DOCKET

07-AFC-3

 DATE 03/02/10

 RECD. MAR. 0 03/04/10

PROOF OF SERVICE ( REVISED 2/16/10 ) FILED WITH

ORIGINAL MAILED FROM SACRAMENTO ON 3/4/10

MS

SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 1

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

CPV SENTINEL, LLC; ADDENDUM TO THE DETERMINATION 

OF COMPLIANCE (DOC) ENGINEERING ANALYSIS

FOR A NEW 850 MW SIMPLE CYCLE POWER PLANT 

COMPANY NAME AND ADDRESS EQUIPMENT LOCATION

CPV Sentinel , LLC 62575 Power Line Rd.

55 Second Street Desert Hot Springs, CA 92440

Suite 525

San Francisco, CA 94105

Contact: Mr. Mark Turner

AQMD Facility ID: 152707

EQUIPMENT DESCRIPTION

Section H of the Facility Permit

Equipment ID 

No.

Connected To RECLAIM 

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES, POWER GENERATION 

GAS TURBINE, CTG 1, NATURAL GAS, 

GENERAL ELECTRIC MODEL LMS100PA, 

SIMPLE CYCLE, 891.7 MMBTU/HR AT 72

DEGREES F WITH WATER INJECTION, 

WITH

A/N 472139

GENERATOR, 103 MW

D1 C3 NOX: MAJOR 

SOURCE

CO: 4.0 PPMV

NATURAL GAS (4) [Rule 

1703 (a)(2)-BACT]; CO: 

2000 PPMV (5) [Rule 

407] 

NOX: 15 PPMV

NATURAL GAS (8) 

[40CFR60 Subpart 

KKKK];NOX: 19

LB/MMCF (1) [Rule 2012]

NOX 12.26 LB/MMCF

NATURAL GAS (1)[Rule 

2012] NOX 2.5 PPMV

NATURAL GAS (4)[Rule 

2005-BACT, Rule 1703 

(a)(2)-BACT]

VOC: 2.0 PPMV (4)[Rule 

1303(a)(1)-BACT]

PM10: 0.01 GRAIN/DSCF 

(5A) [Rule 475]; PM10: 

0.1 GRAIN/DSCF (5) 

[Rule 409]; PM10: 11 

LB/HR (5B) [Rule 475]

SOX: .06 lb/MMBTU (8) 

[40 CFR60 Subpart 

KKKK]; SO2: (9) Acid 

Rain Provisions

A63.1, A63.2 

A99.1, A99.3,

A99.5, A99.7,

A99.9 A195.1,

A195.2, A195.3,

A327.1, A443.1, 

B61.1, C1.1,C1.3,

C1.6, D12.1,

D29.1, D29.2,

D29.3, D82.1,

D82.2, E193.1, 

H23.1, I296.1,

K40.1, K67.1
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 2

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

EQUIPMENT DESCRIPTION (continued)

Equipment ID 

No.

Connected To RECLAIM

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES POWER GENERATION

CO OXIDATION CATALYST NO. 1, BASF, 

150 CUBIC FEET OF TOTAL CATALYST 

VOLUME

A/N: 472140

C3 D1 C4

SELECTIVE CATALYTIC REDUCTION

NO. 1, CORMETECH CHMT-2, WITH 812

CUBIC FEET OF TOTAL CATALYST 

VOLUME, LENGTH 11 FT 1 IN; WIDTH: 2 

FT 2 IN; HEIGHT 4 FT 2 IN;

WITH 

NH3 INJECTION GRID 

A/N: 472140

C4 S6 C3 NH3: 5.0 PPMV (4) 

[Rule 1303(a)(1)-BACT]

A195.4

D12.2

D12.3

D12.4

E179.1

E179.2,E193.1, 

E193.3

STACK NO. 1, DIAMETER: 13 FT 6 IN, 

HEIGHT: 90 FT 

A/N: 472140

S6 C4

GAS TURBINE, CTG 2, NATURAL GAS, 

GENERAL ELECTRIC MODEL LMS100PA, 

SIMPLE CYCLE, 861.7 MMBTU/HR AT 72

DEGREES F WITH WATER INJECTION, 

WITH

A/N 472141 

GENERATOR, 103 MW

D7 C9 NOX: MAJOR 

SOURCE

CO: 4.0 PPMV 

NATURAL GAS (4) 

[Rule 1703 (a)(2)-

BACT]; CO: 2000 

PPMV (5) [Rule 407] 

NOX: 15 PPMV

NATURAL GAS (8) 

[40CFR60 Subpart 

KKKK];NOX: 19 

LB/MMCF (1) [Rule 

2012] NOX 12.26

LB/MMCF NATURAL 

GAS (1)[Rule 2012]

NOX 2.5 PPMV

NATURAL GAS (4)[Rule 

2005-BACT, Rule 1703 

(a)(2)-BACT]

VOC: 2.0 PPMV

(4)[Rule 1303(a)(1)-

BACT]

PM10: 0.01 

GRAIN/DSCF (5A) [Rule 

475]; PM10: 0.1 

GRAIN/DSCF (5) [Rule 

409]; PM10: 11 LB/HR 

(5B) [Rule 475

SOX: .06 lb/MMBTU (8) 

[40 CFR60 Subpart 

KKKK]; SO2: (9) Acid 

Rain Provisions

A63.1, A63.2,

A99.1, A99.3, 

A99.5, A99.7, 

A99.9 A195.1, 

A195.2, A195.3, 

A327.1, A443.1, 

B61.1, C1.1,C1.3, 

C1.6, D12.1, 

D29.1, D29.2,

D29.3, D82.1, 

D82.2, E193.1, 

H23.1, I296.1, 

K40.1, K67.1
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 3

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

EQUIPMENT DESCRIPTION (continued)

Equipment ID 

No.

Connected To RECLAIM

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES POWER GENERATION

CO OXIDATION CATALYST NO. 2, BASF, 

150 CUBIC FEET OF TOTAL CATALYST 

VOLUME

A/N: 472142

C9 D7 C10

SELECTIVE CATALYTIC REDUCTION

NO. 2, CORMETECH CHMT-2, WITH 812

CUBIC FEET OF TOTAL CATALYST 

VOLUME, LENGTH 11 FT 1 IN; WIDTH: 2 

FT 2 IN; HEIGHT 4 FT 2 IN;;

WITH 

NH3 INJECTION GRID 

A/N: 472142

C10 S12 C9 NH3: 5.0 PPMV (4) 

[Rule 1303(a)(1)-BACT]

A195.4

D12.2

D12.3

D12.4

E179.1

E179.2,E193.1, 

E193.3

STACK NO. 2, DIAMETER: 13 FT 6 IN, 

HEIGHT: 90 FT 

A/N: 472142

S12 C10

GAS TURBINE, CTG. 3, NATURAL GAS, 

GENERAL ELECTRIC MODEL LMS100PA, 

SIMPLE CYCLE, 891.7 MMBTU/HR AT 72

DEGREES F WITH WATER INJECTION, 

WITH

A/N 472143 

GENERATOR, 103 MW

D13 C14 NOX: MAJOR 

SOURCE

CO: 4.0 PPMV 

NATURAL GAS (4) 

[Rule 1703 (a)(2)-

BACT]; CO: 2000 

PPMV (5) [Rule 407] 

NOX: 15 PPMV

NATURAL GAS (8) 

[40CFR60 Subpart 

KKKK];NOX: 19 

LB/MMCF (1) [Rule 

2012] NOX 12.26

LB/MMCF NATURAL 

GAS (1)[Rule 2012]

NOX 2.5 PPMV

NATURAL GAS (4)[Rule 

2005-BACT, Rule 1703 

(a)(2)-BACT]

VOC: 2.0 PPMV

(4)[Rule 1303(a)(1)-

BACT]

PM10: 0.01 

GRAIN/DSCF (5A) [Rule 

475]; PM10: 0.1 

GRAIN/DSCF (5) [Rule 

409]; PM10: 11 LB/HR 

(5B) [Rule 475] 

SOX: .06 lb/MMBTU (8) 

[40 CFR60 Subpart 

KKKK]; SO2: (9) Acid 

Rain Provisions

A63.1, A63.2,

A99.1, A99.3, 

A99.5, A99.7, 

A99.9 A195.1, 

A195.2, A195.3, 

A327.1, A443.1, 

B61.1, C1.1,C1.3, 

C1.6, D12.1, 

D29.1, D29.2,

D29.3, D82.1, 

D82.2, E193.1, 

H23.1, I296.1, 

K40.1, K67.1
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 4

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Equipment Description (Continued)

Equipment ID 

No.

Connected To RECLAIM

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES POWER GENERATION

CO OXIDATION CATALYST NO. 3, BASF, 

150 CUBIC FEET OF TOTAL CATALYST 

VOLUME

A/N: 472145

C15 D13 C16

SELECTIVE CATALYTIC REDUCTION

NO. 3, C CORMETECH CHMT-2, WITH 

812 CUBIC FEET OF TOTAL CATALYST 

VOLUME, LENGTH 11 FT 1 IN; WIDTH: 2 

FT 2 IN; HEIGHT 4 FT 2 IN;

WITH 

NH3 INJECTION GRID 

A/N: 472145

C16 S18 C15 NH3: 5.0 PPMV (4) 

[Rule 1303(a)(1)-BACT]

A195.4

D12.2

D12.3

D12.4

E179.1

E179.2,E193.1, 

E193.3

STACK NO. 3, DIAMETER: 13 FT 6 IN, 

HEIGHT: 90 FT 

A/N: 472145

S18 C16

GAS TURBINE, CTG 4, NATURAL GAS, 

GENERAL ELECTRIC MODEL LMS100PA, 

SIMPLE CYCLE, 891.7 MMBTU/HR AT 72

DEGREES F, WITH WATER INJECTION,

WITH

A/N 472147 

GENERATOR, 103 MW

D19 C21 NOX: MAJOR 

SOURCE

CO: 4.0 PPMV 

NATURAL GAS (4) 

[Rule 1703 (a)(2)-

BACT]; CO: 2000 

PPMV (5) [Rule 407] 

NOX: 15 PPMV

NATURAL GAS (8) 

[40CFR60 Subpart 

KKKK];NOX: 19 

LB/MMCF (1) [Rule 

2012] NOX 12.26

LB/MMCF NATURAL 

GAS (1)[Rule 2012]

NOX 2.5 PPMV

NATURAL GAS (4)[Rule 

2005-BACT, Rule 1703 

(a)(2)-BACT]

VOC: 2.0 PPMV

(4)[Rule 1303(a)(1)-

BACT]

PM10: 0.01 

GRAIN/DSCF (5A) [Rule 

475]; PM10: 0.1 

GRAIN/DSCF (5) [Rule 

409]; PM10: 11 LB/HR 

(5B) [Rule 475] 

SOX: .06 lb/MMBTU (8) 

[40 CFR60 Subpart 

KKKK]; SO2: (9) Acid 

Rain Provisions

A63.1, A63.2,

A99.1, A99.3, 

A99.5, A99.7, 

A99.9 A195.1, 

A195.2, A195.3, 

A327.1, A443.1, 

B61.1, C1.1,C1.3, 

C1.6, D12.1, 

D29.1, D29.2,

D29.3, D82.1, 

D82.2, E193.1, 

H23.1, I296.1, 

K40.1, K67.1
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 5

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Equipment Description (Continued)

Equipment ID 

No.

Connected To RECLAIM

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES POWER GENERATION

CO OXIDATION CATALYST NO. 4, BASF, 

150 CUBIC FEET OF TOTAL CATALYST 

VOLUME

A/N: 472149

C21 D19 C22

SELECTIVE CATALYTIC REDUCTION

NO. 4, CORMETECH CHMT-2, WITH 812

CUBIC FEET OF TOTAL CATALYST 

VOLUME, LENGTH 11 FT 1 IN; WIDTH: 2 

FT 2 IN; HEIGHT 4 FT 2 IN;

WITH 

NH3 INJECTION GRID 

A/N: 472149

C22 S24 C21 NH3: 5.0 PPMV (4) 

[Rule 1303(a)(1)-BACT]

A195.4

D12.2

D12.3

D12.4

E179.1

E179.2,E193.1, 

E193.3

STACK NO. 4, DIAMETER: 13 FT 6 IN, 

HEIGHT: 90 FT 

A/N: 472149

S24 C22

GAS TURBINE, CTG. 5, NATURAL GAS, 

GENERAL ELECTRIC MODEL LMS100PA, 

SIMPLE CYCLE, 891.7 MMBTU/HR AT 72

DEGREES F WITH WATER INJECTION, 

WITH

A/N 472150

GENERATOR, 103 MW

D25 C27 NOX: MAJOR 

SOURCE

CO: 4.0 PPMV 

NATURAL GAS (4) 

[Rule 1703 (a)(2)-

BACT]; CO: 2000 

PPMV (5) [Rule 407] 

NOX: 15 PPMV

NATURAL GAS (8) 

[40CFR60 Subpart 

KKKK];NOX: 19 

LB/MMCF (1) [Rule 

2012] NOX 12.26

LB/MMCF NATURAL 

GAS (1)[Rule 2012]

NOX 2.5 PPMV

NATURAL GAS (4)[Rule 

2005-BACT, Rule 1703 

(a)(2)-BACT]

VOC: 2.0 PPMV

(4)[Rule 1303(a)(1)-

BACT]

PM10: 0.01 

GRAIN/DSCF (5A) [Rule 

475]; PM10: 0.1 

GRAIN/DSCF (5) [Rule 

409]; PM10: 11 LB/HR 

(5B) [Rule 475] 

SOX: .06 lb/MMBTU (8) 

[40 CFR60 Subpart 

KKKK]; SO2: (9) Acid 

Rain Provisions

A63.1, A63.2,

A99.1, A99.3, 

A99.5, A99.7, 

A99.9 A195.1, 

A195.2, A195.3, 

A327.1, A443.1, 

B61.1, C1.1,C1.3, 

C1.6, D12.1, 

D29.1, D29.2,

D29.3, D82.1, 

D82.2, E193.1, 

H23.1, I296.1, 

K40.1, K67.1
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 6

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Equipment Description (Continued)

Equipment ID 

No.

Connected To RECLAIM

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES, POWER GENERATION

CO OXIDATION CATALYST NO. 5, BASF, 

150 CUBIC FEET OF TOTAL CATALYST 

VOLUME

A/N: 472153

C27 D25 C28

SELECTIVE CATALYTIC REDUCTION

NO. 5, CORMETECH CHMT-2, WITH 812

CUBIC FEET OF TOTAL CATALYST 

VOLUME, LENGTH 11 FT 1 IN; WIDTH: 2 

FT 2 IN; HEIGHT 4 FT 2 IN; 

WITH 

NH3 INJECTION GRID 

A/N: 472153

C28 S30 C27 NH3: 5.0 PPMV (4) 

[Rule 1303(a)(1)-BACT]

A195.4

D12.2

D12.3

D12.4

E179.1

E179.2,E193.1, 

E193.3

STACK NO. 5, DIAMETER: 13 FT 6 IN, 

HEIGHT: 90 FT 

A/N: 472153

S30 C28

GAS TURBINE, CTG. 6, NATURAL GAS, 

GENERAL ELECTRIC MODEL LMS100PA, 

SIMPLE CYCLE, 891.7 MMBTU/HR AT 72

DEGREES F WITH WATER INJECTION, 

WITH

A/N 472154

GENERATOR, 103 MW

D31 C33

NOX: MAJOR 

SOURCE CO: 4.0 PPMV 

NATURAL GAS (4) 

[Rule 1703 (a)(2)-

BACT]; CO: 2000 

PPMV (5) [Rule 407] 

NOX: 15 PPMV

NATURAL GAS (8) 

[40CFR60 Subpart 

KKKK];NOX: 19 

LB/MMCF (1) [Rule 

2012] NOX 12.26

LB/MMCF NATURAL 

GAS (1)[Rule 2012]

NOX 2.5 PPMV

NATURAL GAS (4)[Rule 

2005-BACT, Rule 1703 

(a)(2)-BACT]

VOC: 2.0 PPMV

(4)[Rule 1303(a)(1)-

BACT]

PM10: 0.01 

GRAIN/DSCF (5A) [Rule 

475]; PM10: 0.1 

GRAIN/DSCF (5) [Rule 

409]; PM10: 11 LB/HR 

(5B) [Rule 475] 

SOX: .06 lb/MMBTU (8)

[40 CFR60 Subpart 

KKKK]; SO2: (9) Acid 

Rain Provisions

A63.1, A63.2,

A99.1, A99.3, 

A99.5, A99.7, 

A99.9 A195.1, 

A195.2, A195.3, 

A327.1, A443.1, 

B61.1, C1.1,C1.3, 

C1.6, D12.1, 

D29.1, D29.2,

D29.3, D82.1, 

D82.2, E193.1, 

H23.1, I296.1, 

K40.1, K67.1
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 7

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Equipment Description (Continued)

Equipment ID 

No.

Connected To RECLAIM

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES, POWER GENERATION

CO OXIDATION CATALYST NO. 6, BASF, 

150 CUBIC FEET OF TOTAL CATALYST 

VOLUME

A/N: 472155

C33 D31 C21

SELECTIVE CATALYTIC REDUCTION

NO. 6, CORMETECH CHMT-2, WITH 812

CUBIC FEET OF TOTAL CATALYST 

VOLUME, LENGTH 11 FT 1 IN; WIDTH: 2 

FT 2 IN; HEIGHT 4 FT 2 IN;;

WITH 

NH3 INJECTION GRID

A/N: 472155

C34 S36 C33 NH3: 5.0 PPMV (4) 

[Rule 1303(a)(1)-BACT]

A195.4

D12.2

D12.3

D12.4

E179.1

E179.2,E193.1, 

E193.3

STACK NO. 6, DIAMETER: 13 FT 6 IN, 

HEIGHT: 90 FT 

A/N: 472155

S36 C34

GAS TURBINE, CTG. 7, NATURAL GAS, 

GENERAL ELECTRIC MODEL LMS100PA, 

SIMPLE CYCLE, 891.7 MMBTU/HR AT 72

DEGREES F WITH WATER INJECTION, 

WITH

A/N 472156

GENERATOR, 103 MW

D37 C39

NOX: MAJOR 

SOURCE CO: 4.0 PPMV 

NATURAL GAS (4) 

[Rule 1703 (a)(2)-

BACT]; CO: 2000 

PPMV (5) [Rule 407] 

NOX: 15 PPMV

NATURAL GAS (8) 

[40CFR60 Subpart 

KKKK];NOX: 19 

LB/MMCF (1) [Rule 

2012] NOX 12.26

LB/MMCF NATURAL 

GAS (1)[Rule 2012]

NOX 2.5 PPMV

NATURAL GAS (4)[Rule 

2005-BACT, Rule 1703 

(a)(2)-BACT]

VOC: 2.0 PPMV

(4)[Rule 1303(a)(1)-

BACT]

PM10: 0.01 

GRAIN/DSCF (5A) [Rule 

475]; PM10: 0.1 

GRAIN/DSCF (5) [Rule 

409]; PM10: 11 LB/HR 

(5B) [Rule 475] 

SOX: .06 lb/MMBTU (8) 

[40 CFR60 Subpart 

KKKK]; SO2: (9) Acid 

Rain Provisions

A63.1, A63.2,

A99.1, A99.3, 

A99.5, A99.7, 

A99.9 A195.1, 

A195.2, A195.3, 

A327.1, A443.1, 

B61.1, C1.1,C1.3, 

C1.6, D12.1, 

D29.1, D29.2,

D29.3, D82.1, 

D82.2, E193.1, 

H23.1, I296.1, 

K40.1, K67.1
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 8

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Equipment Description (Continued)

Equipment ID 

No.

Connected To RECLAIM

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES, POWER GENERATION

CO OXIDATION CATALYST NO. 7, BASF, 

150 CUBIC FEET OF TOTAL CATALYST 

VOLUME

A/N: 472157

C39 D37 C40

SELECTIVE CATALYTIC REDUCTION

NO. 7, CORMETECH CHMT-2, WITH 812

CUBIC FEET OF TOTAL CATALYST 

VOLUME, LENGTH 11 FT 1 IN; WIDTH: 2 

FT 2 IN; HEIGHT 4 FT 2 IN 

WITH 

NH3 INJECTION GRID 

A/N: 472157

C40 S42 C39 NH3: 5.0 PPMV (4) 

[Rule 1303(a)(1)-BACT]

A195.4

D12.2

D12.3

D12.4

E179.1

E179.2,E193.1, 

E193.3

STACK NO. 7, DIAMETER: 13 FT 6 IN, 

HEIGHT: 90 FT 

A/N: 472157

S42 C40

GAS TURBINE, CTG. 8, NATURAL GAS, 

GENERAL ELECTRIC MODEL LMS100PA, 

SIMPLE CYCLE, 891.7 MMBTU/HR AT 72

DEGREES F WITH WATER INJECTION, 

WITH

A/N 472158

GENERATOR, 103 MW

D43 C45

NOX: MAJOR 

SOURCE CO: 4.0 PPMV 

NATURAL GAS (4) 

[Rule 1703 (a)(2)-

BACT]; CO: 2000 

PPMV (5) [Rule 407] 

NOX: 15 PPMV

NATURAL GAS (8) 

[40CFR60 Subpart 

KKKK];NOX: 19 

LB/MMCF (1) [Rule 

2012] NOX 12.26

LB/MMCF NATURAL 

GAS (1)[Rule 2012]

NOX 2.5 PPMV

NATURAL GAS (4)[Rule 

2005-BACT, Rule 1703 

(a)(2)-BACT]

VOC: 2.0 PPMV

(4)[Rule 1303(a)(1)-

BACT]

PM10: 0.01 

GRAIN/DSCF (5A) [Rule 

475]; PM10: 0.1 

GRAIN/DSCF (5) [Rule 

409]; PM10: 11 LB/HR 

(5B) [Rule 475] SOX: 

.06 lb/MMBTU (8) [40 

CFR60 Subpart KKKK]; 

SO2: (9) Acid Rain 

Provisions

A63.1, A63.2,

A99.1, A99.3, 

A99.5, A99.7, 

A99.9 A195.1, 

A195.2, A195.3, 

A327.1, A443.1, 

B61.1, C1.1,C1.3, 

C1.6, D12.1, 

D29.1, D29.2,

D29.3, D82.1, 

D82.2, E193.1, 

H23.1, I296.1, 

K40.1, K67.1
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 9

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Equipment Description (Continued)

Equipment ID 

No.

Connected To RECLAIM

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES, POWER GENERATION

CO OXIDATION CATALYST NO. 8, BASF, 

150 CUBIC FEET OF TOTAL CATALYST 

VOLUME

A/N: 472160

C45 D43 C46

SELECTIVE CATALYTIC REDUCTION

NO. 8, ICORMETECH CHMT-2, WITH 

812 CUBIC FEET OF TOTAL CATALYST 

VOLUME, LENGTH 11 FT 1 IN; WIDTH: 2 

FT 2 IN; HEIGHT4 FT 2 

WITH 

NH3 INJECTION GRID 

A/N: 472160

C46 S48 C45 NH3: 5.0 PPMV (4) 

[Rule 1303(a)(1)-BACT]

A195.4

D12.2

D12.3

D12.4

E179.1

E179.2,E193.1, 

E193.3

STACK NO. 8, DIAMETER: 13 FT 6 IN, 

HEIGHT: 90 FT 

A/N: 472160

S48 C46

System 2: EMERGENCY ENGINE

INTERNAL COMBUSTION ENGINE, 

EMERGENCY FIRE, DIESEL FUEL, LEAN 

BURN, CLARKE, MODEL JU6H-UFADTO, 

240 BHP 

WITH 

AFTERCOOLER, TURBOCHARGER, 

A/N: 472165

D49 NOX: PROCESS 

UNIT

NOX+NMHC: 3

GM/BHP-HR DIESEL 

(4) [RULE 1303; RULE 

2005]; NOX: 134

LB/1000 GAL DIESEL 

(1) [RULE 2012]

CO: 2.6 GM/BHP-HR 

DIESEL (4) [RULE 

1303]

PM10: 0.15 GM/BHPHR DIESEL (4) [RULE 

1303] 

SOX: 0.0055 GM/BHPHR DIESEL (4) [RULE 

2005]; 

B61.2,C1.4, 

D12.5, I296.3, 

K67.3
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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Equipment Description (Continued)

Equipment ID 

No.

