periodic flue gas recirculation rate, or 5.7.1.7 Other operational characteristics.

5.7.2 For units subject to the requirements of Sect ions 5.5.1 or 5.5.2, the operator shall monitor, at least on a monthly basis, the ope rational characteristic(s) recommended by the manufacturer and approved by the APCO.

5.7.3 The operator of any unit subject to Section 5 .5 shall install and maintain an operational non-resettable, totalizing mass or volu metric flow meter in each

fuel line to each unit. Volumetric flow measurement s shall be periodically compensated for temperature and pressure. A master meter, which measures fuel to all units in a group of similar units, may satisfy these requirements if approved by the APCO in writing. The cumulative an nual fuel usage may be verified from utility service meters, purchase o r tank fill records, or other acceptable methods, as approved by the APCO.

5.7.4 Units operated at seasonal sources that are subject to the requirements of 40 CFR 60, Subpart Db (Standards of Performance forIndustrialCommercial-Institutional Steam Generating Units) ma y implement an APCO approved parametric monitoring system (PMS) in lieu of a CEMS for compliance with federal emission limits provide d all of the following apply:

5.7.4.1 The boiler is fired solely on California PUC qualit y natural gas,

and

5.7.4.2 The applicable District emission limit for NOx is m ore

stringent than the limit specified in 40 CFR Part 6 0, Subpart

Db.

5.7.5 The APCO shall not approve an alternative monitorin g system or parametric monitoring system unless it is documented that continuedSJVUAPCD 4320 - 14 10/16/08 operation within ranges of specified emissions-rela ted performance indicators or operational characteristics provides a reasonable assurance of compliance with applicable emission limits. The op erator shall source test over the proposed range of surrogate operating para meters to demonstrate compliance with the applicable emission standards.

5.7.5.1 The predictive or parametric monitoring sys tem shall continuously monitor the key parameters which affec t the emissions and demonstrate the compliance within the established key parameters operating envelope.

5.7.5.2 Initial and annual real time modeling shall be performed to verify the key parameters operational range.

5.7.6 Monitoring SOx Emissions

5.7.6.1 Operators complying with Sections 5.4.1.1 o r 5.4.1.2 shall

provide an annual fuel analysis to the District unl ess a more frequent sampling and reporting period is included in the Permit To Operate. Sulfur analysis shall be performed in accordance

with the test methods in Section 6.2.

5.7.6.2 Operators complying with Section 5.4.1.3 by installing and operating a control device with 95% SOx reduction s hall propose the key system operating parameters and fre quency of the monitoring and recording. The monitoring optio n proposed shall be submitted for approval by the APCO.

5.7.6.3 Operators complying with Section 5.4.1.3 sh all perform an

annual source test unless a more frequent sampling and reporting period is included in the Permit To Opera te. Source tests shall be performed in accordance with the tes t methods in

Section 6.2.SJVUAPCD 4320 - 15 10/16/08

5.8 Compliance Determination

5.8.1 The operator of any unit shall have the opt ion of complying with either the

applicable heat input, in lb/MMBtu, emission limits or the concentration, in ppmv, emission limits specified in Section 5.2. The emission limits selected to demonstrate compliance shall be specified in the source test proposal pursuant to Rule 1081 (Source Sampling).

5.8.2 All emissions measurements shall be made with the unit operating either at conditions representative of normal operations or c onditions specified in the Permit to Operate. Unless otherwise specified in t he Permit to Operate, no determination of compliance shall be established wi thin two hours after a continuous period in which fuel flow to the unit is shut off for 30 minutes or longer, or within 30 minutes after a re-ignition as defined in Section 3.0.

5.8.3 Continuous Emissions Monitoring System (CEM S) emissions

measurements shall be averaged over a period of 15 consecutive minutes to demonstrate compliance with the applicable emission limits. Any 15- consecutive-minute block average CEMS measurement e xceeding the applicable emission limits shall constitute a viola tion.

5.8.4 For emissions monitoring pursuant to Sections 5.7.1, and 6.3.1 using a portable NOx analyzer as part of an APCO approved A lternate Emissions Monitoring System, emission readings shall be avera ged over a 15 consecutive-minute period by either taking a cumula tive 15-consecutiveminute sample reading or by taking at least five re adings evenly spaced out over the 15-consecutive-minute period.

5.8.5 For emissions source testing performed pursua nt to Section 6.3.1 for the purpose of determining compliance with an applicabl e standard or numerical limitation of this rule, the arithmetic average of three 30-consecutive-minute test runs shall apply. If two of three runs are ab ove an applicable limit the test cannot be used to demonstrate compliance with an applicable limit.

6.0 Administrative Requirements

6.1 Recordkeeping

The records required by Sections 6.1.1 through 6. 1.5 shall be maintained for five

calendar years and shall be made available to the A PCO and EPA upon request.