Connected To RECLAIM

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 2: STORAGE TANK

STORAGE TANK, TK-1, FIXED ROOF, 

29.4 PERCENT AQUEOUS AMMONIA, 

DIAMETER: 9’-4”; HEIGHT: 12’-0”; 12,000 

GALLONS WITH PRV SET AT 25 PSIG

WITH 

A/N: 472161

D52 C157.1, 

E144.1,E193.1

STORAGE TANK, TK-2, FIXED ROOF, 

29.4 PERCENT AQUEOUS AMMONIA, 

DIAMETER: 9’-4”; HEIGHT: 12’-0”; 12,000 

GALLONS WITH PRV SET AT 25 PSIG

WITH 

A/N: 472162

D53 C157.1, 

E144.1,E193.1

Section D of the Facility Permit

Equipment ID 

No.

Connected To RECLAIM 

Source Type/ 

Monitoring Unit

Emissions

And Requirements

Conditions

Process 3: RULE 219 EXEMPT EQUIPMENT SUBJECT TO SOURCE SPECIFIC RULES

RULE 219 EXEMPT EQUIPMENT, 

COATING EQUIPMENT, PORTABLE, 

ARCHITECTURAL COATING

E54 VOC: (9) [Rule 1113], K67.5

RULE 219 EXEMPT EQUIPMENT, 

EXEMPT HAND WIPING OPERATIONS

E55 VOC: (9) [Rule 1171]

BACKGROUND

See FDOC dated August 28, 2008 for background information.

On July 25, 2007 the applicant filed applications with the AQMD for Permit to Construct for the CPV Sentinel 

Energy Project. The AQMD issued a PDOC on May 7, 2008 and a FDOC on August 29, 2008. The FDOC 

did not contain information regarding project’s compliance with emissions offset requirements of Rule 1303 

(b)(2). On November 3, 2008 the AQMD was ordered by LA Superior Court not to issue permit through Rule 

1315, Rule 1304 and 1309.1. Prior to the court ruling the applicant was proposing to obtain ERCs credits for

SOx and PM10 through Rule 1309.1 as amended on August 3, 2007 (NOx through RECLAIM system, VOC 

with purchase of ERCs). 

The applicant has been working through the California Energy Commission (CEC) to secure a license which 

incorporates the AQMD Determination of Compliance. On November 3, 2008 the CEC held an evidentiary 

hearing on the proposed project covering all topics except air quality. The CEC ordered that the evidentiary 

record on all topics except air quality be closed on December 8, 2008. 

With the passage of AB1318 (became effective on 1/1/2010) the applicant proposes to obtain offsets for 

PM10 and SOx from AQMD’s internal offset bank as allowed under AB1318. On October 15, 2009 the 

applicant filed an Amendment to Permit to Construct/Operate application for the CPV Sentinel Energy 
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Project: In addition to the revised emissions offset strategy the applicant proposes project design 

refinements as listed below:

I Changes requiring AQMD Permits

o Remove blackstart engine (cancel AQMD application no. 472164)

o Tier 3 engine is now available for the fire pump, the applicant will propose a Tier 3 engine instead of 

a Tier 2 engine (BACT for NOx+VOC = 3.0 g/bhp-hr) under the same AQMD application no. 472165 

o Reduce the operating hours from turbines 6 through 8 to equal the operating hours of the first 5 

turbines (this will reduce the overall annual emissions and require less offsets for PM10, SOx and 

VOC) under applications for turbines 6 through 8 (AQMD applications nos. 472154, 472156 and 

472158).

o Revise the PM10 emissions rate from each turbine from “6 lb/hr” to “5 lb/hr” under applications for 

turbines 1 through 8 (AQMD applications nos. 472139, 472141, 472143, 472147, 472150, 472154, 

472156 and 472158) .

o Revise the CO BACT limit from “6 ppmv” to “4 ppmv” under applications for turbines 1 through 8 and 

their associated Air Pollution Control systems no 1 through 8 (AQMD applications Nos. 472139, 

472141, 472143, 472147, 472150, 472154, 472156, 472158, 472140, 472142,472145, 472149, 

472153, 472155, 472157 and 472160).

II Other changes that do not require AQMD Permits

o Remove the two proposed cooling towers, and provide one cooling tower per turbine

o Eliminate the operations buildings

o Remove one warehouse building and relocate another warehouse building

o Relocate the switchgear building

o Relocate the treated water storage tanks, water pumping skids and water treatment trailer parking

Along with the amendments to the Permit to Construct/Operate applications filed on October 15, 2009, CPV 

Sentinel also submitted a revised air quality dispersion modeling analysis and health risk assessment. The

primary reason the applicant revised the modeling analysis was to ensure the proposed changes in locations 

of buildings and cooling towers would not cause a stack plume downwash conditions that would lead to higher 

offsite pollutant concentrations than were presented in the previous modeling evaluation. There is no change 

in emissions for short-term turbine commissioning impacts. At the time the addendum was filed with the 

District, GE revised the turbine PM10 emissions from 6 lbs/hr to 5 lbs/hr. The modeling was revised using the 

5 lb/hr PM10 emissions rate. Planning, Rule Development & Area Sources (PRDAS) staff reviewed the air 

quality analysis and the health risk assessment (HRA) for the proposed project provided by CPV Sentinel and 

results of the review shows compliance with all applicable ambient concentrations and AQMD rules and 

regulations threshold standards. 
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 12

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Site Description

The proposed location of CPV Sentinel is on an 37 acre parcel located 8 miles northwest of the center of the 

city of Palm Springs (62575 Powerline Rd, Desert Hot Springs, 92240). The parcel is undeveloped and is 

next to the Devers substation. CPV Sentinel will be located in an area zoned for industrial uses in the 

unincorporated area of Riverside County.

The revised site plan shown above was prepared for CPV Sentinel by URS and shows the general layout of 

the proposed facility. There will be one cooling tower per turbine and a couple of buildings were moved to 

different locations on the property. The project site is located in an remote area surrounded by air turbines 

and an Edison substation to the west. To the southeast is the Indigo Energy Facility (1.8 miles). To the 

north, east and south are Wind Farms The site locale is an industrial portion of the unincorporated are of 

Riverside County. The nearest residence is 330 feet east of the Facility and the applicant has an option to 

acquire the property. The second group of nearest residence is located 2.5 km (8,800 ft) southeast of the 

Facility.

COMPLIANCE RECORD

No change from FDOC
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 13

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

PROCESS DESCRIPTION

No change

GE revised the operating conditions and the condition no. 103 and there is a slight increase in NOx, CO and 

VOC emissions (in the second decimal point position). GE will revise the PM10 emissions based on 5 lb/hr.

Definition of a Peaking Unit in Rule 2012

No change, from FDOC

Air Pollution Control (APC) System

No change, from FDOC

Selective Catalytic Reduction/CO Catalyst Systems (A/Ns 472140, 472142, 472145, 472149, 472153, 

472155, 472157 and 472156)

No change, from FDOC

CO Oxidation Catalyst

No change, from FDOC

Aqueous Ammonia Storage Tank (A/N 472161 and 472162)

No change, from FDOC

Heated Ammonia Vaporization Skid

 

1 GE Manufactures two versions of the LMS100 CTG. CPV Sentinel plans to install the LMS100PA. The PA model utilizes water injection for NOx 

abatement while the PB version utilizes dry low emission (DLE) combustors for NOx abatement.

2 PUC is the acronym for the California Public Utilities Commission

3 Represents the maximum possible fuel consumption of the CTG, based on 875.7 MMBTU/hr heat input and 1,018 BTU/scf fuel heat content. 

However, the emission calculations will be based on a worst-case operating scenario as identified by the applicant, which may result in a lower 

fuel usage depending on the ambient temperature, the employment and rate of intercooling, water injection rates, and electrical load generated.

Parameter Specifications

Manufacturer General Electric

Model LMS100PA1

Fuel Type PUC2 Quality Natural Gas

Natural Gas Heating Value 1,018 BTU/scf

Operating condition 103

Gas Turbine Heat Input (HHV) 891.7 MMBTU/hr at 72oF and 40% relative humidity

Fuel Consumption 0.876 MMSCF/hr3

Gas Turbine Exhaust Flow 355534 SCFM

Gas Turbine Exhaust Temperature 785.1oF

Exhaust Moisture 6-8%

Gas Turbine Power Generation 101.279 MW

Net Plant Heat Rate, LHV 7939 BTU/kW-hr 
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 14

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

No change, from FDOC

Ammonia Distribution Header

No change, from FDOC

Performance Warranties

No change, from FDOC

Cooling Tower System

The applicant proposes to install 8 single cell-cooling towers mechanical draft evaporative coolings (each 

for one turbine) and not install the two cooling towers, both mechanical draft, one of five cells (for the first 5 

turbines) and one with three cells for the final 3 turbines. The circulating water rate will be 6,900 gallons per 

minute (GPM) for each cooling tower . The Rule 1401 emissions were determined for this equipment to 

verify the equipment will be exempt from AQMD permit per Rule 219, see Appendix I for emissions 

calculations. 

Emergency Fire Pump Engine (A/N 472165)

Tier 3 engines are now available for this HP range, see Appendix D for revised emissions

Emergency Blackstart Engine (A/N 472164) 

The applicant request to cancel the blackstart engine application

CRITERIA POLLUTANT EMISSIONS

The total emissions from the power plant will include the summation of all eight CTGs and the emergency 

fire pump engine. The emissions from the gas turbines are based on the following formula and 

assumptions:

GE revised the PM10 emissions from the CTG to 5 lb/hr instead of 6 lb/hr, see guarantee e-mail dated 

10/21/09. GE revised the emission for the various case runs. Case 103 has the highest emissions (minor 

changes) and will be used to update the emissions. The CO BACT was revised to 4 ppmv and the CO 

emissions will be revised (lower value). 

Emissions for NOx, CO and VOC

EF(lb/hr)  ((ppmvd/1E06 )/O2) (1 H2O%)/100)(MW/28lb/bl b - mole  ER

where,

ppmvd = Uncontrolled (or controlled) concentration at 15% O2, dry basis

MW = Molecular weight, lb/lb-mol

O2 = O2 correction factor = (20.9-15)/(20.19-O2)

H20 =percent water in the exhaust

ER = exhaust mass rate in lb/hr
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 15

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

The values for O2, water percentage, mass rate were provided by GE (worst case operating 

scenario)

Emissions for SOx

EF(lb/hr)  (0.2 5g /100ft3 ) (1lb / 7000g r) (mmbt/ h r) (1E0 6btu / mmbtu)/ 918btu / ft3) (6 4lbSOx/ 3 2lbS)

where,

Sulfur content = 0.25 lb grains/100 scf

Mmbtu/hr =789.8 mm/btu/hr

Heating value (LLH) = 918 btu/ft3

MW S = 32 lb/mole

MW SOx = 64.2 lb/mole

Emissions for PM10

GE guarantees 5 lb/hr at maximum operating conditions

Assumptions:

1. Emissions are based on the worst case operating scenario 

2. PM10 emissions are based on 0.0062 lb/MMBTU (GE guarantee)

3. SO2 to SO3 conversion in APC equipment is accounted for in the PM10 AP-42 emission factor

4. SOx emissions are based on 0.25 grains S/100 scf 

5. 30-Day Averages are based on 485 hours/month of operation for turbines 1-8.

6. Emissions are based on total fuel consumption rather than total hours of operation

 

The applicant has identified eleven possible operating scenarios. The eleven scenarios are listed as 

operating conditions (OC) 100 through 110 in Appendix B in the Amendment to Permit to 

Construct/Operate application for the CPV Sentinel Energy project:

Table 10 - Operating Scenarios

Ambient 

Temp oF

H2O Injection,

lb/hr

Relative 

Humidity (%)

Intercooler 

(on/off) Compressor Inlet Temp oF

OC100 17 34407(100%) 80 Off 17

OC101 17 24526 (75%) 80 Off 17

OC102 17 15,618 (50%) 80 Off 17

OC103 72 31603 (100) 40 On 59.3

OC104 72 32072 (100) 40 Off 72

OC105 72 22056 (75%) 40 Off 72

OC106 72 13838 (50%) 40 Off 72

OC107 107 28441 (100%) 18 On 77.4

OC108 107 27730 (100%) 18 On 107

OC109 107 18956 (75) 18 On 107

OC110 107 11812 (50%) 18 On 107

Detail of Operating Conditions
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

GE re-ran the operating scenarios and there were slight changes in emissions. The emissions are based 

on operating Case 103 reveals that GE ran the tests while varying the water injection rate, and compressor 

inlet temperature. Ambient temperature was allowed to vary from a minimum of 17oF to a maximum of 

107oF. Note from the table above that for each ambient temperature, the load was varied between 

maximum (100%), average (75%), and minimum (50%) loads. The top five cases where fuel flow to the 

CTGs is the greatest (and therefore yielding the highest emissions) are shown in the table below. 

Table 11 - Worst Case Operating Scenario

Top Operating 

Condition

103

Ambient Temperature, oF 72

Ambient Pressure, psia 14.132

Fuel Consumption, MMBTU/hr 

LHV

804.1

Fuel Consumption, lb/hr 39034

Exhaust Temperature, oF 785.1

Load, MW 101.279

Water Injection (on/off) On

Water Injection, lb/hr 28181

Intercooler (on/off) On

Of the top five cases, the worst case scenario occurs during periods of maximum fuel consumption (804.1

MMBTU/hr), LHV at full load (101.279 MW), low ambient temperature (72oF), with water injection in full 

use, and the intercooler not in operation, as identified in the table above by operating condition no. 103. 

Therefore, to address the worst case scenario, the facility’s NSR emissions will be based on the 

parameters listed in operating condition no. 103. 

There are essentially four modes of operation for the CTGs. Emissions from the four operating modes are 

distinctly different and must be calculated independently. The following table gives more detail of the four 

operating modes.

Table 12 - Operating Modes of the CTGs

Mode Description

Commissioning

The process of fine-tuning each of the CTGs. Facility follows a systematic approach 

to optimize performance of each of the CTGs and the associated control equipment. 

Emissions are expected to be greater during commissioning than during normal 

operation. This mode affects only the initial year of operation not to exceed 150 

hours per turbine. 

Start-up

The applicant has indicated that there will be up to two start-ups per day for each 

CTG, with each start-up lasting 25 minutes. Start up emissions are higher due to 

the fact that the control equipment has not reached optimal temperature to begin the 

chemical reactions needed to convert NOx to elemental nitrogen and water.

Normal 

Operation

Normal operation occurs after the CTGs and the control equipment are working 

optimally, at their designated levels, i.e. NOx emissions are controlled to 2.5 

ppmvd at 15% O2, CO emissions to 4.0 ppmv at 15% O2(revise CO emissions), and VOC to 

2.0 ppmvd at 15% O2. Emissions may vary due to ambient conditions.

Shutdown

Shutdown occurs at the initiation of the turbine shutdown sequence and ends with the 

cessation of CTG firing, and will last approximately 10 minutes thereafter. 

Typically, the shutdown process will emit less than the start-up process but may 

emit slightly greater than during normal operation because both H2O injection into 

the CTGs and NH3 injection into the SCR reactor have ceased operation 

Commissioning Period

No change, except the PM10 emissions rate will be based on 5 lb/hr instead of 6 lb/hr.
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Table 13 - Proposed Commissioning Schedule

Description Power Level

Corrected 

Operating 

Hours

Estimated 

Fuel Rate 

Total Estimated Emission per Event

NOX CO VOC PM10 SOX

(MMBtu/hr) (lbs) (lbs) (lbs) (lbs) (lbs)

* First fire the unit & then shutdown to check for leaks, etc

Core/Sync 

Idle 23 73.5 257 1049 27 115 1.2

* Synch & Check E-stop

Sync Idle 17 73.5 192 786 20 87 0.9

* Additional AVR Commissioning

5% 17 92.8 362 524 13 87 1.1

* Break-in Run

5% 12 92.8 241 349 8 58 0.7

* Dynamic Commissioning of AVR & Commission Water

Load Step 1 10.00% 6 166 96 400 30 29 0.7

Load Step 2 20.00% 6 246 142 261 15 29 1.0

Load Step 3 30.00% 6 319 185 261 15 29 1.3

Load Step 4 40.00% 6 389 225 231 15 29 1.6

Load Step 5 50.00% 6 457 265 190 16 29 1.8

Load Step 6 60.00% 6 525 304 260 19 29 2.1

Load Step 7 70.00% 6 591 342 356 24 29 2.4

Load Step 8 80.00% 6 659 382 503 30 29 2.7

Load Step 9 90.00% 6 728 421 744 43 29 2.9

Load Step 

10 100.00% 6 798 463 1138 69 29 3.2

Subtoal 58 2826 4344 277 288 20

* Base load AVR Commissioning

100% 23 798 1850 4550 275 115 12.9

COMPLETE - TOTAL ESTIMATED FIRED HOURS

150 5729 11603 620 749.5 37

The above table, the PM10 emissions were revised

Start-up / Shutdown of CTGs 

No change, turbines 6-8 will have the same number start-ups/shutdowns as the first five turbines.

Normal Operations

The emissions during normal operations are assumed to be fully controlled to Best Available Control 

Technology (BACT) levels, and exclude emissions due to commissioning, start up and shutdown periods, 

which are not subject to BACT levels. Hourly, monthly, and annual emissions as well as the 30-day 

averages are calculated and shown in Appendices A through E. The emission calculations for the 

emergency fire pump are contained in Appendix D .

Emissions During A Non-Commissioning Year
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 18

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

The tables below shows the individual and cumulative emissions during a non-commissioning year from all

8 gas turbines which includes, start-up, shutdown and normal operation, as well as the emissions from the 

emergency fire pump which is to operate for the designated maximum of 50 hours per year (permit limit.

A. Emissions per Turbine

Mass Emission Rates, lb/hr (Non-Commissioning Year)

Emissions, lb/hr

LMS100PA CTG NOx CO VOC SO2 PM10

Normal Operations 7.95 7.74 2.21 0.63 5

Start up 59.76 38.15 10.21 0.42 5

Shutdown 34.95 203.88 17.48 0.12 5

Based on start-up time of 25 min per day, total time 50 minutes (0.83 hrs)

Based on 2 shut downs per day, total time 20 minutes (0.33 hr)

The start-up and shut down emissions for the purposes of calculations were assume to occur over one hour, 

then it makes the emissions calculations in the following tables easier to manage (data provide by GE)

Note, the CO emissions revised to 4 ppmv, based on a recent BACT determination

Turbine Mass Emission Rates per turbine, lb/dy (Non-Commissioning Year) 

Emissions, lb/dy

LMS100PA CTG NOx CO VOC SO2 PM10

Start-up 50 32 9 0.35 4

Normal operations 119 116 33 9 75

Shutdown 12 67 6 0.040 2

TOTALS 181 215 47 9.78 81

Each turbines will operate up to 15 hours per day (excluding start-up and shut down times)

Based on 2 start-ups per day, total time 50 minutes (0.83 hrs)

Based on 2 shut downs per day, total time 20 minutes (0.33 hr)

Turbine Mass Emission Rates per turbine, lb/month (Non-Commissioning Year)

Emissions, lb/month

LMS100PA CTG NOx CO VOC SO2 PM10

Start-up 1494 954 255 11 125

Normal Operations 3578 3484 995 282 2250

Shutdown 350 2039 175 1 50

TOTALS 5421 6447 1424.55 293.4 2425

Turbines will operate up to 15 hours per day, every day of the month

Up to 2 start-ups and shut downs per day

Total combines turbine Mass Emission Rates, lb/month (Non-Commissioning Year)

Emissions, lb/month

LMS100PA CTG NOx CO VOC SO2 PM10

Start-up 11952 7632 2064 84 1000

Normal Operations 28624 27872 7992 2599 2256

Shutdown 2800 16312 1400 10 400
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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

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TOTALS 43368 51813 11456 2347 19400

Mass Emission Rates, lb/year (Non-Commissioning Year)

Emissions, lb/year

LMS100PA CTG NOx CO VOC SO2 PM10

Start-up 59760 38152 10320 424 5000

Normal Operations 167144 162776 46464 13160 105120

Shutdown 13984 81552 6992 48 2000

TOTALS 240881 282475 63665 13629 112120

Emissions During A Commissioning Year

The tables below show the emissions during a commissioning time per each gas turbines which includes 

commissioning, start-up, shutdown and normal operation, 

Commissioning Emissions rate per Turbine and hours of operations per testing phase

Description NOx CO VOC SOx PM10

hrs lb/hr lb/hr lb/hr lb/hr lb/hr

First fire 23 11.17 45.59 1.16 0.05 5

Synch & Check E-stop 17 11.29 46.24 1.18 0.05 5

Additional AVR 17 21.29 30.80 0.74 0.07 5

Break-in run 12 20.08 29.09 0.70 0.06 5

Dynamic AVR 58 48.72 74.90 4.77 0.34 5

Base load AVR 23 80.43 197.85 11.98 0.56 5

total- lb/hr 150

Turbine emissions lb/hr per turbine, lb/mon and 30 day ave

Description NOx CO VOC SOx PM10

lb/mon lb/mon lb/mon lb/mon lb/mon

First fire 257 1048.56 26.68 1.19 115

Synch & Check Estop 192 786.06 20.05 0.89 85

Additional AVR 362 523.56 12.55 1.12 85

Break-in run 241 349.04 8.37 0.75 60

Dynamic AVR 2826 4344.23 276.78 19.71 290

Base load AVR 1850 4550.48 275.48 12.90 115

total lb/hr ave 38.19 77.35 4.13 0.24 5

totals/mon 5728 11601.92 619.90 36.56 750

30 ave 185 374 20 1 24

Note the commissioning of each turbine will be conducted during one month period and after commissioning is completed for the

month, then normal operation will not proceed until the following month.

Total Turbine monthly emissions (commissioning month-lb/month)

CO NOX VOC PM10 SOx

Turbine lb/mon lb/mon lb/mon lb/mon lb/mon

Unit 1 11,602 5,728 620 750 37

Unit 2 11,602 5,728 620 750 37

Unit 3 11,602 5,728 620 750 37

Unit 4 11,602 5,728 620 750 37
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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

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Unit 5 11,602 5,728 620 750 37

Unit 6 11,602 5,728 620 750 37

Unit 7 11,602 5,728 620 750 37

Unit 8 11,602 5,728 620 750 37

Total 92,815 45,824 4,959 6,000 292

Total combined Turbine (1-8) Mass Emission Rates, lb/year (Commissioning Year)

Emissions, lb/year

LMS100PA CTG NOx CO VOC SO2 PM10

Start-up 59760 38152 10208 424 5000

Normal Operations 167144 162776 46464 13160 105120

Shutdown 13984 81552 6992 48 2000

Commissioning 45832 92824 4960 296 6000

TOTALS 286720 375295 68624 13928 118120

The only difference between the lb/yr for commissioning year versus a non-commissioning year, is the 

additional 150 hrs per turbine of commissioning testing hours.

30-Day Averages

The 30 Day Average emissions are calculated in Appendix B for both a commissioning and noncommissioning year for the worst case operating scenario. The worst case operating scenario was defined 

as OC100 in Table 10 above. The values in the tables below are the cumulative 30 day averages for the 

entire facility (8 CTGs, the emergency fire pump and the cooling tower).

Cumulative 30-Day Averages, lb/day (Commissioning Year)

30 Day Average, lb/day

Eight LMS100PA CTGs NOx4 CO VOC SOx PM10

Commissioning 2994 160 9 194

TOTALS 2994 160 9 194

The above table assumes all the turbines are commissioned in the same month for the worst case 

emissions scenario. Once the commissioning is completed for one turbine, then following month the turbine 

can commence normal operations (permit conditions will address this issue).

Cumulative 30-Day Averages, lb/day (Non-Commissioning Year)

30 Day Average, lb/day

Eight LMS100PA CTGs NOx6 CO VOC SOx PM10

Total Operations 1671 367.6 75.68 625.84

TOTALS 1671 367.6 75.68 625.84

The above table assumes all the turbines are in normal operations and providing electricity to the electrical 

grid in the same month for the worst case emissions scenario. 

 

4 CPV Sentinel has elected to enter RECLAIM. As such, RECLAIM Trading Credits (RTC) will be used to satisfy the NOx offsetting requirements of 

Rule 2005, and therefore the 30-Day Averages for NOx need not be calculated
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 21

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

The following is a comparison of the cumulative 30-day averages for the entire facility (8-LMS100 PA gas 

turbines) for both a commissioning year and a non-commissioning year. The maximum 30-day averages 

for each pollutant, shown in bold. 

NOx6 CO VOC SOx PM10

Facility 30 Day Average (Commissioning Year) 2994 160 9 94

Facility 30 Day Average (Non-Commissioning Year) 1671 367.6 75.68 625.84

The following table shows the 30-day averages from one individual LMS100PA gas turbine for both a 

commissioning year and a non-commissioning year. The maximum 30-day averages for each pollutant are 

shown in bold. 

Turbine

NOx6 CO VOC SOx PM10

30 Day Average (Commissioning Year) 372 20 1 24

30 Day Average (Non-Commissioning Year) 209 45.95 9.46 78.23

Emissions from the Fire pump engine

NOx CO VOC SOx PM10

Lb/hr 1.545 0.36 0.04 0.0022 0.048

Lb/dy 1.545 0.36 0.04 0.0022 0.048

30-day ave n/a 0 0 0 0

Lb/yt 77.25 18.02 2.02 0.11 2.38

Updated emissions applicant proposes to install a Tier 3 fire pump engine

PROHIBITORY RULE EVALUATION

RULE 212-Standards for Approving Permits

The facility emissions was revised and there is a reduction in emissions for all pollutants. The project was 

already noticed to the public, with the emissions reductions, the new public notice is not required.

Previous Total Project emissions 

Emissions, lb/month

Equipment NOx CO VOC SO2 PM10 NH3

LMS100PA CTG 48261 72899 12788 2693 27060 25,403

Fire pump engine 13 2 0 0 0

Blackstart engine 18 4 1 0 0

TOTALS 48292 72905 12789 2693 27060 25403

NH3 = 5.86 b/hr

NH3 = ((450 hr/mon * 5 turbines) + (695 hr/mon * 3 turbines)) * 5.86 lb/hr = 25403

Revised Total Project emissions 
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Emissions, lb/month

Equipment NOx CO VOC SO2 PM10 NH3

LMS100PA CTG 43368 51813 11396 2347 19400 21202

Fire pump engine 6.44 1.50 0.0 0 0

TOTALS 43374 51815 11396 2347 19400 21202

NH3 = 5.86 b/hr

NH3 = ((450 hr/mon * 8 turbines) * 5.89 lb/hr = 21204 lb/mon

RULE 219-Exempt equipment not requiring permits

The Cooling tower is exempt from AQMD permit per section (d)(3) . The MICR from this equipment is less 

than one in one million risk (max 0.00957 in a million) for the combined eight cooling towers.MICR 

reviewed by District modeling staff and MICR is less than the threshold value of this Rule, thus the 

equipment is exempt from requiring a Permit to Operate.

RULE 401-Visible Emissions

No change, from FDOC

RULE 402-Nuisance

No change, from FDOC

RULE 403-Fugitive Dust

No change from FDOC

RULE 407-Liquid and Gaseous Air Contaminants

No change from FDOC

RULE 409-Combustion Contaminants

This rule restricts the discharge of contaminants from the combustion of fuel to 0.1 grain per cubic foot of 

gas, calculated to 12% CO2, averaged over 15 minutes. The equipment is expected to meet this limit 

based on the calculations shown below:

Estimated exhaust gas 355,534 SCFM = 21.33 mmscf/hr

Water content 12.2279

Estimated exhaust gas 355534 SCFM * (1-0.122279) = 312,060

Estimated exhaust gas 312,060 DSCFM * (60 min/hr) * (1mmcf/1E06 ft3)

Estimated exhaust gas 18.72 mmscf/hr

Maximum PM10 Emissions 5 lb/hr

Estimated CO2 in exhaust 3.9964%
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Grain Loading

18.72EE6 scf/hr

(5 lb/hr)(700 0 gr/lb)



3.6634

12



= 0.00612 gr/dscf << 0.1 gr/dscf

The fire pump engine is not subject to this Rule.

RULE 431.1-Sulfur Content of Gaseous Fuels

No change. 

Historically the sulfur content of the fuel has been less than 4 ppmv for combustion sources and the 16 

ppmv sulfur content is the max allowed by the Rule. The applicant provided in the CEC application 

submittal the sulfur content (table 5.2-2) and the range is from 0.051 to 0.119 gr/100 ft3. The applicant for 

the purposes of offsets will limit the sulfur content to 0.25 gr/100 ft3 (permit condition and also require 

monthly testing for the sulfur content).

RULE 431.2-Sulfur Content of Liquid Fuels

No change from FDOC

RULE 474-Fuel Burning Equipment-Oxides of Nitrogen

Superseded by NOx RECLAIM.

RULE 475-Electric Power Generating Equipment

This rule applies to power generating equipment greater than 10 MW installed after May 7, 1976. 

Requirements are that the equipment meet a limit for combustion contaminants of 11 lbs/hr or 0.01 gr/scf. 

Compliance is achieved if either the mass limit or the concentration limit is met. Mass PM10 emissions 

from the turbine are estimated at 5.0 lbs/hr, and 0.0038 gr/scf during natural gas firing at maximum firing 

load (see calculations below). Therefore, compliance is expected. Compliance will be verified through the 

initial performance test.

 

x TFD

O

F x

hr

scf Stack Exhaust Flow d

9 % 2 20.

20.9



 











where:

Fd: Dry F factor for fuel type, 8710 dscf/MMBtu

O2: Rule specific dry oxygen content in the effluent stream, 3%

TFD: Total fired duty measured at HHV, 891.7 MMBtu/hr

lb

gr

x

Stack Exhaust Flow scf hr

PM lb hr

scf

grain Combustion Particulate 7000

, /

, /

1 0

















Stack flow = 8710(20.9/17.9)*897.7 = 9.13 mmscf/hr

Combustion particulate = (5.0/9.13E+06)*7000 = 0.0038 gr/scf

RULE 1110.2 – Emissions from gaseous- and liquid fueled engines

No change from FDOC
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 24

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

RULE 1134 – Emissions of NOx from Gas Turbines

No change from FDOC

RULE 1135 – Emissions of NOx from Electric Power Generating Systems

No change from FDOC

NEW SOURCE REVIEW (NSR) ANALYSIS

The following section describes the NSR analysis for CPV Sentinel. The facility can comply with NSR 

either by qualifying for various exemptions from or by demonstrating compliance with the following rules, 

except the emissions offsets requirements for PM10 and SOx is evaluated as specified in Appendix N. 

Each piece of equipment at CPV Sentinel is evaluated for compliance with the rules in the table below.

Table 14 - Applicable NSR Rules for CPV Sentinel

Applicable NSR Rules for Non-RECLAIM 

Pollutants (CO, VOC, SOx, PM10)

Applicable NSR Rules for RECLAIM 

Pollutants (NOx)

Rule 1303(a)–BACT Rule 2005(b)(1)(A)-BACT

Rule 1303(b)(1)–Modeling Rule 2005(b)(1)(B)-Modeling

Rule 1303(b)(2)-Offsets Rule 2005(b)(2)-Offsets

Rule 1303(b)(3)-Sensitive Zone Requirements Rule 2005(e)-Trading Zone Restrictions

Rule 1303(b)(4)-Facilitywide Compliance Rule 2005(g)-Additional Requirements

Rule 1303(b)(5)-Major Polluting Facilities Rule 2005(h)-Public Notice

Rule 1701 (b)(1) and Rule 1703 (a)(2) BACT 

for NOx, SOx and CO

Rule 2005(i)-Rule 1401 Compliance

Rule 2005(j)-Compliance with Fed/State NSR

RULE 1303(a), Rule 2005(b)(1)(A)-BACT and Rules 1701 (b)(1) and 1703 (a)(2)– LMS100 CTGs

These rules state that the Executive Officer shall deny the Permit to Construct for any new source which 

results in an emission increase of any non-attainment air contaminant, any ozone depleting compound, or 

ammonia unless the applicant can demonstrate that BACT is employed for the new source. CPV Sentinel

is a new source with a potential for an increase in emissions and therefore, BACT is required. Each of the 

LMS100 CTGs proposed for construction by CPV Sentinel will be operated on a simple cycle (no steam 

turbine, HRSG, or secondary electrical generator is associated with simple cycle configurations). As of the 

date of this evaluation, BACT for simple cycle gas turbines is shown in Table 15 below:

Table 15 - BACT Requirements for Simple Cycle Gas Turbines

NOx CO VOC PM10/SOx NH3

2.5 ppmvd, @ 15% 

O2, 1-hour average

4.0 ppmvd, @ 15% O2, 

1-hour average

2.0 ppmvd, @ 15% O2, 

1-hour average

PUC quality 

natural gas w/ S 

content ≤ 1 

grain/100 scf 

5.0 ppmvd @ 15% 

O2, 1-hour 

average

This information was based on a current BACT standards for this type of equipment. The CO BACT was 

revised after the FDOC was issued last year. Since the permits to construct has not been issued and the 

facility is a Major Source, the new BACT requirement applies. The new CO BACT limit is 4 ppmv, ref City 

of Riverside, Public Utilities Dept-Riverside Energy Resource Center, id 139796, a/n 481647 and 481649
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Table 16 - Proposed BACT for CPV Sentinel CTGs

NOx CO VOC PM10/SOx NH3

2.5 ppmvd, @ 15% 

O2, 1-hour average

4.0 ppmvd, @ 15% O2, 

1-hour average

2.0 ppmvd, @ 15% O2, 

1-hour average

PUC quality 

natural gas w/ S 

content ≤ 1 

grain/100 scf 

5.0 ppmvd @ 15% 

O2, 1-hour 

average

Natural gas provided by the Gas Company is limited to 16 ppmv in the South Coast by Rule 431.1, 

Generally , the actual sulfur content is 4 (4 ppmv corresponds to 0.25 gr/100 scf). Actual gas content for 

combustion sources in the District is less than 4 ppmv. Rule 431.1 is not an offset rule and the applicant 

proposes to limit the sulfur content to less than 4 ppmv (permit condition, requires monthly testing for sulfur 

content)

A NOx CEMS will be used to verify compliance with the NOx BACT limit and a CO CEMS will be used to 

verify compliance with the CO BACT limit. The proposed control levels in the table above will meet current 

BACT requirements for all criteria pollutants including NH3. BACT is satisfied for each of the CTGs. 

During start-up operations for the turbines (see pages 23 and 24 for more information and see e-mail dated 

6/13/08 for the start-up emissions profile) , the control system will not be on line because the catalyst have 

a minimum inlet temp in order to reduce the pollutants the required BACT concentration limits. The turbine 

is equipped with water injection (limited NOx controls) and the NOx emissions during start-up is reduced to 

25 ppmv. Condition A433.1 limits the NOx emissions during the first hour of operation (includes start-up 

emissions with water injection in operation) and limits the number of start-ups per year and length of each 

start-up. During start-up it is not practical to require a NOx ppmv limit, but to limit the emissions during the 

start-up hour as done in condition A433.1, thus BACT needs to be defined during start-up to include the 

following

o Limit start-up time-condition, A99.1, A99.2, A99.3, A99.4, A99.9, A99.10, A433.1 and A433.2 

o Limit start-ups per year- conditions, A99.1, A99.2, A99.3, A99.4, A99.9, A99.10, A433.1 and 

A433.2 

o Limit NOx emissions per start-up hours, requires water injection to be used to comply- condition 

A433.1

RULE 1303(a) and Rule 2005(b)(1)(A)-BACT – Emergency Fire Pump Engine

Tier 3 fire pump is available, the applicant will propose a Tier 3 engine, the NOx+VOC will be less than 3 

g/bhp-hr (actual 2.627 g/bhp-hr), CO is listed at 0.6 g/bhp-hr and PM10 is listed at 0.079 g/bhp-hr

RULE 1303(a)-BACT – Cooling Tower

Rule 219(e)(3) provides and exemption for water cooling towers and water cooling ponds not used for 

evaporative cooling of process water or not used for evaporative cooling of water from barometric jets or 

from barometric condensers and in which no chromium compounds are contained. The eight cooling tower 

being proposed at CPV Sentinel will meet the requirements of Rule 219(s)(2), Rule 1401 MICR well below 

one in one million limits and is therefore exempt from NSR. BACT therefore does not apply.
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

RULE 1303(a)-BACT – Ammonia Storage Tank

No change from FDOC

RULE 1303(b)(1) and Rule 2005(b)(1)(B) - Modeling

The primary reason for revising the previous air quality impact analysis was then to ensure that proposed 

changes in the locations of certain project emissions sources and changes to the dimensions and locations 

of other buildings and structures on the site would not cause stack plume downwash conditions that would 

lead to higher offsite pollutant concentrations than were presented in the previous submittals to the District.

The applicant has conducted air dispersion modeling using the EPA AERMOD model. The Tier 4 Health 

Risk Assessment was conducted in accordance with guidelines set forth by the California Office of 

Environmental Health Hazard Assessment (OEHHA) and the California Air Resources Board (CARB). The 

OEHHA/CARB computer program (HARP) was used to determine the health risk assessment. The air 

dispersion model was run at a single normalized emission rate of 1.0 gram/sec. The applicant has 

submitted modeling results for both a commissioning and non-commissioning year which considered 

building downwash effects through the use of the EPA Building Profile Input Program, a program which is 

compatible with the ISCST3 model. Effects of terrain slope, aspect ratio, plume height, wind speed, wind 

direction and temperature were also accounted for in the analysis. The AERMOD model requires both 

surface and upper air meteorological data in the modeling applications. The National Weather Service 

(NWS) surface data at Dagget-Barstow station were used with wind data from the Wintec Wind Engery 

facility. The upper air data were obtained from the Desert Rock station in Nevada because it has the best 

data coverage for the modeling application. The analysis further accounted for flat, simple, intermediate, 

and complex terrain. Terrain features were taken from 1-second U.S. Geological Survey (USGS) data 

taken from its Digital Elevation Model (DEM). The DEM data provides terrain elevations with 1-meter

vertical resolution and 10-meters horizontal resolution based on a UTM coordinate system. The EPA 

SCREEN3 model was used to estimate potential impacts due to fumigation. Potential fumigation impacts 

were estimated for NO2, CO, and SO2. Table A-2 shown below is found in Rule 1303 and lists the most 

stringent ambient air quality standards and allowable change in concentration for each air contaminant. 

The appropriate averaging times are also listed. 

Table A-2

Most Stringent Ambient Air Quality Standard and 

Allowable Change in Concentration

For Each Air Contaminant/Averaging Time Combination

Air Contaminant Averaging 

Time

Most Stringent Air 

Quality Standard

Significant Change in 

Air Quality Concentration

Nitrogen Dioxide 1-hour 25 pphm 338 μg/m3 1 pphm 20 μg/m3

Annual 5.3 pphm 56 μg/m3 0.05 pphm 1 μg/m3

Carbon Monoxide 1-hour 20 ppm 23 μg/m3 1 pphm 1.1 μg/m3

8-hour 9.0 ppm 10 μg/m3 0.45 pphm 0.50 μg/m3

Suspended Particulate 

Matter <10μm (PM10)

24-hour 50 μg/m3 2.5 μg/m3

AGM5 30 μg/m3 1 μg/m

3

SO2 24-hour 25 μg/m3 1 μg/m3

The applicant is required under Rule 1303(b)(1) to demonstrate compliance with one of the following 

requirements: 

(a) The most stringent air quality standard shown in Table A-2 above, or 

 

5 AGM is the acronym for Annual Geometric Mean
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

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REVIEWED BY:

(b) The significant change in air quality concentration standards shown in Table A-2 above, if the most 

stringent air quality standards are exceeded

The applicant has submitted the following modeled maximum project impacts for CPV Sentinel. The 

applicant estimated the air quality impacts for many scenarios which included the commissioning, startup, 

normal operation, and shutdown phases. The worst-case scenario was identified for each pollutant and 

each averaging period. The numbers in the table below are per turbine.

Maximum individual Turbine Impacts for CPV Sentinel

Pollutant Averaging

Time

Turbine 

no. Max 

Impact 

(μg/m3)

Background

(μg/m3)

Total 

Impact 

(μg/m3)

Most Stringent

Standard 

(μg/m3)

Significant

Change in 

air quality 

concentratio

n (ug/m3)

Comply

(Yes/No)

NOx

1-hour NO. 8 22.50 174.8 197.3 338 N/a Yes

Annual No. 6 0.077 24.5 24.58 56 N/a Yes

SO2 24-hour No. 7 0.38 39.4 39.78 105 n/a Yes

1 -hour No. 7 1.45 62.5 63.95 655 n/a Yes

3-hour No. 7 1 41.6 42.6 1300 n/a Yes

Annual No. 8 0.06 10.7 10.76 80 n/a Yes

CO 1-hour NO. 8 34.04 2645 2679 23,000 N/a Yes

8-hour NO. 7 10.46 944.4 954.86 10,000 N/a Yes

Note, for the above values, the entire project impacts is less than concentration standards, see memo 

dated 11/13/09 by Naveen Barry

Pollutant Averaging

Time

Turbine 

no. Max 

Impact 

(μg/m3)

Significant

Change in 

air quality 

concentratio

n (ug/m3)

Comply

(Yes/No)

PM10

24-hour 8 1.99 2.5 Yes

AGM 8 0.06 1 Yes

As seen from the table above, both the 24-hour and AGM air quality standards for PM10 will be comply with 

the Significant Change in Air Concentration limit. The basin is non-attainment for PM10, the more stringent 

standard applies. Therefore, the applicant will be required to show compliance with the significant change 

in air quality standards for PM10.

The CO and NOx emissions were based on normal operation of the turbines (max hourly emissions), The 

short term impacts for the commissioning operations did not change and was not modeled. The CO BACT 

limit was revised to 4 ppmv instead of 6 ppmv, the revised CO modeling was based on 6 ppmv, because 

the consultant did not have enough time to update the modeling based on 4 ppmv for CO. The PM10 

emissions were based on 5 lb/hr. Note, CARB adopted new NOx standards of 338 ug/m3 (1 hour) and 56 

ug/m3 (annual) and the standards took effect in May 2008. Each turbine will comply with the revised NOx 

standards.

AQMD modeling staff reviewed the applicant’s analyses for both air quality modeling and health risk 

assessment (HRA). Modeling staff provided their comments in a memorandum from Mr. Barry to Mr. Mike 

Mills dated November 13, 2009, see Appendix M. A copy of this memorandum is contained in the 

engineering file. Staff’s review of the modeling and HRA analyses concluded that the applicant used EPA 

AERMOD model (version 07026) along with the appropriate model options in the analysis for NO2, CO, 

PM10, and SO2. The applicant modeled both the cumulative and individual permit unit impacts for the 
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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

project. The memorandum states that the ISCST3 modeling as performed by the applicant conforms to the 

District’s dispersion modeling requirements. No significant deficiencies in methodology were noted.

Protection of Visibility. The visibility analysis was not revised. The revisions to the project will result in the 

short-term project emissions to be either at the same level or less than what was previously analyzed. The 

second largest source of combustion pollutant emissions was the blackstart engine, which has been 

removed from the project. The PM10 emissions from the cooling towers are less than the emissions 

originally included. Therefore, the visibility impacts from the revised project are less than the PLUVUE II 

impacts contained in the original report. Confirmed by District modeling staff, see memo dated 11/13/09. 

PSD Analyses The applicant estimated the emissions from the proposed project for NO2, CO, PM10, and 

SO2. The emission summary is Appendix C. Rule 1702 (m) (1) states that a major stationary source 

includes steam electric plants of more than 250 MMBTU/hr heat input. Although this facility will have a heat 

input of greater than 250 MMBTU/hr, it only produces electric power through mechanical means and not 

through a steam process as defined under subsection (1) of the rule. Therefore, the proposed simple cycle 

units are subject to subsection (2) which places the Major Stationary Source threshold on emissions of 250 

tons per year or more. The maximum NOx potential to emit for these 8 turbines is 143 tons per year, 

therefore, this project is not considered a Major Stationary Source and is not subject to the rule 1703 NOx 

PSD analysis.

RULE 1303(b)(2) and Rule 2005(b)(2)-Offsets – LMS100 PA CTGs

Since CPV Sentinel is a new facility with an emissions increase, offset requirements apply. CPV Sentinel

has opted into AQMD’s NOx RECLAIM program and as such, NOx increases will be offset with RTCs at a 

1.0 to1 ratio. For non-RECLAIM non-attainment (or precursors to non-attainment) criteria pollutants the

VOC emissions will be offset by the purchase of Emission Reduction Credits (ERCs) at a 1.2 to 1 ratio.

Since CO is an attainment pollutant there are no offset requirements for CO. For PM10 and SOx 

emissions offsets please refer to Appendix N. 

I Required Offsets for RECLAIM Pollutants (NOx)

The required RTCs for NOx for the first and second years of operation are shown below. The values 

include start-ups, commissioning (first year only), normal operation, and shutdowns, see Appendix F for 

details. (The total emissions for the second year excludes commissioning).