Failure to maintain records or information containe d in the records that demonstrate noncompliance with the applicable requirements of t his rule shall constitute a

violation of this rule. 6.1.1 The operator of any unit operated under the exemption of Section 4.2 shall

monitor and record, for each unit, the cumulative a nnual hours of operation on each fuel other than natural gas during periods of natural gas curtailmentSJVUAPCD 4320 - 16 10/16/08 and equipment testing. The NOx emission concentrat ion, expressed in ppmv or lb/MMBtu, for each unit that is operated du ring periods of natural gas curtailment shall be recorded. Failure to main tain records required by

Section 6.1.1 or information contained in the recor ds that demonstrates noncompliance with the conditions for exemption und er Section 4.2 will result in loss of exemption status. On and after t he applicable compliance schedule specified in Section 5.2 Table 1, any unit losing an exemption status shall be brought into full compliance with t his rule as specified in

Section 7.2.

6.1.2 The operator of any unit that is subject to the requirements of Section 5.5

shall record the amount of fuel use at least on a m onthly basis for each unit. On and after the applicable compliance schedule spe cified in Section 7.0, in the event that such unit exceeds the applicable ann ual heat input limit specified in Section 5.5, the unit shall be brought into full compliance with this rule as specified in Section 5.2 Table 1.

6.1.3 The operator of any unit subject to Section 5.5.1 or Section 6.3.1 shall

maintain records to verify that the required tune-u p and the required monitoring of the operational characteristics of th e unit have been performed.

6.1.4 The operator performing start-up or shutdow n of a unit shall keep records of

the duration of start-up or shutdown.

6.1.5 The operator of any unit firing on liquid fue l during a PUC-quality natural gas curtailment period pursuant to Section 5.4.2 sh all record the sulfur content of the fuel, amount of fuel used, and durat ion of the natural gas curtailment period.

6.2 Test Methods

The following test methods shall be used unless oth erwise approved by the APCO

and EPA.

6.2.1 Fuel hhv shall be certified by third party fuel supplier or determined by:

6.2.1.1 ASTM D 240-87 or D 2382-88 for liquid hydr ocarbon fuels;

6.2.1.2 ASTM D 1826-88 or D 1945-81 in conjuncti on with ASTM D 3588-89 for gaseous fuels.

6.2.2 Oxides of nitrogen (ppmv) - EPA Method 7E, or ARB Method 100. 6.2.3 Carbon monoxide (ppmv) - EPA Method 10, or ARB Method 100. 6.2.4 Stack gas oxygen - EPA Method 3 or 3A, or A RB Method 100. 6.2.5 NOx Emission Rate (Heat Input Basis) - EPA Method 19.SJVUAPCD 4320 - 17 10/16/08

6.2.6 Stack gas velocities - EPA Method 2. 6.2.7 Stack gas moisture content - EPA Method 4.

6.2.8 SOx Test Methods

6.2.8.1 Oxides of sulfur – EPA Method 6C, EPA Metho d 8, or ARB

Method 100

6.2.8.2 The SOx emission control system efficiency shall be determined using the following:

% Control Efficiency = [(C SO2, inlet – C SO2, outlet ) / C SO2, inlet ] X 100

Where:

C SO2, inlet = concentration of SOx (expressed as SO

2 ) at the inlet

side of the SOx emission control system, in

lb/dscf

C SO2, outlet = concentration of SOx (expressed as SO

2 ) at the

outlet side of the SOx emission control system, in

lb/dscf

6.2.9 Determination of total sulfur as hydrogen sul fide (H

2 S) content – EPA Method 11 or EPA Method 15, as appropriate.

6.2.10 Sulfur content of liquid fuel – American Soc iety for Testing and Materials (ASTM) D 6920-03 or ASTM D 5453-99

6.3 Compliance Testing

6.3.1 Each unit subject to the requirements in Se ction 5.2 shall be source tested to

determine compliance with the applicable emission l imits at least once every 12 months, (no more than 30 days before or after th e required annual source test date).

6.3.1.1 Units that demonstrate compliance on two co nsecutive 12-month source tests may defer the following 12-month sourc e test for up to 36 months (no more than 30 days before or after the required 36- month source test date). During the 36-month sour ce testing interval, the operator shall tune the unit in accor dance with the provisions of Section 5.5.1, and shall monitor, on a monthly basis, the unit’s operational characteristics recommended by the manufacturer to ensure compliance with the applicab le emission limits specified in Section 5.2.SJVUAPCD 4320 - 18 10/16/08 6.3.1.2 Tune-ups required by Sections 5.5.1 and 6.3 .1 do not need to be performed for units that operate and maintain an AP CO approved CEMS or an APCO approved Alternate Monitoring Syste m where the applicable emission limits are periodically mon itored.

6.3.1.3 If the result of the 36-month source test d emonstrates that the unit does not meet the applicable emission limits specif ied in Section 5.2, the source testing frequency shall revert to a t least once every

12 months.