Turbines one through eight

Hours NOx NOx NOx

Operating Condition 103 per (lb/hr) (lb/year) (lb/year)

Year per device cumulative

CTGs

 Startup 125 59.76 7,470.00 59,760

 Shutdown 50 34.95 1,747.50 13,980

 Normal Operation 2,628 7.95 20,862.60 167,147.8

 Commissioning 150 38.19 5,728.50 45,828
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

CTG Totals 2,953 35,838.60 286,708.80

Hours NOx NOx

Operating Condition 103 per (lb/hr) (lb/year)

Year cumulative

CTG 1-8 Totals 286,708.8

Emergency Fire Pump 50 1.54 77.25 77.25

Total 1st Year Emissions (lb/year) 286,786.05

Offset Ratio 1.00

1st year RTCs (lb/year) 286,786.05

2nd year RTCs (lb/year) 241,958.05

II Required Offsets for Non-RECLAIM Pollutants (VOCs, SOx, CO and PM10)

Table 18 shows the facility-wide 30-day averages for CO and VOC. Offsets are based upon 30-day 

averages from individual permit units. As mentioned above, CPV Sentinel may elect to use ERCs or other 

means to provide the required offsets. The amounts in Table 18 are required to fully offset the facility 

increases and satisfy the requirements of Rule 1303(b)(2): 

Table 18 – 30-Day Averages for the Entire Facility, (lb/day)

NOx CO VOC

Maximum 30 Day Average 2994 367.6

Table 19 - Required Offsets for Non-RECLAIM Pollutants (for entire facility)

NOx CO VOC

Maximum 30 Day Average 2994 367.6

Offset Ratio 1.2 1.2

Required Offsets 441.42

Required Offsets 441

Table 20 - Required Offsets for Non-RECLAIM Pollutants (per-turbine basis lb/day)

NOx CO VOC

Maximum 30 Day Average 374 45.95

Offset Ratio 1.2

Required Offsets 55.14

Offsets are not required for CO, since the Salton Sea Air Basin in AQMD is in attainment with CO. The CO

emissions are listed for informational purposes only in this section, however the analysis for attainment 

pollutants is disussed under Regulation XVII.
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

The table below shows the total amount of VOC ERC’s that CPV Sentinel has purchased as of February 

28, 2010. The table consists of two ERC certificates for VOC (certificate no. see below) purchased on 

3/27/08, from Tenaska in the amount of 412 lb/day. 

Total Amount of Emission Reduction Credits currently held by CPV Sentinel

Pollutant ERC Certificate No. Date of 

Purchase Name of Seller Amount of ERC (lb/day)

VOC AQ007877 03/27/08 Tenaska 348

VOC AQ007879 03/27/08 Tenaska 64

CPV Sentinel has indicated that the required amounts of offsets will be provided prior to issuance of the 

Facility Permit. Compliance with offset requirements of Rules 1303(b)(2) is required prior to issuance of 

the Permits to Construct.

The maximum PM10 and SOx emissions occur during a commissioning year and are as follows:

PM10 lb/yr SOX lb/yr

Maximum pounds per year, includes 

commissioning period 118,120 13,928

For PM10 and SOx offset evaluation, please refer to Appendix N

AB1318 (California Health & Satety Code Section 40440.14)

AB1318 was enacted by the State Legislature on 9/11/09 and was signed into law by the Governor on 

10/11/09 and became effective on 1/1/2010. The bill will add Section 3619.8 to, and to add and repeal 

40440.14 of, the Health and Safety Code, and to amend Section 21080 of the Public Resource Code, 

relating the SCAQMD. 

To be eligible for the emissions credits under AB1318 the electrical generating facility shall meet the 

requirements pursuant to Health & Safety Code Section 4040.14 (d) as shown in Table 25 below.

Table 25 -

AB1318 Compliance for CPV Sentinel Project

Subject to State Resources conservation and 

development commission permitting 

jurisdiction

Yes

Have a power purchase agreement prior to 

12/31/2008 with a public utility in the LA 

basin

Yes

Be under jurisdiction the AQMD, but not 

located within the South Coast Air Basin

Yes, facility located in the Salton Sea air 

basin under AQMD jurisdiction

Can not transfer credits until mitigation 

fees are paid. The fees are set per Rule 

1309.1 adopted on Aug 3, 2007

Applicant needs to pay the mitigation fee 

prior to the issuance of emissions credits, 

fee calculation in appendix L

Turbines 1 though 5 will pay mitigations fees per Rule 1309.1 (g)(1)(F)

Turbines 6 though 8 will be mitigations fees per Rule 1309.1 (g)(1)(B)
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

See Appendix L for fee determination under AB1318

Fuel limits

The facility’s maximum monthly and annual fuel usage (caps) for the simultaneous operation of the 8 CTGs 

will be 3,400 mmscf and 19640 mmscf, respectively, based on operating condition 103. The annual fuel 

cap will be the basis for the facility’s PTE. The monthly and annual fuel caps will correspond to 485

hours/month and 2803 hours/year of operation for each turbine. These values were selected by CPV 

Sentinel. 

The fire pump engine will have hours per year limitations. The calculations are shown below and a monthly 

fuel cap (ref Appendix G) will be included on the Facility Permit as a permit condition. 

Commissioning period

CTG fuel/turbine = 301 mmcf 

Non commissioning period Turbines 1 through 8 (per turbine)

Monthly:

CTGFuel =(485 hr/mon) * 891.7 mmbtu/hr * 1ft3/1018 btu

CTG Fuel = 425 mmcf/month

Annually:

CTG Fuel =(2803 hr/yr) * 891.7 mmbtu/hr * 1ft3/1018 btu

CTGFuel= 2,455.24 mmcf/yr

Non commissioning period Turbines 1 through 8 (total)

Monthly:

CTGFuel = 425 mmcf/month * 8 turbines

CTG Fuel = 3400 mmcf/month

Annually:

CTG Fuel =2455.24 mmcf/yr * 8 turbines

CTGFuel= 19,642 mmcf/yr

RULES 1303(b)(3)-Sensitive Zone Requirements and 2005(e)-Trading Zone Restrictions

Both rules state that credits must be obtained from the appropriate trading zone. In the case of Rule 

1303(b)(3), facilities located in the South Coast Air Basin are subject to the Sensitive Zone requirements 

specified in Health & Safety Code Section 40410.5. CPV Sentinel is located in the Coachella Valley and is 

therefore eligible to obtain its ERCs from either Zone 1 or Zone 2a. Similarly in the case of Rule 2005(e), 

CPV Sentinel, because of its location may obtain RTCs from either Zone 1 or Zone 2, at its choosing. 

Therefore upon providing the adequate amount of emissions reductions credits or RTCs compliance is 

expected with both rules.

RULE 1303(b)(4)-Facility Compliance
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

No change

RULE 1303(b)(5)-Major Polluting Facilities

Rule 1303(b)(5)(A) – Alternative Analysis

No change

Rule 1303(b)(5)(B) – Statewide Compliance

No change

Rule 1303(b)(5)(C) – Protection of Visibility

Modeling is required if the source is within a Class I area and the NOx and PM10 emissions exceed 40 

TPY and 15TYP respectively. There are three Class I sites is located within the minimum distances to 

this facility. Modeling from plume visibility is required, however, the applicant has provided modeling 

impact data for the Class I areas and the data was reviewed by District’s modeling staff and complies 

with this section of the Rule.

Rule 1303(b)(5)(D) – Compliance through CEQA

No change

Rule 1401 – New Source Review of Toxic Air Contaminants

This rule specifies limits for maximum individual cancer risk (MICR), acute hazard index (HIA), chronic 

hazard index (HIC) and cancer burden (CB) from new permit units, relocations, or modifications to existing 

permits which emit toxic air contaminants. Rule 1401 requirements are summarized as follows:

Table 22 – Rule 1401 Requirements

Parameters and 

Specifications Rule 1401 Requirements

MICR, without T-BACT ≤ 1x10-6

MICR, with T-BACT ≤ 1x10-5

Acute Hazard Index ≤ 1.0

Chronic Hazard Index ≤ 1.0

Cancer Burden ≤ 0.5

The applicant performed a Tier 4 health risk assessment using the Hot Spots Analysis and Reporting 

Program (HARP, version 1.2a). The applicant used EPA ISCST3 model (version 99155) in their modeling 

analysis. (This is the version of ISCST3 used in HARP.) The analysis included an estimate of the MICR for 

the nearest residential and commercial receptors, the acute and chronic hazard indices for the entire 

facility. PRA modeling staff reviewed the applicant’s methodology and procedures used, and re-ran the 

HARP model and verified the health risk and hazard indices which were presented by the applicant. PRA 

staff concluded that each of the health risk values for MICR, HIA and HIC were appropriately estimated 

(see memorandum in file, dated November 13, 2009 from MR. Naveen Berry to Mr. Mike Mills). Table 24

below is a summary of the modeled health risk assessment results (list largest MICR, HIA and HIC 

regardless of receptor location). The cancer burden is not calculated because the MICR is less than 1 x 

10-6for both residential and commercial receptors. See Appendix I for TAC emissions calculations.

 Table 23 – Rule 1401 Modeled Results

Turbine 1
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ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Risk Parameter Cancer Risk Rule 1401 

Requirements

Compliance

(Yes/No)

MICR 0.00514 x 10-06 ≤ 1 x 10-6Yes

HIA 0.0147 ≤ 1.0 Yes

HIC 0.00016 ≤ 1.0 Yes

Receptor UTMs 539411E / 374511N

Turbine 2

Risk Parameter Cancer Risk Rule 1401 

Requirements

Compliance

(Yes/No)

MICR 0.00509 x 10-06 ≤ 1 x 10-6Yes

HIA 0.0148 ≤ 1.0 Yes

HIC 0.00016 ≤ 1.0 Yes

Receptor UTMs 539411E /3745100N

Turbine 3

Risk Parameter Cancer Risk Rule 1401 

Requirements

Compliance

(Yes/No)

MICR 0.00505 x 10-06 ≤ 1 x 10-6Yes

HIA 0.0149 ≤ 1.0 Yes

HIC 0.00015 ≤ 1.0 Yes

Receptor UTMs 539411E / 6745110N

Turbine 4

Risk Parameter Cancer Risk Rule 1401 

Requirements

Compliance

(Yes/No)

MICR 0.00504x 10-06 ≤ 1 x 10-6Yes

HIA 0.0148 ≤ 1.0 Yes

HIC 0.00015 ≤ 1.0 Yes

Receptor UTMs 537111E / 3758610N

Turbine 5

Risk Parameter Cancer Risk Rule 1401 

Requirements

Compliance

(Yes/No)

MICR 0.00506 x 10-06≤ 1 x 10-6Yes

HIA 0.0148 ≤ 1.0 Yes

HIC 0.00015 ≤ 1.0 Yes

Receptor UTMs 537211E / 3758510N

Turbine 6

Risk Parameter Cancer Risk Rule 1401 

Requirements

Compliance

(Yes/No)

MICR 0.00512 x 10-06≤ 1 x 10-6Yes

HIA 0.0146 ≤ 1.0 Yes

HIC 0.00016 ≤ 1.0 Yes

Receptor UTMs 537311E / 3758410N

Turbine 7

Risk Parameter Cancer Risk Rule 1401 

Requirements

Compliance

(Yes/No)

MICR 0.0051 x 10-06≤ 1 x 10-6Yes

HIA 0.0146 ≤ 1.0 Yes

HIC 0.00016 ≤ 1.0 Yes

Receptor UTMs 537311E / 3758510N
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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

Turbine 8

Risk Parameter Cancer Risk Rule 1401 

Requirements

Compliance

(Yes/No)

MICR 0.0509 x 10-06≤ 1 x 10-6Yes

HIA 0.0147 ≤ 1.0 Yes

HIC 0.00016 ≤ 1.0 Yes

Receptor UTMs 537211E / 3758310N

Table 24 shows that CPV Sentinel will comply with the applicable requirements of Rule 1401. The cancer 

burden is not computed because the highest MICR is less than 1 x 10-6. The applicant use EPA ISCST3 

(version 99155) in their modeling analysis (this is the version of ISCST3 used in HARP) The applicant 

performed the risk assessment with the Hot Spots Analysis and Reporting Program (HARP, version 1.3). 

Planning reviewed the See Appendix H for the actual TAC emissions. 

The fire pump are exempt per section (i)(1)(A). The cancer risk was calculated for this equipment and is 

listed below for informational purposes only.

The peak cancer risks for the total project at all receptors is 0.5 in one million. The peak acute and chronic 

hazard indices for the total project are 0.1 and 0.008, respectively. These total facility risks are less than 

the Rule 1401 cancer and non-cancer permit limits of 10 in one million and hazard index of 1, respectively. 

Confirmed by District modeling staff, see memo dated 11/13/09

The combined risk for all the cooling towers is 0.00957 in a million

Fire pump engine risk is 0.4699 in a million

The total risk for all the turbines, one fire pump and cooling towers is 0.52016 in a million. The peak 

The table below list the MICR/HIA/HIC at the residential and commercial receptor

Table 24 – Rule 1401 Modeled Results for nearest residential/commercial receptor

Source Residential Commercial Residential Commercial Residential Commercial

MICR MICR HIC HIC HIA HIA

Gas Turbine No. 1 5.44E-06 1.32E-04 3.02E-06 2.08E-05 1.30E-03 1.58E-03

Gas Turbine No. 2 9.47E-06 9.66E-05 3.67E-06 3.25E-05 1.14E-03 1.98E-03

Gas Turbine No. 3 1.82E-05 6.95E-05 3.73E-06 4.77E05 1.27E-03 2.26E-03

Gas Turbine No. 4 3.23E-05 5.31E-05 3.31E-06 6.27E-05 1.53E-03 2.36E-03

Gas Turbine No. 5 4.77E-05 4.79E-05 2.73E-06 7.14E-05 1.44E-03 2.25E-03

Gas Turbine No. 6 5.62E-05 4.52E-05 2.22E-06 7.14E-05 1.09E-03 1.96E-03

Gas Turbine No. 7 5.62E-05 4.09E-05 1.89E-06 6.29E-05 6.88E-04 1.64E-03

Gas Turbine No. 8 5.13E-05 3.82E-05 1.76E-06 5.03E-05 3.78E-04 1.67E-03

Total Project (includes 

turbines, fire pump, engine & 

cooling towers) 2.83E-01 5.15E-02 2.45E-03 7.03E-03 9.11E-03 1.64E-02
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ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

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REVIEWED BY:

Location

30 meters 

of eastern 

fence

Devers 

substation

230 m east 

of the 

eastern 

fence

Wintec Wind 

farm

230 m east 

of the 

eastern 

fence

RULE 1470-Requirements for Stationary Diesel-Fueled Internal Combustion and Other Compression 

Ignition Engines. 

No change, Fire pump complies with this Rule

RULE 1472- Requirements for Facilities with Multiple Stationary Emergency Standby Diesel-Fueled 

Internal engines

No change

Rule 2005(g) – Additional Requirements

No change

Rule 2005(h) – Public Notice 

No change

Rule 2005(i) – Rule 1401 Compliance. 

CPV Sentinel will comply with Rule 1401 as demonstrated in the Tier 4 analysis and subsequently 

reviewed and found to be satisfactory by AQMD modeling staff. Compliance is expected.

 

Rule 2005(j) – Compliance with State and Federal NSR. 

No change

Rule 2005 – Fire pump 

No change

Tier 3 engines are available, the applicant proposes to install a Tier 3 engine, the NOx+VOC are below the 

3 g/bhp-hr limits, see appendix D

RTCs- Rule 2012(e)(2)(C)

BACT limit = 3 g/bhp-hr

Fuel rate = 13.5 gal/hr

EF = 3 g/bhp-hr *(1 lb/454 g) * (1 hr/ 13.5 gal) * (1000 gal/M gal) *274 HP

EF = 134 lb/mgal

Rule 2012 – RECLAIM, Monitoring Recording and Recordkeeping Requirements

No change
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

REGULATION XVII-Prevention of Significant Deterioration

The applicant estimated the emissions from the proposed project for NO2, CO, PM10, and SO2. The 

emission summary is Appendix C. Rule 1702 (m) (1) states that a major stationary source includes steam 

electric plants of more than 250 MMBTU/hr heat input. Although this facility will have a heat input of greater 

than 250 MMBTU/hr, it only produces electric power through mechanical means and not through a steam 

process as defined under subsection (1) of the rule. Therefore, the proposed simple cycle units are subject 

to subsection (2) which places the Major Stationary Source threshold on emissions of 250 tons per year or 

more. The maximum NOx potential to emit for these 8 turbines is 143 tons per year, and the maximum CO 

potential to emit for these 8 turbines is 188 tons per year. Therefore, this project is not considered a Major 

Stationary Source and is not subject to the rule 1703 NOx and CO PSD analysis. Rule 1701 (b)(1) 

requires CO BACT be applied to the Turbines. The turbines will be vented to CO control and the CO 

emissions will be limited to 4 ppmv (permit condition).

INTERIM PERIOD EMISSION FACTORS

RECLAIM requires a NOx emission factor to be used for reporting emissions during the interim reporting 

period. The interim period is defined as a period, of no greater than 12 months from initial operation, when 

the CEMS has not been certified. During this period, the emissions cannot be accurately, monitored, or 

verified. The emissions during this period are assumed to be at uncontrolled levels. The interim reporting 

period can be broken down into the two parts which includes the commissioning period in which an 

uncontrolled emission rate is assumed. The emission factor for the commissioning period is an average of 

for the entire 150 hour period. During this period, the turbines may be uncontrolled, partially controlled, or 

100 percent controlled. The remaining interim reporting period at which controlled rates at BACT are 

assumed. 

Since CPV Sentinel will be included in NOx RECLAIM, an interim period emission factor will be 

determined. In the event CEMS data is not available, NOx emissions during the interim period will be 

calculated using monthly fuel usage and the emission factors derived below. There will be two interim 

period emission factors calculated for NOx. 

The first factor will be for use during commissioning stage when the CTGs are assumed to be operating at 

uncontrolled levels and the second factor will be for use after commissioning is complete and the CTGs are 

assumed to operate at BACT levels. The specific calculations are shown in Appendix G and the results are 

shown in the tables below. 

Commissioning Period

Pollutants NOx CO

Total emissions (lbs) 5728 11602

Total Fuel (mmscf) 301.48 301.48

Emission Factor (lb/mmscf) 19.0 38.48

Remaining Period (Non-Commissioning start-up)

Pollutants NOx CO

Total emissions (lbs) 240881 282475

Total Fuel (mmscf) 19642 19642

Emission Factor (lb/mmscf) 12.26 14.38

CALIFORNIA ENVIRONMENTAL QUALITY ACT (CEQA)
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ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

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REVIEWED BY:

No change

NSPS for Stationary Gas Turbines - 40CFR Part 60 Subpart KKKK

No change

NESHAPS for Stationary Gas Turbines - 40CFR Part 63 Subpart YYYY

This regulation applies to gas turbines located at major sources of HAP emissions. A major source is 

defined as a facility with emissions of 10 tpy or more of a single HAP or 25 tpy or more of a combination of 

HAPs. The largest single HAP emission from the turbine or engine is formaldehyde from the turbine at 900

lbs/yr, or 0.45 tpy. The total combined HAPs from both sources at CPV Sentinel are less than 25 tpy 

(reference Appendix I). Therefore, the CPV Sentinel facility is not a major source, and the requirements of 

this regulation do not apply. Ammonia is not defined as an HAP pollutant per this Rule.

EPA has indicated there are NESHAPS for area sources dated 3/5/2009 (40 CFR Part 63). Per table 2 of 

the Rule (pg 9703), the fire pump is listed between 50 and 500 HP, the following is required:

o Change oil and oil filter every 500 hours of operation

o Inspect air cleaner every 1000 hours

o Inspect all hoses and belts every 500 hours of operation

40 CFR Part 64 – Compliance Assurance Monitoring

The CAM regulation applies to emission units at major stationary sources required to obtain a Title V 

permit, which use control equipment to achieve a specified emission limit. The rule is intended to provide 

“reasonable assurance” that the control systems are operating properly to maintain compliance with the 

emission limits. Based on the emission calculations shown in Appendix K, the CPV Sentinel facility is a 

major source of NOx, CO, VOC, and PM10, and the turbines will be subject to an emission limit for each of 

these pollutants.

NOx

 Emission Limit – NOx is subject to a 2.5 ppm 1 hour BACT limit.

 Control Equipment – NOx is controlled with the SCR

 Requirement - As a NOx Major Source under Reclaim, the turbines are required to have CEMS 

under Rule 2012. The use of a continuous monitor to show compliance with an emission limit is 

exempt from CAM under 64.2(b)(vi). 

CO

 Emission Limit – CO is subject to a 4.0 ppm 1 hour BACT limit (revised CO BACT limit).

 Control Equipment – CO is controlled with the oxidation catalyst.

 Requirement – The turbines will be required to use a CO CEMS under Rule 218. The use of a 

continuous monitor to show compliance with an emission limit is exempt from CAM under 

64.2(b)(vi).

VOC

 Emission Limit – VOC is subject to a 2.0 ppm 1 hour BACT limit.

 Control Equipment – VOC is controlled with the oxidation catalyst.

 Uncontrolled emissions-R1 emissions per turbine s 8 tons/yr (see Appendix K)
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ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

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 The CAM rule applies to each pollutant specific emission units (PSEU) that meets a three-part test. 

The PSEU must: 

a. be subject to an emission limitation or standard, and

b. use a control device to achieve compliance, and

c. have pre-control emissions that exceed or are equivalent to the major source

threshold. 

VOC emissions are subject to an emissions limit (2 ppmv)

The oxidation catalyst will be used to reduce the R1 emissions below the compliance emissions 

limit The pre-control emissions does not exceed the 10 tons per year emissions threshold per 

turbine. Thus the CAM requirements for VOC does not apply for this equipment.

 Requirement – The oxidation catalyst is effective at operating temperatures above 300°F. The 

facility is required to maintain a temperature gauge in the exhaust (condition D12.3), which will 

measure the exhaust temperature on a continuous basis and record the readings on an hourly 

basis. The exhaust temperature is required to be at least 700°F, (with exceptions for start ups and 

shutdowns). This will insure that the oxidation catalyst is operating properly. 

PM10

 Emission Limit – PM10 is subject to a 5 lbs/hr limit. Also an annual emissions limit based on a 12 

month rolling average for PM10 and SOx, see permit condition no. A63.2

 Control Equipment – PM10 is not controlled by any specific control device.

 Requirement – Since there is no specific control device for PM10 emissions, there are no CAM 

requirements.

40CFR Part 72 – Acid Rain Provisions

No change

Federal NSR program for PM 2.5, PSD and 40CFR Part 51 Appendix S

The proposed facility is located in the Coachella Valley which is part of the Salton Sea Air Basin (SSAB). 

The SSAB is in attainment with the National Ambient Air Quality Standard for PM 2.5, and therefore the 

project is not subject to Non-Attainment NSR requirements such as offsets for PM2.5.

The applications were deemed complete prior to 07/15/08 and the Facility is located in attainment area. 

This project is not subject to Appendix S requirements.

The total PM2.5 emissions (assuming all PM10 emissions are PM2.5) is 56 tons per year is well below the 

100 ton/yr PSD threshold, and therefore it is not subject to the PSD. 

REGULATION XXX – Title V

There is a net decrease in emissions (see Rule 212 section) from the draft Title V permit sent to EPA on 

May 7, 2009. There is not relaxation of any permit permit conditions. The CO BACT limit has been reduced 

to 4 ppmv. 
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

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ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

OVERALL EVALUATION / RECOMMENDATION(S)

Issue a Facility Permit to Construct with the following permit conditions.

PERMIT CONDITIONS

Facility Permit conditions

F9.1 Except for open abrasive blasting operations, the operator shall not discharge into the 

atmosphere from any single source of emissions whatsoever any air contaminant for a 

period or periods aggregating more than three minutes in any one hour which is:

(a) As dark or darker in shade as that designated No.1 on the Ringelmann Chart, as 

published by the United States Bureau of Mines; or

(b) Of such opacity as to obscure an observer' s view to a degree equal to or greater

than does smoke described in subparagraph (a) of this condition.

[RULE 401, 3-2-1984; RULE 401, 11-09-2001]

F14.1

The operator shall maintain a copy of the MSDS on site

[Rule 431.2]

(LMS100PA CTGs) Devices D1,D7,D13,D19,D25, D31, D37 and D43

A63.1 The operator shall limit emission from this equipment as follows:

CONTAMINANT EMISSION LIMIT

PM10 2,425 LBS IN ANY ONE MONTH

CO 6,477 LBS IN ANY ONE MONTH

SOx 293 LBS IN ANY ONE MONTH

VOC 1432 LBS IN ANY ONE MONTH

The above emissions are per one turbine. The operator shall calculate the monthly 

emissions for VOC, PM10 and SOx using the equation below and the following emission 

factors: VOC: 2.52 lb/mmcf; PM10: 5.71 lb/mmcf; and SOx: 0.71 lb/mmcf.

Monthly Emissions, lb/month = X (E.F.)

Where X = monthly fuel usage in mmscf/month and E.F. = emission factor indicated 

above.

Compliance with the CO emission limit shall be verified through valid CEMS data.

The operator shall calculate the emission limit(s) for the purpose of determining

compliance with the monthly CO limit in the absence of valid CEMS data by using the 

above equation and the following emission factor(s): 

(A) During the commissioning period and prior to CO catalyst installation – 38.48 lbs 

CO/mmcf

(B) After installation of the CO catalyst but prior to CO CEMS certification testing –

14.38 lb CO/mmcf. The emission rate shall be recalculated in accordance with 

Condition D82.1 if the approved CEMS certification test resulted in emission 

concentration higher than 4 ppmv.

(C) After CO CEMS certification testing – 14.38 lb/CO mmcf. After CO CEMS 

certification test is approved by the AQMD, the emissions monitored by the CEMS and 

calculated in accordance with condition D82.1 shall be used to calculate emissions.

For the purposes of this condition, the limit(s) shall be based on the emissions from 

a single turbine. During commissioning, the CO emissions shall not exceed 11,602 lbs 
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ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

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REVIEWED BY:

in any one month. During commissioning, the VOC emissions shall not exceed 620 lbs in 

any one month.

The operator shall provide the AQMD with written notification of the date of initial 

CO catalyst use within seven (7) days of this event.

For the purpose of this condition the turbine shall not commence with normal operation 

until the commissioning process has been completed. The District shall be notified in 

writing once the commissioning process has been completed. Normal operations may

proceed in the same commissioning month provided the operator follows the requirements 

listed below.

The operator shall calculate the commissioning emissions for VOC, SOx and PM10 for the 

commissioning month (beginning of the month to the last day of commissioning) using 

the equation below and the following emission factors: VOC: 2.06 lb/mmcf; PM10: 2.49

lb/mmcf; and SOx: 0.12 lb/mmcf.

Commissioning Emissions, lb/month = X (E.F.)

Where X = commissioning fuel usage in mmscf/month and E.F. = emission factor indicated

above.

The commissioning emissions for VOC, SOx and PM10 shall be subtracted from the monthly 

emissions limits (listed in the table at the top of this condition) and the revised 

monthly emission limits will be the maximum emissions allowed for the remaining of the 

month. 

For the purpose of this condition, normal operations is defined as the turbine is able 

to supply electrical energy to the power grid as required under contract with SCE or 

other entity. 

[Rule 1303 – Offsets]

Turbines 1-5

A63.2 The operator shall limit emission from this equipment as follows:

 

CONTAMINANT EMISSION LIMIT 

PM10 118,120 LBS IN ANY ONE YEAR

SOx 13,928 LBS IN ANY ONE YEAR

For the purposes of this condition, the annual limit(s) shall be calculated by using 

annual and monthly fuel use data, and the following emission factors: PM10 5.71 

lb/MMSCF; and SOx: 0.25 grains/100 scf. 

For the purpose of this condition, the yearly emission limit shall be defined as a 

period of twelve (12) consecutive months determined on a rolling basis with a new 12 

month period beginning on the first day of each calendar month.

[Rule 1303 – Offsets, 40CFR 51 subpart S]

A99.1 The 2.5 PPM NOx emission limits shall not apply during turbine commissioning, startup, and shutdown periods. The commissioning period shall not exceed 150 hours. 

Start-up time shall not exceed 25 minutes for each start-up. Shutdown periods shall 

not exceed 10 minutes for each shutdown. The turbine shall be limited to a maximum of 

300 start-ups per year. Written records of commissioning, start-ups and shutdowns 

shall be maintained and made available upon request from the Executive Officer.

For this condition start-up shall be defined as the start up process to bring the 

turbine in full successful operations. If during start-up the process is aborted and 

the start-up is restarted, then the start-up and restart is defined as "one start-up”. 
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ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

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REVIEWED BY:

In this case the start-up time shall not exceed one hour. The NOx emissions limited to 

29.54 pounds per hour as listed in condition A433.1

The operator shall keep records of aborted turbine start-ups and make the records 

available to District personnel upon request.

[Rule 2005]

Turbine 1 through 8

A99.3 The 4.0 PPM CO emission limits shall not apply during turbine commissioning, startup, and shutdown periods. The commissioning period shall not exceed 150 hours. 

Start-up time shall not exceed 25 minutes for each start-up. Shutdown periods 

shall not exceed 10 minutes for each shutdown. The turbine shall be limited to a 

maximum of 300 start-ups per year. Written records of commissioning, start-ups and 

shutdowns shall be maintained and made available upon request from the Executive 

Officer.

For this condition start-up shall be defined as the start up process to bring the 

turbine in full successful operations. If during start-up the process is aborted and 

the start-up is restarted, then the start-up and restart is defined as "one start-up”. 

In this case the start-up time shall not exceed one hour.

[Rule 1303(a) – BACT]

Turbine 1 through 8

A99.5 The 19 LBS/MMCF NOx emission limits shall only apply during the interim reporting 

period during initial turbine commissioning to report RECLAIM emissions. The interim 

reporting period shall not exceed 12 months from entry into RECLAIM. 

[Rule 2012 – Requirements for Monitoring, Reporting and Recordkeeping for Oxides of 

Nitrogen Emissions]

Each Turbine

A99.7 The 12.26 LBS/MMCF NOx emission limits shall only apply during the interim reporting 

period after initial turbine commissioning to report RECLAIM emissions. The interim 

reporting period shall not exceed 12 months from entry into RECLAIM. 

[Rule 2012 – Requirements for Monitoring, Reporting and Recordkeeping for Oxides of 

Nitrogen Emissions]

Each turbine

A99.9 The 2.0 PPM VOC emission limits shall not apply during turbine commissioning, startup, and shutdown periods. The commissioning period shall not exceed 150 hours. 

Start-up time shall not exceed 25 minutes for each start-up. Shutdown periods 

shall not exceed 10 minutes for each shutdown. The turbine shall be limited to a 

maximum of 300 start-ups per year. Written records of commissioning, start-ups and 

shutdowns shall be maintained and made available upon request from the Executive 

Officer.

For this condition start-up shall be defined as the start up process to bring the 

turbine in full successful operations. If during start-up the process is aborted and 

the start-up is restarted, then the start-up and restart is defined as "one start-up”. 

In this case the start-up time shall not exceed one hour.

[Rule 1303(a) – BACT]

Turbine 1 through 8

A195.1 The 4.0 PPMV CO emission limit(s) is averaged over 60 minutes at 15 percent O2, dry.

[Rule 1703(a)(2)– PSD-BACT]

Each Turbine
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

A195.2 The 2.5 PPMV NOX emission limit(s) is averaged over 60 minutes at 15 percent O2, dry.

[Rule 2005, Rule 1703(a)(2)– PSD-BACT]

Each Turbine

A195.3 The 2.0 ppmv VOC emission limit(s) is averaged over 60 minutes at 15 percent O2, dry.

[Rule 1303(a) – BACT]

Each Turbine

A327.1 For the purpose of determining compliance with District Rule 475, combustion 

contaminants emissions may exceed the concentration limit or the mass emission 

limit listed, but not both limits at the same time. 

[Rule 475]

Each Turbine

A433.1 The operator shall comply at all times with the 2.5 ppm 1-hour BACT limit for NOx, 

except as defined in condition A99.1 and for the following scenario:

Operating Scenario Maximum Hourly 

Emission Limit Operational Limit

Start-up hour 29.54lb/hr NOx emissions not to exceed 

29.54lbs total per start-up per 

turbine. Each turbine shall be 

limited to 300 start-ups per 

year, with each start-up not to 

exceed 25 minutes.

[Rule 1703(a)(2)-PSD-BACT, Rule 2005]

Turbine 1 through 8

B61.1 The operator shall not use natural gas containing the following specified 

compounds:

Compound Grains per 100 scf

H2S Less than 0.25

This concentration limit is an annual average based on monthly sample of natural gas 

composition or gas supplier documentation. Gaseous fuel samples shall be tested using 

District Method 307-91 for total sulfur calculated as H2S.

[Rule 1303(b) – Offset]

Each Turbine

C1.1 The operator shall limit the fuel usage to no more than 425 mmcf in any one calendar 

month.

For the purpose of this condition, fuel usage shall be defined as the total 

natural gas usage of a single turbine during a non-commissioning month.

The operator shall maintain records in a manner approved by the District to 

demonstrate compliance with this condition. 

[Rule 1303(b)(2) – Offset]

 For turbines 1 -8

C1.3 The operator shall limit the fuel usage to no more than 301 mmcf.

For the purpose of this condition, fuel usage shall be defined as the total natural 

gas usage of a single turbine during a commissioning period. The max fuel usage 

shall not exceed 301 mmcf per month.
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

The operator shall maintain records in a manner approved by the District to 

demonstrate compliance with this condition. 

[Rule 1303(b)(2) – Offset]

 Each Turbine

C1.6 The operator shall limit the fuel usage to no more than 2455 mmcf in any one calendar 

year.

For the purpose of this condition, fuel usage shall be defined as the total 

natural gas usage of a single turbine during a non-commissioning year.

The operator shall maintain records in a manner approved by the District to 

demonstrate compliance with this condition. 

[Rule 1401, Rule Rule 1701 (b)]

 For turbines 1 -8

 D12.1 The operator shall install and maintain a(n) flow meter to accurately indicate the 

fuel usage being supplied to the turbine.

The operator shall also install and maintain a device to continuously record the 

parameter being measured 

[Rule 1303(b)(2) – Offset, Rule 2012]

 Each Turbine

D29.1 The operator shall conduct source test(s) for the pollutant(s) identified below.

Pollutant to be 

tested

Required Test 

Method(s)

Averaging Time Test Location

NOX emissions District Method 

100.1

1 hour Outlet of the SCR

CO emissions District Method 

100.1

1 hour Outlet of the SCR

SOX emissions AQMD Laboratory 

Method 307-91

Not applicable Fuel Sample

VOC emissions District Method 

25.3

1 hour Outlet of the SCR

PM10 emissions District Method 5 4 Hours Outlet of the SCR

NH3 emissions District method 

207.1 and 5.3 or 

EPA method 17

1 hour Outlet of the SCR

The test shall be conducted after AQMD approval of the source test protocol, but no 

later the later of 180 days after initial start-up or three hundred hours of 

operations after start-up. The AQMD shall be notified of the date and time of the 

test at least 10 days prior to the test.

The test shall be conducted to determine the oxygen levels in the exhaust. In 

addition, the tests shall measure the fuel flow rate (CFH), the flue gas flow rate, 

and the turbine generating output in MW.

The test shall be conducted in accordance with AQMD approved test protocol. The 

protocol shall be submitted to the AQMD engineer no later than 45 days before the 

proposed test date and shall be approved by the AQMD before the test commences. The 

test protocol shall include the proposed operating conditions of the turbine 

during the tests, the identity of the testing lab, a statement from the testing lab 

certifying that it meets the criteria of Rule 304, and a description of all sampling 

and analytical procedures. 
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

The test shall be conducted when this equipment is operating at maximum, average, and 

minimum loads.

The test shall be conducted for compliance verification of the BACT VOC 2.0 ppmv 

limit.

For natural gas fired turbines only, VOC compliance shall be demonstrated as follows: 

a) Stack gas samples are extracted into Summa canisters maintaining a final canister 

pressure between 400-500 mm Hg absolute, b) Pressurization of canisters are done 

with zero gas analyzed/certified to contain less than 0.05 ppmv total hydrocarbon as 

carbon, and c) Analysis of canisters are per EPA Method TO-12 (with pre 

concentration) and temperature of canisters when extracting samples for analysis is 

not below 70 deg F.

The use of this alternative method for VOC compliance determination does not mean 

that it is more accurate than AQMD Method 25.3, nor does it mean that it may be 

used in lieu of AQMD Method 25.3 without prior approval except for the determination 

of compliance with the VOC BACT level of 2.0 ppmv calculated as carbon for natural 

gas fired turbines.

Because the VOC BACT level was set using data derived from various source test 

results, this alternate VOC compliance method provides a fair comparison and 

represents the best sampling and analysis technique for this purpose at this time. 

The test results shall be reported with two significant digits.

For the purpose of this condition, alternative test method may be allowed for each of 

the above pollutants upon concurrence of AQMD,EPA and CARB.

[Rule 1303(a)(1) – BACT, Rule 1303(b)(2) – Offset, Rule 2005, Reg 1703(a-PSD-BACT]

Each Turbine

D29.2 The operator shall conduct source test(s) for the pollutant(s) identified below.

Pollutant to be 

tested

Required Test 

Method(s)

Averaging Time Test Location

NH3 emissions District method 

207.1 and 5.3 or 

EPA method 17

1 hour Outlet of the SCR

The test shall be conducted and the results submitted to the District within 45 days 

after the test date. The AQMD shall be notified of the date and time of the 

test at least 7 days prior to the test.

The test shall be conducted at least quarterly during the first twelve months of 

operation and at least annually thereafter. The NOx concentration, as determined by 

the CEMS, shall be simultaneously recorded during the ammonia slip test. If the 

CEMS is inoperable, a test shall be conducted to determine the NOx emissions using 

District Method 100.1 measured over a 60 minute averaging time period.

If the turbine is not in operation during one quarter, then no testing is required

during that quarter

The test shall be conducted to demonstrate compliance with the Rule 1303 BACT

concentration limit 

[Rule 1303(a)(1) – BACT]

Each Turbine

D29.3 The operator shall conduct source test(s) for the pollutant(s) identified below.

Pollutant to be 

tested

Required Test 

Method(s)

Averaging Time Test Location
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

SOX emissions AQMD Laboratory 

Method 307-91

Not applicable Fuel Sample

VOC emissions District Method 

25.3

1 hour Outlet of the SCR

PM10 emissions District Method 5 4 hours Outlet of the SCR

The test shall be conducted at least once every three years.

The test shall be conducted to determine the oxygen levels in the exhaust. In 

addition, the tests shall measure the fuel flow rate (CFH), the flue gas flow rate, 

and the turbine generating output in MW.

The test shall be conducted in accordance with AQMD approved test protocol. The 

protocol shall be submitted to the AQMD engineer no later than 45 days before the 

proposed test date and shall be approved by the AQMD before the test commences. The 

test protocol shall include the proposed operating conditions of the turbine during 

the tests, the identity of the testing lab, a statement from the testing lab 

certifying that it meets the criteria of Rule 304, and a description of all sampling 

and analytical procedures. 

The test shall be conducted when this equipment is operating at maximum, average, and 

minimum load.

The test shall be conducted for compliance verification of the BACT VOC 2.0 ppmv 

limit.

For natural gas fired turbines only, VOC compliance shall be demonstrated as follows: 

a) Stack gas samples are extracted into Summa canisters maintaining a final canister 

pressure between 400-500 mm Hg absolute, b) Pressurization of canisters are done 

with zero gas analyzed/certified to contain less than 0.05 ppmv total hydrocarbon as 

carbon, and c) Analysis of canisters are per EPA Method TO-12 (with pre 

concentration) and temperature of canisters when extracting samples for 

analysis is not below 70 deg F.

The use of this alternative method for VOC compliance determination does not mean 

that it is more accurate than AQMD Method 25.3, nor does it mean that it may be used 

in lieu of AQMD Method 25.3 without prior approval except for the determination of 

compliance with the VOC BACT level of 2.0 ppmv calculated as carbon for natural gas 

fired turbines.

Because the VOC BACT level was set using data derived from various source test 

results, this alternate VOC compliance method provides a fair comparison and 

represents the best sampling and analysis technique for this purpose at this time. 

The test results shall be reported with two significant digits.

For the purpose of this condition, alternative test method may be allowed for each of 

the above pollutants upon concurrence of AQMD, EPA and CARB.

[Rule 1303(a)(1) – BACT, Rule 1303(b)(2) – Offset, Reg 1703(a-PSD-BACT]

Each Turbine

D82.1 The operator shall install and maintain a CEMS to measure the following parameters:

CO concentration in ppmv

Concentrations shall be corrected to 15 percent oxygen on a dry basis

The CEMS shall be installed and operated no later than 90 days after initial startup of the turbine, and in accordance with an approved AQMD Rule 218 CEMS plan 

application. The operator shall not install the CEMS prior to receiving initial 
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

approval from AQMD. Within two weeks of the turbine start-up, the operator shall 

provide written notification to the District of the exact date of start-up.

The CEMS shall be installed and operated to measure CO concentrations over a 15 

minute averaging time period.

The CEMS would convert the actual CO concentrations to mass emission rates (lbs/hr) 

using the equation below and record the hourly emission rates on a continuous 

basis. 

CO Emission Rate, lbs/hr = K Cco Fd[20.9% - %O2 d)][(Qg * HHV)/106], where

K = 7.267 *10-8 (lb/scf)/ppm

Cco = Average of four consecutive 15 min. ave. CO concentration, ppm

Fd = 8710 dscf/MMBTU natural gas

%O2 d = Hourly ave. % by vol. O2 dry, corresponding to Cco

Qg = Fuel gas usage during the hour, scf/hr

HHV = Gross high heating value of fuel gas, BTU/scf

[Rule 1303(a)(1) – BACT, Rule 218]

Each Turbine

D82.2 The operator shall install and maintain a CEMS to measure the following 

parameters:

NOx concentration in ppmv

Concentrations shall be corrected to 15 percent oxygen on a dry basis.

The CEMS shall be installed and operating no later than 90 days after initial startup of the turbine and shall comply with the requirements of Rule 2012. During the 

interim period between the initial start-up and the provisional certification 

date of the CEMS, the operator shall comply with the monitoring requirements of 

Rule 2012(h)(2) and 2012(h)(3). Within two weeks of the turbine start-up date, the 

operator shall provide written notification to the District of the exact date of 

start-up.

The CEMS shall be installed and operating (for BACT purposes only) no later than 90 

days after initial start up of the turbine.

[Rule 2005; Rule 2012, Rule 1703]

Each Turbine

E193.1 The operator shall upon completion of construction, operate and maintain this 

equipment according to the following specifications:

In accordance with all mitigation measures stipulated in the final California Energy 

Commission decision for the 07-AFC-3 project.

[CEQA]

H23.1 This equipment is subject to the applicable requirements of the following Rules or 

Regulations:

Contaminant Rule Rule/Subpart

NOx 40CFR60, SUBPART KKKK

SOX 40CFR60, SUBPART KKKK
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

[40CFR 60 SUBPART KKKK]

Each turbine

I296.1 This equipment shall not be operated unless the operator demonstrates to the 

Executive Officer that the facility holds sufficient RTCs to offset the prorated 

annual emissions increase for the first compliance year of operation. In addition, 

this equipment shall not be operated unless the operator demonstrates to the 

Executive Officer that, at the commencement of each compliance year after the 

first compliance year of operation, the facility holds sufficient RTCs in an 

amount equal to the annual emission increase.

To comply with this condition, the operator shall prior to the 1st compliance year 

hold a minimum NOx RTCs of 35838 lbs/yr. This condition shall apply during the 1st

12 months of operation, commencing with the initial operation of the gas turbine.

To comply with this condition, the operator shall, prior to the beginning of all 

years subsequent to the 1st compliance year, hold a minimum of 30,110 lbs/yr of NOx 

RTCs for operation of the gas turbine. 

In accordance with Rule 2005(f), unused RTC’s may be sold only during the 

reconciliation period for the fourth quarter of the applicable compliance year 

inclusive of the 1st compliance year.

This condition shall apply to each turbine individually.

[Rule 2005]

Turbines 1 though 8

K40.1 The operator shall provide to the District a source test report in accordance with the 

following specifications:

Source test results shall be submitted to the District no later than 60 days after 

the source test was conducted.

Emission data shall be expressed in terms of concentration (ppmv) corrected to 15 

percent oxygen (dry basis), mass rate (lb/hr), and lb/MMCF. In addition, solid PM 

emissions, if required to be tested, shall also be reported in terms of 

grains/DSCF.

All exhaust flow rate shall be expressed in terms of dry standard cubic feet per 

minute (DSCFM) and dry actual cubic feet per minute (DACFM).

All moisture concentration shall be expressed in terms of percent corrected to 15 

percent oxygen.

Source test results shall also include the oxygen levels in the exhaust, fuel flow 

rate (CFH),heating content of the fuel, the flue gas temperature, and the generator 

power output (MW) under which the test was conducted.

[Rule 1303(a)(1) – BACT, Rule 1303(b)(2) – Offset, Rule 1702(a)(2)-PSD-BACT, Rule 

2005]

Each Turbine

K67.1 The operator shall keep records in a manner approved by the District, for the 

following parameter(s) or item(s):

Natural gas fuel use after CEMS certification

Natural gas fuel use during the commissioning period

Natural gas fuel use after the commissioning period and prior to CEMS 

certification

[Rule 2012]

Each Turbine

(SCR/CO Catalyst)
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

A195.4 The 5 ppmv NH3 emission limit is averaged over 60 minutes at 15% O2, dry basis. The 

operator shall calculate and continuously record the NH3 slip concentration using the 

following:

NH3 (ppmv) = [a–b*c/1EE+06]*1EE+06/b

where,

a = NH3 injection rate (lbs/hr)/17(lb/lb-mol)

b = dry exhaust gas flow rate (scf/hr)/385.3 scf/lb-mol)

c = change in measured NOx across the SCR (ppmvd at 15% O2)

The operator shall install and maintain a NOx analyzer to measure the SCR inlet 

NOx ppmv accurate to plus or minus 5 percent calibrated at least once every twelve 

months.

The NOx analyzer shall be installed and operated within 90 days of initial startup.

The operator shall use the above described method or another alternative method 

approved by the Executive Officer.

The ammonia slip calculation procedures described above shall not be used for 

compliance determination or emission information without corroborative data using 

an approved reference method for the determination of ammonia.

[Rule 1303(a)(1) – BACT]

D12.2 The operator shall install and maintain a(n) flow meter to accurately indicate the 

flow rate of the total hourly throughput of injected ammonia.

The operator shall also install and maintain a device to continuously record the 

parameter being measured.

The measuring device or gauge shall be accurate to within plus or minus 5 percent. 

It shall be calibrated once every twelve months. The records shall be kept on site 

and made available to AQMD personnel upon request

The ammonia injection system shall be placed in full operation as soon as the 

minimum temperature is reached. The minimum temperature is listed as 540 degrees F.

at the inlet to the SCR reactor.

[Rule 1303(a)(1) – BACT, Rule 2005]

D12.3 The operator shall install and maintain a(n) temperature gauge to accurately indicate 

the temperature in the exhaust at the inlet to the SCR reactor.

The operator shall also install and maintain a device to continuously record the 

parameter being measured.

The measuring device or gauge shall be accurate to within plus or minus 5 percent. 

It shall be calibrated once every twelve months.

The catalyst temperature range shall be remain between 740 degree F and 840 degree 

F.

The catalyst inlet temperature shall not exceed 840 degrees F.

The temperature range requirement of this condition does not apply during start-up 

operations of the turbine not to exceed 25 minutes per start-up. 

For this condition start-up shall be defined as the start up process to bring the 

turbine in full successful operations. If during start-up the process is aborted 

and the start-up is restarted, then the start-up and restart is defined as "one 

start-up”. In this case the start-up time shall not exceed one hour.