6.3.1.4 Failure to comply with the requirements of Section 6.3.1 or any source test results that exceed the applicable emis sion limits in

Section 5.2 shall constitute a violation of this ru le.

6.3.2 In lieu of compliance with Section 6.3.1, complianc e with the applicable

emission limits in Section 5.2 shall be demonstrate d by submittal of annual

emissions test results to the District from a unit or units that represents a group of units, provided:

6.3.2.1 All units in the group are initially sou rce tested. The emissions from all test runs from units within the group are less than 90% of the permitted value, and the emissions do not va ry greater than 25% from the average of all test runs; and

6.3.2.2 All units in a group are similar in term s of rated heat input, make and series, operational conditions, fuel used, and control method. No unit with a rated heat input greater than 100 MM Btu shall be considered as part of the group; and

6.3.2.3 The group is owned by a single owner and is located at a single stationary source; and

6.3.2.4 Selection of the representative unit(s) is approved by the APCO prior to testing; and

6.3.2.5 The number of representative units sourc e tested shall be at least 30% of the total number of units in the group. The representative tests shall rotate each year so that within three years all units in the group have been tested at le ast once.

6.3.2.6 All units in the group shall have received the s imilar

maintenance and tune-up procedures as the represent ative unit(s) as listed in the Permit to Operate. The operator s hall submit to the APCO the specific maintenance procedures to be performed on each unit that will be included in the group for representative testing. Such maintenance procedures shall be spec ified in theSJVUAPCD 4320 - 19 10/16/08 Permit to Operate for units that are included in th e group for representative testing. Any maintenance work on a unit which

has no effect on emissions standards and which is n ot specified in the maintenance procedures shall be submitted to the APCO for approval before such unit can be included as pa rt of the group for representative testing. Any unit that necessit ates any
maintenance work which has an effect on emission st andards and is beyond the maintenance procedures identified in the Permit to Operate, shall not be included as part of the group for representative testing. The unit shall be source t ested in accordance with the provisions of Section 6.3.1; an d

6.3.2.7 Should any of the representative units e xceed the required emission limits, each of the units in the group sha ll demonstrate compliance by emissions testing. Failure to comple te emissions testing within 90 days of the failed test shall res ult in the untested units being in violation of this rule. After compl iance with the requirements of Section 6.3.2.7 has been demonstrat ed, subsequent source testing shall be performed pursua nt to
Sections 6.3.1 or 6.3.2.

6.4 Emission Control Plan (ECP)

6.4.1 No later than January 1, 2010, the operator of any unit shall submit to the APCO for approval an Emissions Control Plan accordi ng to the compliance schedule in Section 7.0. For each unit, the plan s hall contain the following:

6.4.1.1 Permit to Operate number, 6.4.1.2 Fuel type and hhv, 6.4.1.3 Annual fuel consumption (expressed as Bt u/yr),

6.4.1.4 Current emission level, including method used to determine emission level,

6.4.1.5 NOx limit to be satisfied pursuant to Section 5.2 T able 1 or emission fee payment to be made pursuant to Section 5.3, and 6.4.1.6 Plan of actions, including a schedule of increments of progress, which will be taken to satisfy the requirements of Section 5.0 and the compliance schedule in Section 7.0.SJVUAPCD 4320 - 20 10/16/08

7.0 Compliance Schedule

7.1 As shown in Section 5.2 Table 1, the column lab eled:

7.1.1 “Authority to Construct” identifies the dat e by with the operator shall submit

an Application for Authority to Construct for each unit subject to the rule.

7.1.2 “Compliance Deadline” identifies the date b y which the owner shall

demonstrate that each unit is in compliance with th e applicable requirements

of this rule.

7.2 Any unit that is exempted under Section 4.2 th at becomes subject to the emission

limits of this rule through the loss of exemption s tatus shall be in full compliance with this rule on and after the date the exemption status is lost.

7.3 Any unit that becomes subject to the emission limits of this rule as a result of

exceeding the applicable annual heat input limit sp ecified in Section 5.5 shall be in compliance with the applicable emission limits in S ection 5.2 Table 1 and Section 5.4 on and after the date the annual heat input lim it is exceeded.

8.0 Calculations

8.1 All ppmv emission limits specified in Section 5.2 are referenced at dry stack gas

conditions and 3.00 percent by volume stack gas oxy gen. Emission concentrations shall be corrected to 3.00 percent oxygen as follow s:

measured measured corrected ] NOx ppm [ x ]2 O [% % 95. 20 %

95. 17 ] NOx ppm [

−

=

measured

measured corrected ] CO ppm [ x ]2 O [% % 95. 20 %

95. 17 ] CO ppm [

−

=

8.2 All pounds per million Btu NOx emission rates shall be calculated as pounds of

nitrogen dioxide per million Btu of heat input (exp ressed as hhv).