[Rule 1303(a)(1) – BACT, Rule 2005, 1702 (a)(2)-PSD-BACT]

D12.4 The operator shall install and maintain a(n) pressure gauge to accurately indicate the 

differential pressure across the SCR catalyst bed in inches of water column.

The operator shall also install and maintain a device to continuously record the 

parameter being measured.
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

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ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

The measuring device or gauge shall be accurate to within plus or minus 5 percent. 

It shall be calibrated once every twelve months.

The pressure drop across the catalyst shall not exceed 12 inches water column

[Rule 1303(a)(1) – BACT, Rule 2005, Rule 1702 (a)(2)-PSD-BACT]

E179.1 For the purpose of the following condition number(s), continuously record shall be 

defined as recording at least once every hour and shall be calculated based upon the 

average of the continuous monitoring for that hour.

Condition Number D12.2

Condition Number D12.3

[Rule 1303(a)(1) – BACT, Rule 2005-BACT, Rule 1702(a)(2)-PSD-BACT]

E179.2 For the purpose of the following condition numbers, continuously record shall be 

defined as measuring at least once every month and shall be calculated based upon the 

average of the continuous monitoring for that month.

Condition Number: D12.4

[Rule 1303(a)(1) – BACT, Rule 1702(a)(2)-PSD-BACT]

E193.1 The operator shall upon completion of construction, operate and maintain this 

equipment according to the following specifications:

In accordance with all mitigation measures stipulated in the final California 

Energy Commission decision for the 07-AFC-3 project.

[CEQA]

(Ammonia Storage Tank)

C157.1 The operator shall install and maintain a pressure relief valve with a minimum 

pressure set at 25 psig.

[Rule 1303(a)(1) – BACT]

E144.1 The operator shall vent this equipment, during filling, only to the vessel from which 

it is being filled.. 

[Rule 1303(a)(1) – BACT]

E193.1 The operator shall upon completion of construction, operate and maintain this 

equipment according to the following specifications:

In accordance with all mitigation measures stipulated in the final California 

Energy Commission decision for the 07-AFC-3 project.

[CEQA]

K67.2 The operator shall keep records in a manner approved by the Executive Officer, for the 

following parameter(s) or item(s):

The operator shall document an inspection each time the tank is filled to insure the 

vapor recovery equipment is consistently and properly used

[Rule 1303(a)(1) – BACT]

(Emergency Fire Pump)

C1.4 The operator shall limit the operating time to no more than 50 hours in any one year.

For the purposes of this condition, the operating time is inclusive of time 

allotted for maintenance and testing

[Rule 1110.2, Rule 1304,Rule 1470, Rule 2012]

D12.5 The operator shall install and maintain a(n) non-resettable elapsed meter to accurately 

indicate the elapsed operating time of the engine.
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 50

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

[Rule 1304, Rule 1470, Rule 2012]

B61.2 The operator shall only use diesel fuel containing the following specified compounds:

COMPOUND Range PPM BY WEIGHT

Sulfur Less than or equal to 15

The operator shall maintain a copy of the MSDS on site

[Rule 431.2]

E193.1 The operator shall upon completion of construction, operate and maintain this 

equipment according to the following specifications:

In accordance with all mitigation measures stipulated in the final California 

Energy Commission decision for the 07-AFC-3 project.

I296.3 This equipment shall not be operated unless the operator demonstrates to the Executive 

Officer the facility holds sufficient RTCs to offset the prorated annual emissions 

increase for the first compliance year of operation. In addition, this equipment 

shall not be operated unless the operator demonstrates to the Executive Officer that, at 

the commencement of each compliance year after the first compliance year of 

operation, the facility holds sufficient RTCs in an amount equal to the annual emissions 

increase.

To comply with this condition, the operator shall, prior to each compliance year 

hold a minimum NOx RTCs of 77 lbs. 

In accordance with Rule 2005(f), unused RTCs may be sold only during the 

reconciliation period for the fourth quarter of the applicable compliance year 

inclusive of the 1st compliance year.

[Rule 2005]

K67.3 The operator shall keep records in a manner approved by the Executive Officer, for the 

following parameter(s) or item(s):

Manual and automatic operation and shall list all engine operations in each of the 

following areas:

Emergency use hours of operation

Maintenance and testing hours

Other operating hours (describe the reason for operation)

In addition, each time the engine is started manually, the log shall include the date of 

operation and the timer reading in hours at the beginning and end of operation. the log 

shall be kept for a minimum of five calendar years prior to the current year and made 

available to district personnel upon request. the total hours of operation for the 

previous calendar year shall be recorded sometime during the first 15 days of January of 

each year.

[Rule 1110.2, Rule 1470]

(Section D; Device E54)

K67.5 The operator shall keep records, in a manner approved by the District, for 

the following parameter(s) or item(s):
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 51

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

For architectural applications where thinners, reducers, or other VOC 

containing materials are added, maintain daily records for each coating 

consisting of (a) coating type, (b) VOC content as applied in grams per 

liter (g/l) of materials used for low-solids coatings, (c) VOC content 

as applied in g/l of coating, less water and exempt solvent, for other 

coatings.

For architectural applications where no thinners, reducers, or other 

VOC containing materials are added, maintain semi-annual records 

consisting of (a) coating type, (b) VOC content as applied in grams per 

liter (g/l) of materials used for low-solids coatings, (c) VOC content 

as applied in g/l of coating, less water and exempt solvent, for other 

coatings.
SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT PAGES PAGE 

52 52

ENGINEERING AND COMPLIANCE DIVISION APPLICATION NO. DATE 

Master File 02-28-2010

ENGINEERING ANALYSIS / EVALUATION PROCESSED BY:

Roy Olivares

REVIEWED BY:

CPV SENTINEL ENERGY PROJECT 

List of Appendices

1. Appendix A – LMS100PA Hourly Emissions

 Normal Operations

 Start-up Emissions

 Shutdown Emissions

2. Appendix B – LMS100PA Monthly Emissions

 Commissioning year

 Non-Commissioning year

 30-Day Averages (Commissioning year)

 30-Day Averages (Non-commissioning year)

3. Appendix C – LMS100PA Annual Emissions

 Commissioning year

 Non-commissioning year

4. Appendix D – Emergency Fire Pump Emissions

5. Appendix E – Commissioning Emissions

6. Appendix F – NOx RTC calculations

7. Appendix G – Interim Period Emission Factors

8. Appendix H – Interim Period Emission Factors

9. Appendix I – TAC Emissions

10. Appendix J – Additional Fees calculations

11. Appendix K- Uncontrolled VOC emissions for each turbine

12. Appendix L- AB1318 Mitigation fees and AB1318 Offset Report

13. Appendix M-Review of an Air Quality Analysis and a Health Risk Assessment for 

Amendment to Permit to Construct/Permit to Operate Application for the CPV 

Sentinel Energy Project (A/N’s 472139 thru 472158)

14. Appendix N-Offset Evaluation Section
152707

DRAFT

Date: March 02, 2010

Facility ID:

Revision #:

FACILITY PERMIT TO OPERATE

Title Page

NOTICE

IN ACCORDANCE WITH RULE 206, THIS PERMIT TO OPERATE OR A COPY THEREOF 

MUST BE KEPT AT THE LOCATION FOR WHICH IT IS ISSUED.

THIS PERMIT DOES NOT AUTHORIZE THE EMISSION OF AIR CONTAMINANTS IN EXCESS 

OF THOSE ALLOWED BY DIVISION 26 OF THE HEALTH AND SAFETY CODE OF THE 

STATE OF CALIFORNIA OR THE RULES OF THE SOUTH COAST AIR QUALITY 

MANAGEMENT DISTRICT. THIS PERMIT SHALL NOT BE CONSTRUED AS PERMISSION TO 

VIOLATE EXISTING LAWS, ORDINANCES, REGULATIONS OR STATUTES OF ANY OTHER 

FEDERAL, STATE OR LOCAL GOVERNMENTAL AGENCIES.

CPV SENTINEL LLC

62575 POWER LINE RD 

DESERT HOT SPRINGS, CA 92240 

 By___________________

Mohsen Nazemi, P.E.

Deputy Executive Officer

Engineering & Compliance

Barry R. Wallerstein, D. Env.

EXECUTIVE OFFICER
FACILITY PERMIT TO OPERATE

TABLE OF CONTENTS

CPV SENTINEL LLC

Table of Content 

DRAFT

152707

Date: March 02, 2010

Facility ID:

Revision #:

Section Description Revision # Date Issued

A Facility Information DRAFT 03/02/2010

B RECLAIM Annual Emission Allocation DRAFT 03/02/2010

C Facility Plot Plan TO BE DEVELOPED

Facility Description and Equipment DRAFT 03/02/2010

Specific Conditions

D

E Administrative Conditions DRAFT 03/02/2010

RECLAIM Monitoring and Source Testing DRAFT 03/02/2010

Requirements

F

Recordkeeping and Reporting DRAFT 03/02/2010

Requirements for RECLAIM Sources

G

Permit To Construct and Temporary DRAFT 03/02/2010

Permit to Operate

H

I Compliance Plans & Schedules DRAFT 03/02/2010

J Air Toxics DRAFT 03/02/2010

K Title V Administration DRAFT 03/02/2010

Appendix

NOx and SOx Emitting Equipment Exempt DRAFT 03/02/2010

From Written Permit Pursuant to Rule 

219

A

B Rule Emission Limits DRAFT 03/02/2010
SECTION A: FACILITY INFORMATION

Page:

CPV SENTINEL LLC

Date:

Facility ID:

Section A

FACILITY PERMIT TO OPERATE

1

152707

DRAFT

March 02, 2010

Revision #:

EQUIPMENT LOCATION:

LEGAL OWNER &/OR OPERATOR:

LEGAL OPERATOR (if different than owner):

MAILING ADDRESS:

RESPONSIBLE OFFICIAL:

TITLE:

TELEPHONE NUMBER:

CONTACT PERSON:

TITLE:

CPV SENTINEL LLC

MARK TURNER

PROJECT MANAGER

(415) 293-1463

MARK TURNER

PROJECT MANAGER

TELEPHONE NUMBER: (415) 293-1463

62575 POWER LINE RD 

DESERT HOT SPRINGS, CA 92240

55 SECOND ST STE 525

SAN FRANCISCO, CA 94105

INITIAL TITLE V PERMIT ISSUED: March 02, 2010

TITLE V PERMIT EXPIRATION DATE: March 01, 2015

TITLE V RECLAIM

NOx:

SOx:

CYCLE:

ZONE:

YES

NO

0

COASTAL

YES
CPV SENTINEL LLC

FACILITY PERMIT TO OPERATE

DRAFT

March 02, 2010

Page:

Date:

Facility ID:

Section B 1

152707

Revision #:

SECTION B: RECLAIM ANNUAL EMISSION ALLOCATION

NOT APPLICABLE
CPV SENTINEL LLC

SECTION C: FACILITY PLOT PLAN

FACILITY PERMIT TO OPERATE

DRAFT

Date: March 02, 2010

Facility ID: 152707

Revision #:

Section C Page: 1

(TO BE DEVELOPED)
March 02, 2010

DRAFT

CPV SENTINEL LLC

SECTION D: FACILITY DESCRIPTION AND EQUIPMENT SPECIFIC CONDITIONS

FACILITY PERMIT TO OPERATE

Date:

Facility ID: 152707

Revision #:

Section D Page: 1

The operator shall comply with the terms and conditions set forth below:

Emissions *

 And Requirements

RECLAIM 

Source Type/ 

Monitoring 

Unit

Equipment Connected 

To

ID 

No.

Conditions

Process 3: RULE 219 EXEMPT EQUIPMENT SUBJECT TO SOURCE SPECIFIC RULES

RULE 219 EXEMPT EQUIPMENT, 

COATING EQUIPMENT, PORTABLE, 

ARCHITECTURAL COATINGS

E54 VOC: (9) [RULE 1113, 11-8-1996;

RULE 1113, 7-13-2007; RULE 

1171, 11-7-2003; RULE 1171, 

2-1-2008]

C3 K67.5

RULE 219 EXEMPT EQUIPMENT, 

EXEMPT HAND WIPING 

OPERATIONS

E55 VOC: (9) [RULE 1171, 11-7-2003;

RULE 1171, 2-1-2008]

C3

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
SECTION D: DEVICE ID INDEX

CPV SENTINEL LLC

FACILITY PERMIT TO OPERATE

DRAFT

March 02, 2010

Page:

152707

Date:

Facility ID:

Section D

Revision #:

 2 

The following sub-section provides an index

to the devices that make up the facility

description sorted by device ID.
CPV SENTINEL LLC

FACILITY PERMIT TO OPERATE

DRAFT

March 02, 2010

Page:

152707

Date:

Facility ID:

Section D

Revision #:

 3 

SECTION D: DEVICE ID INDEX

Device Index For Section D

Device ID Section D Page No. Process System

E54 1 3 0

E55 1 3 0
SECTION D: FACILITY DESCRIPTION AND EQUIPMENT SPECIFIC CONDITIONS

The operator shall comply with the terms and conditions set forth below:

CPV SENTINEL LLC

FACILITY PERMIT TO OPERATE

DRAFT

March 02, 2010

Page:

152707

Date:

Facility ID:

Section D

Revision #:

 4 

FACILITY CONDITIONS

Except for open abrasive blasting operations, the operator shall not discharge into the 

atmosphere from any single source of emissions whatsoever any air contaminant for a 

period or periods aggregating more than three minutes in any one hour which is:

(a) As dark or darker in shade as that designated No.1 on the Ringelmann Chart, as 

published by the United States Bureau of Mines; or

(b) Of such opacity as to obscure an observer's view to a degree equal to or greater than 

does smoke described in subparagraph (a) of this condition.

F9.1

[RULE 401, 3-2-1984; RULE 401, 11-9-2001]

The operator shall not purchase diesel fuel containing sulfur compounds in excess of 15 

ppm by weight as supplied by the supplier.

F14.1

The operator shall maintain a copy of the MSDS on site

[RULE 431.2, 5-4-1990; RULE 431.2, 9-15-2000]

DEVICE CONDITIONS

K. Record Keeping/Reporting

The operator shall keep records, in a manner approved by the District, for the following 

parameter(s) or item(s):

K67.5
SECTION D: FACILITY DESCRIPTION AND EQUIPMENT SPECIFIC CONDITIONS

The operator shall comply with the terms and conditions set forth below:

CPV SENTINEL LLC

FACILITY PERMIT TO OPERATE

DRAFT

March 02, 2010

Page:

152707

Date:

Facility ID:

Section D

Revision #:

 5 

For architectural applications where no thinners, reducers, or other VOC containing 

materials are added, maintain semi-annual records for all coating consisting of (a) 

coating type, (b) VOC content as supplied in grams per liter (g/l) of materials for 

low-solids coatings, (c) VOC content as supplied in g/l of coating, less water and 

exempt solvent, for other coatings.

For architectural applications where thinners, reducers, or other VOC containing 

materials are added, maintain daily records for each coating consisting of (a) coating 

type, (b) VOC content as applied in grams per liter (g/l) of materials used for 

low-solids coatings, (c) VOC content as applied in g/l of coating, less water and 

exempt solvent, for other coatings.

[RULE 1113, 11-8-1996; RULE 1113, 7-13-2007]

[Devices subject to this condition : E54]
FACILITY PERMIT TO OPERATE

CPV SENTINEL LLC

SECTION E: ADMINISTRATIVE CONDITIONS

The operating conditions in this section shall apply to all permitted equipment at this 

facility unless superseded by condition(s) listed elsewhere in this permit.

DRAFT

March 02, 2010

Page: 1

152707

Date:

Facility ID:

Section E

Revision #:

1. The permit shall remain effective unless this permit is suspended, revoked, 

modified, reissued, denied, or it is expired for nonpayment of permit processing or 

annual operating fees. [201, 203, 209, 301]

a. The permit must be renewed annually by paying annual operating fees, and the 

permit shall expire if annual operating fees are not paid pursuant to 

requirements of Rule 301(d). [301(d)]

b. The Permit to Construct listed in Section H shall expire one year from the 

Permit to Construct issuance date, unless a Permit to Construct extension has 

been granted by the Executive Officer or unless the equipment has been 

constructed and the operator has notified the Executive Officer prior to the 

operation of the equipment, in which case the Permit to Construct serves as a 

temporary Permit to Operate. [202, 205]

c. The Title V permit shall expire as specified under Section K of the Title V 

permit. The permit expiration date of the Title V facility permit does not 

supercede the requirements of Rule 205. [205, 3004]

2. The operator shall maintain all equipment in such a manner that ensures proper 

operation of the equipment. [204]

3. This permit does not authorize the emissions of air contaminants in excess of those 

allowed by Division 26 of the Health and Safety Code of the State of California or 

the Rules and Regulations of the AQMD. This permit cannot be considered as 

permission to violate existing laws, ordinances, regulations, or statues of other 

governmental agencies. [204]

4. The operator shall not use equipment identified in this facility permit as being 

connected to air pollution control equipment unless they are so vented to the 

identified air pollution control equipment which is in full use and which has been 

included in this permit. [204]
FACILITY PERMIT TO OPERATE

CPV SENTINEL LLC

SECTION E: ADMINISTRATIVE CONDITIONS

DRAFT

March 02, 2010

Page: 2

152707

Date:

Facility ID:

Section E

Revision #:

5. The operator shall not use any equipment having air pollution control device(s) 

incorporated within the equipment unless the air pollution control device is in full 

operation. [204]

6. The operator shall maintain records to demonstrate compliance with rules or permit 

conditions that limit equipment operating parameters, or the type or quantity of 

material processed. These records shall be made available to AQMD personnel 

upon request and be maintained for at least five years. [204]

7. The operator shall maintain and operate all equipment to ensure compliance with 

all emission limits as specified in this facility permit. Compliance with emission 

limits shall be determined according to the following specifications, unless 

otherwise specified by AQMD rules or permit conditions: [204]

a. For internal combustion engines and gas turbines, measured concentrations shall 

be corrected to 15 percent stack-gas oxygen content on a dry basis and be 

averaged over a period of 15 consecutive minutes; [1110.2, 1134]

b. For other combustion devices, measured concentrations shall be corrected to 3 

percent stack-gas oxygen content on a dry basis and be averaged over a period 

of 15 consecutive minutes; [1146, 1146.1, 204]

c. For non-combustion sources, compliance with emission limits shall be 

determined and averaged over a period of 60 minutes; [204]

d. For the purpose of determining compliance with Rule 407, carbon monoxide 

(CO) shall be measured on a dry basis and be averaged over 15 consecutive 

minutes, and sulfur compounds which would exist as liquid or gas at standard 

conditions shall be calculated as sulfur dioxide (SO2) and be averaged over 15 

consecutive minutes; [407]

e. For the purpose of determining compliance with Rule 409, combustion 

contaminant emission measurements shall be corrected to 12 percent of carbon 

dioxide (CO2) at standard conditions and averaged over a minimum of 15 

consecutive minutes. [409]
FACILITY PERMIT TO OPERATE

CPV SENTINEL LLC

SECTION E: ADMINISTRATIVE CONDITIONS

DRAFT

March 02, 2010

Page: 3

152707

Date:

Facility ID:

Section E

Revision #:

f. For the purpose of determining compliance with Rule 475, combustion 

contaminant emission measurements shall be corrected to 3 percent of oxygen 

(O2) at standard conditions and averaged over 15 consecutive minutes or any 

other averaging time specified by the Executive Officer. [475]

8. The operator shall, when a source test is required by AQMD, provide a source test 

protocol to AQMD no later than 60 days before the proposed test date. The test 

shall not commence until the protocol is approved by AQMD. The test protocol 

shall contain the following information: [204, 304]

a. Brief description of the equipment tested.

b. Brief process description, including maximum and normal operating 

temperatures, pressures, throughput, etc.

c. Operating conditions under which the test will be performed.

d. Method of measuring operating parameters, such as fuel rate and process 

weight. Process schematic diagram showing the ports and sampling locations, 

including the dimensions of the ducts and stacks at the sampling locations, and 

distances of flow disturbances, (e.g. elbows, tees, fans, dampers) from the 

sampling locations (upstream and downstream).

e. Brief description of sampling and analytical methods used to measure each 

pollutant, temperature, flow rates, and moisture.

f. Description of calibration and quality assurance procedures.

g. Determination that the testing laboratory qualifies as an "independent testing 

laboratory" under Rule 304 (conflict of interest).

9. The operator shall submit a report no later than 60 days after conducting a source 

test, unless otherwise required by AQMD rules or equipment-specific conditions. 

The report shall contain the following information: [204]

a. The results of the source test.
FACILITY PERMIT TO OPERATE

CPV SENTINEL LLC

SECTION E: ADMINISTRATIVE CONDITIONS

DRAFT

March 02, 2010

Page: 4

152707

Date:

Facility ID:

Section E

Revision #:

b. Brief description of the equipment tested.

c. Operating conditions under which the test was performed.

d. Method of measuring operating parameters, such as fuel rate and process 

weight. Process schematic diagram showing the ports and sampling locations, 

including the dimensions of the ducts and stacks at the sampling locations, and 

distances of flow disturbances, (e.g. elbows, tees, fans, dampers) from the 

sampling locations (upstream and downstream).

e. Field and laboratory data forms, strip charts and analyses.

f. Calculations for volumetric flow rates, emission rates, control efficiency, and 

overall control efficiency.

10. The operator shall, when a source test is required, provide and maintain facilities 

for sampling and testing. These facilities shall comply with the requirements of 

AQMD Source Test Method 1.1 and 1.2. [217]

11. Whenever required to submit a written report, notification or other submittal to the 

Executive Officer, AQMD, or the District, the operator shall mail or deliver the 

material to: Deputy Executive Officer, Engineering and Compliance, AQMD, 

21865 E. Copley Drive, Diamond Bar, CA 91765-4182. [204]
SECTION F: RECLAIM MONITORING AND SOURCE TESTING REQUIREMENTS

FACILITY PERMIT TO OPERATE

CPV SENTINEL LLC

DRAFT

March 02, 2010

152707

Page: 1

Date:

Facility ID:

Section F

Revision #:

NOT APPLICABLE
SECTION G: RECORDKEEPING AND REPORTING REQUIREMENTS FOR

FACILITY PERMIT TO OPERATE

CPV SENTINEL LLC

DRAFT

March 02, 2010

152707

Page: 1

Date:

Facility ID:

Section G

Revision #:

RECLAIM SOURCES

NOT APPLICABLE
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 1

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

System 1: GAS TURBINES, POWER GENERATION

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 2

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

GAS TURBINE, CTG-1, NATURAL 

GAS, GENERAL ELECTRIC, MODEL 

LMS100PA, SIMPLE CYCLE, 891.7 

MMBTU/HR AT 72 DEGREES F, 

WITH WATER INJECTION WITH

A/N: 

NOX: MAJOR 

SOURCE**

D1 CO: 4 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988]; CO: 

2000 PPMV NATURAL GAS 

(5) [RULE 407, 4-2-1982]; 

NOX: 2.5 PPMV NATURAL 

GAS (4) [RULE 1703 - PSD 

Analysis, 10-7-1988; RULE 

2005, 4-20-2001]; NOX: 12.26 

LBS/MMSCF (1) [RULE 

2012, 5-6-2005]; NOX: 15 

PPMV NATURAL GAS (8) 

[40CFR 60 Subpart KKKK, 

7-6-2006]; NOX: 19 

LBS/MMSCF NATURAL 

GAS (1) [RULE 2012, 

5-6-2005]; PM10: 0.01 

GRAINS/SCF NATURAL 

GAS (5A) [RULE 475, 

10-8-1976; RULE 475, 

8-7-1978]; PM10: 0.1 

GRAINS/SCF NATURAL 

GAS (5) [RULE 409, 

8-7-1981]; PM10: 11 LBS/HR 

NATURAL GAS (5B) [RULE 

475, 10-8-1976; RULE 475, 

8-7-1978]; SO2: (9) [40CFR 

72 - Acid Rain Provisions, 

11-24-1997]; SOX: 0.06 

LBS/MMBTU NATURAL 

GAS (8) [40CFR 60 Subpart 

KKKK, 7-6-2006]; VOC: 2 

PPMV NATURAL GAS (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

C3 A63.1, A63.2, 

A99.1, A99.3, 

A99.5, A99.7, 

A99.9, 

A195.1, 

A195.2, 

A195.3, 

A327.1, 

A433.1, 

B61.1, C1.1, 

C1.3, C1.6, 

D12.1, D29.1, 

D29.2, D29.3, 

D82.1, D82.2, 

E193.1, H23.1, 

I296.1, K40.1, 

K67.1

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 3

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

-BACT, 12-6-2002]

GENERATOR, 103 MW

CO OXIDATION CATALYST, NO. 1, 

BASF, WITH 150 CUBIC FEET OF 

TOTAL CATALYST VOLUME.

A/N:

C3 D1 C4 E54 E55

SELECTIVE CATALYTIC 

REDUCTION, NO. 1, CORMETECH 

CHMT-2, 812 CU.FT.; WIDTH: 2 FT 

2 IN; HEIGHT: 4 FT 2 IN; LENGTH: 10 

FT 11 IN WITH

A/N: 

C4 NH3: 5 PPMV NATURAL 

GAS (4) [RULE 1303(a)(1)

-BACT, 5-10-1996; RULE 

1303(a)(1)-BACT, 12-6-2002]

C3 S6 A195.4, 

D12.2, D12.3, 

D12.4, E179.1, 

E179.2, 

E179.3, 

E193.1

AMMONIA INJECTION, GRID

STACK, NO. 1, HEIGHT: 90 FT ; 

DIAMETER: 13 FT 6 IN

A/N:

S6 C4

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 4

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

GAS TURBINE, CTG-2, NATURAL 

GAS, GENERAL ELECTRIC, MODEL 

LMS100PA, SIMPLE CYCLE, 861.7 

MMBTU/HR AT 72 DEGREES F, 

WITH WATER INJECTION WITH

A/N: 

NOX: MAJOR 

SOURCE**

D7 CO: 4 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988]; CO: 

2000 PPMV NATURAL GAS 

(5) [RULE 407, 4-2-1982]; 

NOX: 2.5 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988; RULE 

2005, 5-6-2005]; NOX: 12.26 

LBS/MMSCF (1) [RULE 

2012, 5-6-2005]; NOX: 15 

PPMV NATURAL GAS (8) 

[40CFR 60 Subpart KKKK, 

7-6-2006]; NOX: 19 

LBS/MMSCF NATURAL 

GAS (1) [RULE 2012, 

5-6-2005]; PM10: 0.01 

GRAINS/SCF NATURAL 

GAS (5A) [RULE 475, 

10-8-1976; RULE 475, 

8-7-1978]; PM10: 0.1 

GRAINS/SCF NATURAL 

GAS (5) [RULE 409, 

8-7-1981]; PM10: 11 LBS/HR 

NATURAL GAS (5B) [RULE 

475, 10-8-1976; RULE 475, 

8-7-1978]; SO2: (9) [40CFR 

72 - Acid Rain Provisions, 

11-24-1997]; SOX: 0.06 

LBS/MMBTU NATURAL 

GAS (8) [40CFR 60 Subpart 

KKKK, 7-6-2006]; VOC: 2 

PPMV NATURAL GAS (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

C9 A63.1, A63.2, 

A99.1, A99.3, 

A99.5, A99.7, 

A99.9, 

A195.1, 

A195.3, 

A327.1, 

A433.1, 

B61.1, C1.1, 

C1.3, C1.6, 

D12.1, D29.1, 

D29.2, D29.3, 

D82.1, D82.2, 

E193.1, 

I296.1, K40.1, 

K67.1

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 5

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

-BACT, 12-6-2002]

GENERATOR, 103 MW

CO OXIDATION CATALYST, NO. 2, 

BASF, WITH 150 CUBIC FEET OF 

TOTAL CATALYST VOLUME.

A/N:

C9 D7 C10

SELECTIVE CATALYTIC 

REDUCTION, NO. 2, CORMETECH 

CHMT-2, 812 CU.FT.; WIDTH: 2 FT 

2 IN; HEIGHT: 4 FT 2 IN; LENGTH: 10 

FT 11 IN WITH

A/N: 

C10 NH3: 5 PPMV NATURAL 

GAS (4) [RULE 1303(a)(1)

-BACT, 5-10-1996; RULE 

1303(a)(1)-BACT, 12-6-2002]

C9 S12 A195.4, 

D12.2, D12.3, 

D12.4, E179.1, 

E179.2, 

E179.3, 

E193.1

AMMONIA INJECTION, GRID

STACK, NO. 2, HEIGHT: 90 FT ; 

DIAMETER: 13 FT 6 IN

A/N:

S12 C10

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 6

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

GAS TURBINE, GTG 3, NATURAL 

GAS, GENERAL ELECTRIC, MODEL 

LMS100PA, SIMPLE CYCLE, 891.7 

MMBTU/HR AT 72 DEGREES F, 

WITH WATER INJECTION WITH

A/N: 

NOX: MAJOR 

SOURCE**

D13 CO: 4 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988]; CO: 

20000 PPMV NATURAL 

GAS (5) [RULE 407, 

4-2-1982]; NOX: 2.5 PPMV 

NATURAL GAS (4) [RULE 

1703(a)(2) - PSD-BACT, 

10-7-1988; RULE 2005, 

5-6-2005]; NOX: 12.26 

LBS/MMSCF NATURAL 

GAS (1) [RULE 2012, 

5-6-2005]; NOX: 15 PPMV 

NATURAL GAS (8) [40CFR 

60 Subpart KKKK, 7-6-2006]; 

NOX: 19 LBS/MMSCF (1) 

[RULE 2012, 5-6-2005]; 

PM10: 0.01 GRAINS/SCF 

NATURAL GAS (5A) [RULE 

475, 10-8-1976; RULE 475, 

8-7-1978]; PM10: 0.1 

GRAINS/SCF NATURAL 

GAS (5) [RULE 409, 

8-7-1981]; SO2: (8) [40CFR 

72 - Acid Rain Provisions, 

11-24-1997]; SOX: 0.06 

LBS/MMSCF NATURAL 

GAS (8) [40CFR 60 Subpart 

KKKK, 7-6-2006]; VOC: 2 

PPMV NATURAL GAS (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

-BACT, 12-6-2002]

C15 A63.1, A63.2, 

A99.1, A99.3, 

A99.5, A99.7, 

A99.9, 

A195.1, 

A195.2, 

A195.3, 

A327.1, 

A433.1, 

B61.1, C1.1, 

C1.3, C1.6, 

D12.1, D29.1, 

D29.2, D29.3, 

D82.1, D82.2, 

E193.1, H23.1, 

I296.1, K40.1, 

K67.1

GENERATOR, 103 MW

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 7

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

CO OXIDATION CATALYST, NO. 3, 

BASF, WITH 150 CUBIC FEET OF 

TOTAL CATALYST VOLUME.

A/N:

C15 D13 C16

SELECTIVE CATALYTIC 

REDUCTION, NO.3, CORMETECH 

CHMT-2, 812 CU.FT.; WIDTH: 2 FT 

2 IN; HEIGHT: 4 FT 2 IN; LENGTH: 10 

FT 11 IN WITH

A/N: 

C16 NH3: 5 PPMV NATURAL 

GAS (4) [RULE 1303(a)(1)

-BACT, 5-10-1996; RULE 

1303(a)(1)-BACT, 12-6-2002]

C15 S18 A195.4, 

D12.2, D12.3, 

D12.4, E179.1, 

E179.2, 

E179.3, 

E193.1

AMMONIA INJECTION, GRID C28

STACK, NO. 3, HEIGHT: 90 FT ; 

DIAMETER: 13 FT 6 IN

A/N:

S18 C16

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 8

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

GAS TURBINE, GTG 4, NATURAL 

GAS, GENERAL ELECTRIC, MODEL 

LMS100PA, SIMPLE CYCLE, 891.7 

MMBTU/HR AT 72 DEGREES F, 

WITH WATER INJECTION WITH

A/N: 

NOX: MAJOR 

SOURCE**

D19 CO: 4 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988]; CO: 

2000 PPMV NATURAL GAS 

(5) [RULE 409, 8-7-1981]; 

NOX: 2.5 PPMV (4) [RULE 

1703(a)(2) - PSD-BACT, 

10-7-1988; RULE 2005, 

5-6-2005]; NOX: 12.26 

LBS/MMSCF NATURAL 

GAS (1) [RULE 2012, 

5-6-2005]; NOX: 15 PPMV (8) 

[40CFR 60 Subpart KKKK, 

7-6-2006]; NOX: 19 

LBS/MMSCF (1) ; PM10: 

0.01 GRAINS/SCF 

NATURAL GAS (5B) [RULE 

475, 10-8-1976; RULE 475, 

8-7-1978]; SO2: (9) [40CFR 

72 - Acid Rain Provisions, 

11-24-1997]; SOX: 0.06 

LBS/MMBTU NATURAL 

GAS (8) [40CFR 60 Subpart 

KKKK, 7-6-2006]; VOC: 2 

PPMV NATURAL GAS (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

-BACT, 12-6-2002]

C21 A63.1, A63.2, 

A99.1, A99.3, 

A99.5, A99.7, 

A99.9, 

A195.1, 

A195.2, 

A195.3, 

A433.1, 

B61.1, C1.1, 

C1.3, C1.6, 

D12.1, D29.1, 

D29.2, D29.3, 

D82.1, D82.2, 

E193.1, H23.1, 

I296.1, K67.1

GENERATOR, 103 MW

CO OXIDATION CATALYST, NO. 4, 

BASF, WITH 150 CUBIC FEET OF 

TOTAL CATALYST VOLUME.

A/N:

C21 D19 C22

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 9

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

SELECTIVE CATALYTIC 

REDUCTION, NO.4, CORMETCH 

CHMT-2, 812 CU.FT.; WIDTH: 2 FT 

2 IN; HEIGHT: 4 FT 2 IN; LENGTH: 10 

FT 11 IN WITH

A/N: 

C22 NH3: 5 PPMV NATURAL 

GAS (4) [RULE 1303(a)(1)

-BACT, 5-10-1996; RULE 

1303(a)(1)-BACT, 12-6-2002]

C21 S24 A195.4, 

D12.2, D12.3, 

D12.4, E179.1, 

E179.2, 

E179.3, 

E193.1

AMMONIA INJECTION, GRID

STACK, NO. 4, HEIGHT: 90 FT ; 

DIAMETER: 13 FT 6 IN

A/N:

S24 C22

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 10

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

GAS TURBINE, GTG 5, NATURAL 

GAS, GENERAL ELECTRIC, MODEL 

LMS100PA, SIMPLE CYCLE, 891.7 

MMBTU/HR AT 72 DEGREES F, 

WITH WATER INJECTION WITH

A/N: 

NOX: MAJOR 

SOURCE**

D25 CO: 4 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988]; CO: 

2000 PPMM NATURAL 

GAS (5) [RULE 407, 

4-2-1982]; NOX: 2.5 PPMV 

NATURAL GAS (4) [RULE 

1703(a)(2) - PSD-BACT, 

10-7-1988; RULE 2005, 

5-6-2005]; NOX: 12.26 

LBS/MMSCF NATURAL 

GAS (1) [RULE 2012, 

5-6-2005]; NOX: 15 PPMV 

NATURAL GAS (8) [40CFR 

60 Subpart KKKK, 7-6-2006]; 

NOX: 19 LBS/MMSCF (1) 

[RULE 2012, 5-6-2005]; 

PM10: 0.01 GRAINS/SCF 

NATURAL GAS (5C) [RULE 

475, 10-8-1976; RULE 475, 

8-7-1978]; SO2: (8) [40CFR 

72 - Acid Rain Provisions, 

11-24-1997]; SOX: 0.06 

LBS/MMBTU NATURAL 

GAS (8) [40CFR 60 Subpart 

KKKK, 7-6-2006]; VOC: 2 

PPMM NATURAL GAS (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

-BACT, 12-6-2002]

C27 A63.1, A63.2, 

A99.1, A99.3, 

A99.5, A99.7, 

A99.9, 

A195.1, 

A195.2, 

A195.3, 

A327.1, 

A433.1, 

B61.1, C1.1, 

C1.3, C1.6, 

D12.1, D29.1, 

D29.2, D29.3, 

D82.1, D82.2, 

E193.1, H23.1, 

I296.1, K40.1, 

K67.1

GENERATOR, 103 MW

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 11

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

CO OXIDATION CATALYST, NO.5, 

BASF, WITH 150 CUBIC FEET OF 

TOTAL CATALYST VOLUME.

A/N:

C27 D25 C28

SELECTIVE CATALYTIC 

REDUCTION, NO.5, CORMETECH 

CHMT-2, 812 CU.FT.; WIDTH: 2 FT 

2 IN; HEIGHT: 4 FT 2 IN; LENGTH: 10 

FT 11 IN WITH

A/N: 

C28 NH3: 5 PPMV NATURAL 

GAS (4) [RULE 1303(a)(1)

-BACT, 5-10-1996; RULE 

1303(a)(1)-BACT, 12-6-2002]

B17 C27 S30 A195.4, 

D12.2, D12.3, 

D12.4, E179.1, 

E179.2, 

E179.3, 

E193.1

AMMONIA INJECTION, GRID

STACK, NO. 5, HEIGHT: 90 FT ; 

DIAMETER: 13 FT 6 IN

A/N:

S30 C28

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 12

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

GAS TURBINE, GTG 6, NATURAL 

GAS, GENERAL ELECTRIC, MODEL 

LMS100PA, SIMPLE CYCLE, 891.7 

MMBTU/HR AT 72 DEGREES F, 

WITH WATER INJECTION WITH

A/N: 

NOX: MAJOR 

SOURCE**

D31 CO: 4 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988]; CO: 

2000 PPMV NATURAL GAS 

(5) [RULE 407, 4-2-1982]; 

NOX: 12.26 LBS/MMSCF 

NATURAL GAS (1) [RULE 

2012, 5-6-2005]; NOX: 15 

PPMV NATURAL GAS (8) 

[40CFR 60 Subpart KKKK, 

7-6-2006]; NOX: 19 

LBS/MMSCF (1) [RULE 

2012, 5-6-2005]; PM10: 0.01 

GRAINS/SCF NATURAL 

GAS (5A) [RULE 475, 

10-8-1976; RULE 475, 

8-7-1978]; PM10: 11 LBS/HR 

NATURAL GAS (5B) [RULE 

475, 10-8-1976; RULE 475, 

8-7-1978]; SO2: (9) [40CFR 

72 - Acid Rain Provisions, 

11-24-1997]; SOX: 0.06 

LBS/MMBTU NATURAL 

GAS (8) [40CFR 60 Subpart 

KKKK, 7-6-2006]; VOC: 2 

PPMV NATURAL GAS (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

-BACT, 12-6-2002]

C33 A63.2, A99.1, 

A99.3, A99.5, 

A99.7, A99.9, 

A195.1, 

A195.2, 

A195.3, 

A327.1, 

A433.1, 

B61.1, C1.1, 

C1.3, C1.6, 

D12.1, D29.1, 

D29.2, D29.3, 

D82.1, D82.2, 

E193.1, H23.1, 

I296.1, K40.1, 

K67.1

GENERATOR, 103 MW

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 13

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

CO OXIDATION CATALYST, NO. 6, 

BASF, WITH 150 CUBIC FEET OF 

TOTAL CATALYST VOLUME.

A/N:

C33 D31 C34

SELECTIVE CATALYTIC 

REDUCTION, NO. 6, CORMETECH 

CHMT-2, 812 CU.FT.; WIDTH: 2 FT 

2 IN; HEIGHT: 4 FT 2 IN; LENGTH: 10 

FT 11 IN WITH

A/N: 

C34 NH3: 5 PPMV NATURAL 

GAS (4) [RULE 1303(a)(1)

-BACT, 5-10-1996; RULE 

1303(a)(1)-BACT, 12-6-2002]

C33 S36 A195.4, 

D12.2, D12.3, 

D12.4, E179.1, 

E179.2, 

E179.3, 

E193.1

AMMONIA INJECTION, GRID

STACK, NO.6, HEIGHT: 90 FT ; 

DIAMETER: 13 FT 6 IN

A/N:

S36 C34

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 14

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

GAS TURBINE, GTG 7, NATURAL 

GAS, GENERAL ELECTRIC, MODEL 

LMS100PA, SIMPLE CYCLE, 891.7 

MMBTU/HR AT 72 DEGREES F, 

WITH WATER INJECTION WITH

A/N: 

NOX: MAJOR 

SOURCE**

D37 CO: 4 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988]; CO: 

2000 PPMV NATURAL GAS 

(5) [RULE 407, 4-2-1982]; 

NOX: 2.5 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988; RULE 

2005, 5-6-2005]; NOX: 12.26 

LBS/MMSCF NATURAL 

GAS (1) [RULE 2012, 

5-6-2005]; NOX: 15 PPMV 

NATURAL GAS (8) [40CFR 

60 Subpart KKKK, 7-6-2006]; 

NOX: 19 LBS/MMSCF (1) 

[RULE 2012, 5-6-2005]; 

PM10: 0.01 GRAINS/SCF 

NATURAL GAS (5A) [RULE 

475, 10-8-1976; RULE 475, 

8-7-1978]; PM10: 11 LBS/HR 

NATURAL GAS (5B) [RULE 

475, 10-8-1976; RULE 475, 

8-7-1978]; SO2: (9) [40CFR 

72 - Acid Rain Provisions, 

11-24-1997]; SOX: 0.06 

LBS/MMBTU NATURAL 

GAS (8) [40CFR 60 Subpart 

KKKK, 7-6-2006]; VOC: 2 

PPMV NATURAL GAS (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

-BACT, 12-6-2002]

C39 A63.1, A63.2, 

A99.1, A99.3, 

A99.5, A99.7, 

A99.9, 

A195.1, 

A195.2, 

A195.3, 

A327.1, 

A433.1, 

B61.1, C1.1, 

C1.3, C1.6, 

D12.1, D29.1, 

D29.2, D29.3, 

D82.1, D82.2, 

E193.1, H23.1, 

I296.1, K40.1, 

K67.1

GENERATOR, 103 MW

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 15

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

CO OXIDATION CATALYST, NO. 7, 

BASF, WITH 150 CUBIC FEET OF 

TOTAL CATALYST VOLUME.

A/N:

C39 D37 C40

SELECTIVE CATALYTIC 

REDUCTION, NO. 7, CORMETECH 

CHMT-2, 812 CU.FT.; WIDTH: 2 FT 

2 IN; HEIGHT: 4 FT 2 IN; LENGTH: 10 

FT 11 IN WITH

A/N: 

C40 NH3: 5 PPMV NATURAL 

GAS (4) [RULE 1303(a)(1)

-BACT, 5-10-1996; RULE 

1303(a)(1)-BACT, 12-6-2002]

C39 S42 A195.4, 

D12.2, D12.3, 

D12.4, E179.1, 

E179.2, 

E179.3, 

E193.1

AMMONIA INJECTION, GRID

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

DRAFT

FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

CPV SENTINEL LLC

152707

Page: 16

Date:

Facility ID:

Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

GAS TURBINE, GTG8, NATURAL 

GAS, GENERAL ELECTRIC, MODEL 

LMS100PA, SIMPLE CYCLE, 891.7 

MMBTU/HR AT 72 DEGREES F, 

WITH WATER INJECTION WITH

A/N: 

NOX: MAJOR 

SOURCE**

D43 CO: 4 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988]; CO: 

2000 PPMV NATURAL GAS 

(5) [RULE 407, 4-2-1982]; 

NOX: 2.5 PPMV NATURAL 

GAS (4) [RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988; RULE 

2005, 5-6-2005]; NOX: 12.26 

LBS/MMSCF NATURAL 

GAS (1) [RULE 2012, 

5-6-2005]; NOX: 15 PPMV 

NATURAL GAS (8) [40CFR 

60 Subpart KKKK, 7-6-2006]; 

NOX: 19 LBS/MMSCF 

NATURAL GAS (1A) [RULE 

2012, 5-6-2005]; PM10: 0.01 

GRAINS/SCF NATURAL 

GAS (5A) [RULE 475, 

10-8-1976; RULE 475, 

8-7-1978]; PM10: 11 LBS/HR 

NATURAL GAS (5B) [RULE 

475, 10-8-1976; RULE 475, 

8-7-1978]; SO2: (9) [40CFR 

72 - Acid Rain Provisions, 

11-24-1997]; SOX: 0.06 

LBS/MMBTU NATURAL 

GAS (8) [40CFR 60 Subpart 

KKKK, 7-6-2006]; VOC: 2 

PPMV NATURAL GAS (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

-BACT, 12-6-2002]

C45 A63.1, A63.2, 

A99.1, A99.3, 

A99.5, A99.7, 

A99.9, 

A195.1, 

A195.2, 

A195.3, 

A327.1, 

A433.1, 

B61.1, C1.1, 

C1.3, C1.6, 

D12.1, D29.1, 

D29.2, D29.3, 

D82.1, D82.2, 

H23.1, I296.1, 

K40.1, K67.1

GENERATOR, 103 MW

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

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FACILITY PERMIT TO OPERATE

SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

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Section H

Revision #:

The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

CO OXIDATION CATALYST, NO. 8, 

BASF, WITH 150 CUBIC FEET OF 

TOTAL CATALYST VOLUME.

A/N:

C45 D43 C46

SELECTIVE CATALYTIC 

REDUCTION, NO. 8, CORMETECH 

CHMT-2, 812 CU.FT.; WIDTH: 2 FT 

2 IN; HEIGHT: 4 FT 2 IN; LENGTH: 10 

FT 11 IN WITH

A/N: 

C46 NH3: 5 PPMV NATURAL 

GAS (4) [RULE 1303(a)(1)

-BACT, 5-10-1996; RULE 

1303(a)(1)-BACT, 12-6-2002]

C45 S48 A195.4, 

D12.2, D12.3, 

D12.4, E179.1, 

E179.2, 

E179.3, 

E193.1

AMMONIA INJECTION, GRID

STACK, NO.8, HEIGHT: 90 FT ; 

DIAMETER: 13 FT 6 IN

A/N:

S48 C46

System 2: EMERGENCY ENGINES

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
March 02, 2010

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SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

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Section H

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The operator shall comply with the terms and conditions set forth below:

Emissions Conditions

 And Requirements

RECLAIM 

Source Type/ 

Monitoring Unit

Connected 

To

ID 

No.

Equipment *

Process 1: INTERNAL COMBUSTION

INTERNAL COMBUSTION ENGINE, 

EMERGENCY FIRE, DIESEL FUEL, 

CLARKE, MODEL JU6H-UFADTO, 

DRIVING AN FIRE PUMP, WITH 

AFTERCOOLER, TURBOCHARGER, 

274 HP

A/N:

NOX: PROCESS 

UNIT**

D49 CO: 2.6 GRAM/BHP-HR 

DIESEL (4) [RULE 1703(a)(2) 

- PSD-BACT, 10-7-1988]; 

NOX: 134 LBS/1000 GAL 

DIESEL (1) [RULE 2012, 

5-6-2005]; NOX + ROG: 3 

GRAM/BHP-HR DIESEL (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

-BACT, 12-6-2002; RULE 

1703(a)(2) - PSD-BACT, 

10-7-1988; RULE 2005, 

5-6-2005]; PM10: 0.15 

GRAM/BHP-HR DIESEL (4) 

[RULE 1303(a)(1)-BACT, 

5-10-1996; RULE 1303(a)(1)

-BACT, 12-6-2002]; SOX: 

0.005 GRAM/BHP-HR 

DIESEL (4) [RULE 1303(a)(1)

-BACT, 5-10-1996; RULE 

1303(a)(1)-BACT, 12-6-2002]

B61.2, C1.4, 

D12.5, I296.3, 

K67.3

Process 2: INORGANIC CHEMICAL STORAGE

STORAGE TANK, TK-1, 29.4% 

AQUEOUS AMMONIA, WITH PVR 

SET AT 25 PSIG, 12000 GALS; 

DIAMETER: 9 FT 4 IN; HEIGHT: 12 

FT 

A/N:

D52 C157.1, 

E144.1, 

E193.1, K67.2

STORAGE TANK, TK-2, 29.4% 

AQUEOUS AMMONIA, WITH PVR 

SET AT 25 PSIG, 12000 GALS; 

DIAMETER: 9 FT 4 IN; HEIGHT: 12 

FT 

A/N:

D53 C157.1, 

E144.1, 

E193.1, K67.2

 * (1) (1A) (1B) Denotes RECLAIM emission factor (2) (2A) (2B) Denotes RECLAIM emission rate

(3) Denotes RECLAIM concentration limit (4) Denotes BACT emission limit

(5) (5A) (5B) Denotes command and control emission limit (6) Denotes air toxic control rule limit

(7) Denotes NSR applicability limit (8) (8A) (8B) Denotes 40 CFR limit (e.g. NSPS, NESHAPS, etc.)

 (9) See App B for Emission Limits (10) See section J for NESHAP/MACT requirements

 ** Refer to section F and G of this permit to determine the monitoring, recordkeeping and reporting requirements for this device. 
SECTION H: DEVICE ID INDEX

FACILITY PERMIT TO OPERATE

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The following sub-section provides an index

to the devices that make up the facility

description sorted by device ID.
SECTION H: DEVICE ID INDEX

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Device Index For Section H

Device ID Section H Page No. Process System

D1 3 1 1

C3 3 1 1

C4 3 1 1

S6 3 1 1

D7 5 1 1

C9 5 1 1

C10 5 1 1

S12 5 1 1

D13 6 1 1

C15 7 1 1

C16 7 1 1

S18 7 1 1

D19 8 1 1

C21 8 1 1

C22 9 1 1

S24 9 1 1

D25 10 1 1

C27 11 1 1

C28 11 1 1

S30 11 1 1

D31 12 1 1

C33 13 1 1

C34 13 1 1

S36 13 1 1

D37 14 1 1

C39 15 1 1

C40 15 1 1

D43 16 1 1

C45 17 1 1

C46 17 1 1

S48 17 1 1

D49 18 1 2

D52 18 2 0

D53 18 2 0
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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FACILITY CONDITIONS

Except for open abrasive blasting operations, the operator shall not discharge into the 

atmosphere from any single source of emissions whatsoever any air contaminant for a 

period or periods aggregating more than three minutes in any one hour which is:

(a) As dark or darker in shade as that designated No.1 on the Ringelmann Chart, as 

published by the United States Bureau of Mines; or

(b) Of such opacity as to obscure an observer's view to a degree equal to or greater 

than does smoke described in subparagraph (a) of this condition.

F9.1

[RULE 401, 3-2-1984; RULE 401, 11-9-2001]

The operator shall not purchase diesel fuel containing sulfur compounds in excess of 15 

ppm by weight as supplied by the supplier.

F14.1

The operator shall maintain a copy of the MSDS on site

[RULE 431.2, 5-4-1990; RULE 431.2, 9-15-2000]

DEVICE CONDITIONS

A. Emission Limits

A63.1 The operator shall limit emissions from this equipment as follows:

CONTAMINANT EMISSIONS LIMIT

PM10 Less than or equal to 2425 LBS IN ANY ONE MONTH

CO Less than or equal to 6477 LBS IN ANY ONE MONTH

SOX Less than or equal to 293 LBS IN ANY ONE MONTH
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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VOC Less than or equal to 1432 LBS IN ANY ONE MONTH
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The operator shall calculate the monthly emissions for VOC, PM10 and SOx 

using the equation below and the following emission factors: VOC: 2.52 lb/mmcf; 

PM10: 5.71 lb/mmcf; and SOx: 0.71 lb/mmcf.

Monthly Emissions, lb/month = X (E.F.)

Where X = monthly fuel usage in mmscf/month and E.F. = emission factor 

indicated above

Compliance with the CO emission limit shall be verified through valid CEMS data

The operator shall calculate the emission limit(s) for the purpose of determining 

compliance with the monthly CO limit in the absence of valid CEMS data by using 

the above equation and the following emission factor(s):

(A) During the commissioning period and prior to CO catalyst installation - 38.48 

lbs CO/mmcf

(B) After installation of the CO catalyst but prior to CO CEMS certification 

testing - 14.38 lb CO/mmcf. The emission rate shall be recalculated in 

accordance with Condition D82.1 if the approved CEMS certification test 

resulted in emission concentration higher than 4 ppmv.

(C) After CO CEMS certification testing - 14.38 lb/CO mmcf. After CO CEMS 

certification test is approved by the AQMD, the emissions monitored by the 

CEMS and calculated in accordance with condition D82.1 shall be used to 

calculate emissions.

For the purposes of this condition, the limit(s) shall be based on the emissions 

from a single turbine. During commissioning, the CO emissions shall not exceed 

11,602 lbs in any one month. During commissioning, the VOC emissions shall 

not exceed 620 lbs in any one month.

The operator shall provide the AQMD with written notification of the date of 

initial CO catalyst use within seven (7) days of this event.
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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For the purpose of this condition the turbine shall not commence with normal 

operation until the commissioning process has been completed. The District shall 

be notified in writing once the commissioning process has been completed. 

Normal operations may proceed in the same commissioning month provided the 

operator follows the requirements listed below:

The operator shall calculate the commissioning emissions for VOC, SOx and 

PM10 for the commissioning month (beginning of the month to the last day of 

commissioning) using the equation below and the following emission factors: 

VOC: 2.06 lb/mmcf; PM10: 2.49 lb/mmcf; and SOx: 0.12 lb/mmcf

Commissioning Emissions, lb/month = X (E.F.)

Where X = commissioning fuel usage in mmscf/month and E.F. = emission factor 

indicated above.

The commissioning emissions for VOC, SOx and PM10 shall be subtracted from 

the monthly emissions limits (listed in the table at the top of this condition) and 

the revised monthly emission limits will be the maximum emissions allowed for 

the remaining of the month

For the purpose of this condition, normal operations is defined as the turbine is 

able to supply electrical energy to the power grid as required under contract with 

SCE or other entity.

[RULE 1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)-Offset, 12-6-2002]

[Devices subject to this condition : D1, D7, D13, D19, D25, D37, D43]

A63.2 The operator shall limit emissions from this equipment as follows:

CONTAMINANT EMISSIONS LIMIT

PM10 Less than or equal to 118120 LBS IN ANY ONE YEAR

SOX Less than or equal to 13928 LBS IN ANY ONE YEAR
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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For the purposes of this condition, the annual limit(s) shall be calculated by using 

annual and montthly fuel use data, and the following emission factors: PM10 5.71 

lb/MMSCF; and SOx: 0.25 grains/100 scf.

For the purpose of this condition, the yearly emission limit shall be defined as a 

period of twelve (12) consecutive months determined on a rolling basis with a 

new 12 month period beginning on the first day of each calendar month.

[RULE 1303, 5-10-1996; RULE 1303, 10-20-2000; 40CFR 51 Subpart S, 3-8-2007]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

The 2.5 PPM NOX emission limit(s) shall not apply during turbine commissioning, 

start-up, and shutdown periods. The commissioning period shall not exceed 150 hours. 

Start-up time shall not exceed 25 minutes for each start-up. Shutdown periods shall not 

exceed 10 minutes for each shutdown. The turbine shall be limited to a maximum of 300 

start-ups per year. Written records of commissioning, start-ups and shutdowns shall be 

maintained and made available upon request from the Executive Officer.

A99.1

For the purposes of this condition, start-up shall be defined as start up process to 

bring the turbine in full successful operations. If during start-up the process is 

aborted and the start-up is restarted, then the start-up and restart is defined as "one 

start-up" In this case the start-up time shall not exceed one hour. The NOx 

emissions limited to 29.54 pounds per hour as listed in condition A433.1.

For the purposes of this condition, the aborted start-up shall be defined as not to 

exceed one hour.

[RULE 1703(a)(2) - PSD-BACT, 10-7-1988; RULE 2005, 5-6-2005]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The 4 PPM CO emission limit(s) shall not apply during turbine commissioning, start-up, 

and shutdown periods. The commissioning period shall not exceed 150 hours. Start-up 

time shall not exceed 25 minutes for each start-up. Shutdown periods shall not exceed 

10 minutes for each shutdown. The turbine shall be limited to a maximum of 300 

start-ups per year. Written records of commissioning, start-ups and shutdowns shall be 

maintained and made available upon request from the Executive Officer.

A99.3

For the purposes of this condition, start-up shall be defined as the start up process 

to bring the turbine in full successful operations. If during start-up the process is 

aborted and the start-up is restarted, then the start-up and restart is defined as "one 

start-up". In this case the start-up time shall not exceed one hour.

[RULE 1703(a)(2) - PSD-BACT, 10-7-1988]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

The 19.0 LBS/MMCF NOX emission limit(s) shall only apply the interim reporting 

period during initial turbine commissioning to report RECLAIM emissions. The interim 

reporting period shall not exceed 12 months from entry into RECLAIM.

A99.5

[RULE 2012, 5-6-2005]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

The 12.26 LBS/MMCF NOX emission limit(s) shall only apply during the interim 

reporting period after initial turbine commissioning to report RECLAIM emissions. The 

interim reporting period shall not exceed 12 months from entry into RECLAIM.

A99.7

[RULE 2012, 5-6-2005]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The 2.0 PPM ROG emission limit(s) shall not apply during turbine commissioning, 

start-up, and shutdown periods. The commissioning period shall not exceed 150 hours. 

Start-up time shall not exceed 25 minutes for each start-up. Shutdown periods shall not 

exceed 10 minutes for each shutdown. The turbine shall be limited to a maximum of 300 

start-ups per year. Written records of commissioning, start-ups and shutdowns shall be 

maintained and made available upon request from the Executive Officer.

A99.9

For the purposes of this condition, start-up shall be defined as the start up process 

to bring the turbine in full successful operations. If during start-up the process is 

aborted and the start-up is restarted, then the start-up and restart is defined as "one 

start-up". In this case the start-up time shall not exceed one hour.

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

A195.1 The 4.0 PPMV CO emission limit(s) is averaged over 60 minutes at 15 percent O2, dry.

[RULE 1703(a)(2) - PSD-BACT, 10-7-1988]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

The 2.5 PPMV NOX emission limit(s) is averaged over 60 minutes at 15 percent O2, 

dry.

A195.2

[RULE 1703(a)(2) - PSD-BACT, 10-7-1988; RULE 2005, 5-6-2005]

[Devices subject to this condition : D1, D13, D19, D25, D31, D37, D43]

The 2.0 PPMV ROG emission limit(s) is averaged over 60 minutes at 15 percent O2, 

dry.

A195.3

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The 5 PPMV NH3 emission limit(s) is averaged over 60 minutes at 15% O2, dry basis. 

The operator shall calculate and continuously record the NH3 slip concentration using 

the following.

A195.4

NH3 (ppmv) = [a-b*c/1EE+06]*1EE+06/b; where

a = NH3 injection rate (lbs/hr)/17(lb/lb-mol)

b = dry exhaust gas flow rate (scf/hr)/385.3 scf/lb-mol)

c = change in measured NOx across the SCR (ppmvd at 15% O2)

The operator shall install and maintain a NOx analyzer to measure the SCR inlet 

NOx ppmv accurate to plus or minus 5 percent calibrated at least once every 

twelve months

The NOx analyzer shall be installed and operated within 90 days of initial start-up

The operator shall use the above described method or another alternative method 

approved by the Executive Officer.

The ammonia slip calculation procedures described above shall not be used for 

compliance determination or emission information without corroborative data 

using an approved reference method for the determination of ammonia

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002]

[Devices subject to this condition : C4, C10, C16, C22, C28, C34, C40, C46]

For the purpose of determining compliance with District Rule 475, combustion 

contaminant emissions may exceed the concentration limit or the mass emission limit 

listed, but not both limits at the same time.

A327.1

[RULE 475, 10-8-1976; RULE 475, 8-7-1978]

[Devices subject to this condition : D1, D7, D13, D25, D31, D37, D43]
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The operator shall comply at all times with the 2.5 ppm 1-hour BACT liimit for NOx, 

except as defined in condition A99.1 and for the following scenario::

A433.1

Operating 

Scenario

Maximum Hourly Emissions 

Limit

Operational Limit

Start-up hour 29.54 NOx emissions not to exceed 

29.54lbs total per start-up per 

turbine. Each turbine shall be 

limited to 300 start-ups per year, 

with each start-up not to exceed 

25 minutes.

[RULE 1703(a)(2) - PSD-BACT, 10-7-1988; RULE 2005, 4-20-2001]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

B. Material/Fuel Type Limits

B61.1 The operator shall not use natural gas containing the following specified compounds:

Compound Grains per 100 scf

H2S greater than 0.25

This concentration limit is an annual average based on monthly sample of natural 

gas composition or gas supplier documentation. Gaseous fuel samples shall be 

tested using District Method 307-91 for total sulfur calculated as H2S.

[RULE 1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)-Offset, 12-6-2002]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

B61.2 The operator shall only use diesel fuel containing the following specified compounds:
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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Compound Range ppm by weight

Sulfur less than or equal to 15

The operator shall maintain a copy of the MSDS on site

[RULE 431.2, 5-4-1990; RULE 431.2, 9-15-2000]

[Devices subject to this condition : D49]

C. Throughput or Operating Parameter Limits

The operator shall limit the fuel usage to no more than 425 MM cubic feet in any one 

calendar month.

C1.1

For the purpose of this condition, fuel usage shall be defined as the total natural 

gas usage of a single turbine during a non-commissioning month..

The operator shall maintain records in a manner approved by the District, to 

demonstrate compliance with this condition.

[RULE 1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)-Offset, 12-6-2002]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

C1.3 The operator shall limit the fuel usage to no more than 301 MM cubic feet.

For the purpose of this condition, fuel usage shall be defined as the total natural 

gas usage of a single turbine during a commissioning period. The max fuel usage 

shall not exceed 301 mmcf per month.

The operator shall maintain records in a manner approved by the District, to 

demonstrate compliance with this condition.

[RULE 1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)-Offset, 12-6-2002]
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

C1.4 The operator shall limit the operating time to no more than 50 hour(s) in any one year.

For the purposes of this condition, the operating time is inclusive of time allotted 

for maintenance and testing.

[RULE 1110.2, 2-1-2008; RULE 1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)

-Offset, 12-6-2002; RULE 1470, 6-1-2007; RULE 2012, 5-6-2005]

[Devices subject to this condition : D49]

C1.6 The operator shall limit the fuel usage to no more than 2455 MM cubic feet per year.

For the purpose of this condition, fuel usage shall be defined as the total natural 

gas usage of a single turbine during a non-commissioning year..

The operator shall maintain records in a manner approved by the District, to 

demonstrate compliance with this condition.

[RULE 1401, 3-4-2005; RULE 1703(a)(3) PSD Analysis, 10-7-1988]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

The operator shall install and maintain a pressure relief valve with a minimum pressure 

set at 25 psig.

C157.1

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002]

[Devices subject to this condition : D52, D53]

D. Monitoring/Testing Requirements

The operator shall install and maintain a(n) flow meter to accurately indicate the fuel 

usage being supplied to the turbine.

D12.1
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The operator shall also install and maintain a device to continuously record the 

parameter being measured

[RULE 1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)-Offset, 12-6-2002; RULE 2012, 

5-6-2005]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

The operator shall install and maintain a(n) flow meter to accurately indicate the flow 

rate of the total hourly throughput of injected ammonia.

D12.2

The operator shall also install and maintain a device to continuously record the 

parameter being measured

The measuring device or gauge shall be accurate to within plus or minus 5 

percent.

It shall be calibrated once every twelve months. The calibrations records shall be 

kept on site and made available to AQMD personnel upon request.

The ammonia injection system shall be placed in full operation as soon as the 

minimum temperature is reached. The minimum temperature is listed as 540 

degrees F. at the inlet to the SCR reactor

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002]

[Devices subject to this condition : C4, C10, C16, C22, C28, C34, C40, C46]

The operator shall install and maintain a(n) temperature gauge to accurately indicate the 

temperature of the at the inlet to the SCR reactor.

D12.3
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The operator shall also install and maintain a device to continuously record the 

parameter being measured

The measuring device or gauge shall be accurate to within plus or minus 5 percent

It shall be calibrated once every twelve months.

The catalyst temperature range shall remain between 740 degree F and 840 

degrees F

The catalyst intlet temperature shall not exceed 840 degrees F.

The temperature range requirement of this condition does not apply during 

start-up operations of the turbine not to exceed 25 minutes per start-up.

For this condition start-up shall be defined as the start up process to bring the 

turbine in full successful operations. If during start-up the process is aborted and 

the start-up is restarted, then the start-up and restart is defined as "one start-up". In 

this case the start-up time shall not exceed one hour

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002; RULE 

1703(a)(2) - PSD-BACT, 10-7-1988; RULE 2005, 5-6-2005]

[Devices subject to this condition : C4, C10, C16, C22, C28, C34, C40, C46]

The operator shall install and maintain a(n) pressure gauge to accurately indicate the 

differential pressure across the SCR catalyst bed in inches of water column.

D12.4

The operator shall also install and maintain a device to continuously record the 

parameter being measured

The measuring device or gauge shall be accurate to within plus or minus 5 

percent. It shall be calibrated once every twelve months

It shall be calibrated once every twelve months

The pressure drop across the catalyst shall not exceed 12 inches water column
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002; RULE 

1703(a)(2) - PSD-BACT, 10-7-1988; RULE 2005, 5-6-2005]

[Devices subject to this condition : C4, C10, C16, C22, C28, C34, C40, C46]

The operator shall install and maintain a(n) non-resettable elapsed time meter to 

accurately indicate the elapsed operating time from the engine.

D12.5

[RULE 1110.2, 2-1-2008; RULE 1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)

-Offset, 12-6-2002; RULE 1470, 6-1-2007; RULE 2012, 5-6-2005]

[Devices subject to this condition : D49]

D29.1 The operator shall conduct source test(s) for the pollutant(s) identified below.

Pollutant(s) to 

be tested

Required Test Method(s) Averaging Time Test Location

Outlet of the SCR 

serving this equipment

NOX emissions District method 100.1 1 hour

CO emissions District method 100.1 1 hour Outlet of the SCR 

serving this equipment

AQMD Laboratory Fuel sample

Method 307-91

SOX emissions Not Applicable

Outlet of the SCR 

serving this equipment

VOC emissions District Method 25.3 1 hour

PM10 

emissions

Outlet of the SCR 

serving this equipment

District Method 5 4 hours

District method 207.1 

and 5.3 or EPA method 

17

Outlet of the SCR 

serving this equipment

NH3 emissions 1 hour
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The test shall be conducted after AQMD approval of the source test protocol, but 

no later the later of 180 days after initial start-up or three hundred hours of 

operations after start-up. The AQMD shall be notified of the date and time of the 

test at least 10 days prior to the test

The test shall be conducted to determine the oxygen levels in the exhaust. In 

addition, the tests shall measure the fuel flow rate (CFH), the flue gas flow rate, 

and the turbine generating output in MW.

The test shall be conducted in accordance with AQMD approved test protocol. 

The protocol shall be submitted to the AQMD engineer no later than 45 days 

before the proposed test date and shall be approved by the AQMD before the test 

commences. The test protocol shall include the proposed operating conditions of 

the turbine during the tests, the identity of the testing lab, a statement from the 

testing lab certifying that it meets the criteria of Rule 304, and a description of all 

sampling and analyt

The test shall be conducted when this equipment is operating at maximum, 

average, and minimum loads.

The test shall be conducted for compliance verification of the BACT VOC 2.0 

ppmv limit.

For natural gas fired turbines only, VOC compliance shall be demonstrated as 

follows: a) Stack gas samples are extracted into Summa canisters maintaining a 

final canister pressure between 400-500 mm Hg absolute, b) Pressurization of 

canisters are done with zero gas analyzed/certified to contain less than 0.05 ppmv 

total hydrocarbon as carbon, and c) Analysis of canisters are per EPA Method 

TO-12 (with pre concentration) and temperature of canisters when extracting 

samples for analysis is not below 7

The use of this alternative method for VOC compliance determination does not 

mean that it is more accurate than AQMD Method 25.3, nor does it mean that it 

may be used in lieu of AQMD Method 25.3 without prior approval except for the 

determination of compliance with the VOC BACT level of 2.0 ppmv calculated as 

carbon for natural gas fired turbines.
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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Because the VOC BACT level was set using data derived from various source test 

results, this alternate VOC compliance method provides a fair comparison and 

represents the best sampling and analysis technique for this purpose at this time. 

The test results shall be reported with two significant digits.

For the purpose of this condition, alternative test method may be allowed for each 

of the above pollutants upon concurrence of AQMD, EPA and CARB.

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002; RULE 

1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)-Offset, 12-6-2002; RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988; RULE 2005, 5-6-2005]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

D29.2 The operator shall conduct source test(s) for the pollutant(s) identified below.

Pollutant(s) to 

be tested

Required Test Method(s) Averaging Time Test Location

Outlet of the SCR 

serving this equipment

District method 207.1 

and 5.3 or EPA method 

17

NH3 emissions 1 hour
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The test shall be conducted and the results submitted to the District within 45 

days after the test date. The AQMD shall be notified of the date and time of the 

test at least 7 days prior to the test.

The test shall be conducted at least quarterly during the first twelve months of 

operation and at least annually thereafter. The NOx concentration, as determined 

by the CEMS, shall be simultaneously recorded during the ammonia slip test. If 

the CEMS is inoperable, a test shall be conducted to determine the NOx 

emissions using District Method 100.1 measured over a 60 minute averaging time 

period.

If the turbine is not in operation during one quarter, then no testing is required 

during that quarter

The test shall be conducted to demonstrate compliance with the Rule 1303 BACT 

concentration limit

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

D29.3 The operator shall conduct source test(s) for the pollutant(s) identified below.

Pollutant(s) to 

be tested

Required Test Method(s) Averaging Time Test Location

AQMD Laboratory Fuel sample

Method 307-91

SOX emissions Not Applicable

VOC emissions District Method 25.3 1 hour Outlet of the SCR 

serving this equipment

Outlet of the SCR 

serving this equipment

PM10 District Method 5 4 hours

emissions
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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The test shall be conducted at least once every three years.

The test shall be conducted to determine the oxygen levels in the exhaust. In 

addition, the tests shall measure the fuel flow rate (CFH), the flue gas flow rate, 

and the turbine generating output in MW.

The test shall be conducted in accordance with AQMD approved test protocol. 

The protocol shall be submitted to the AQMD engineer no later than 45 days 

before the proposed test date and shall be approved by the AQMD before the test 

commences. The test protocol shall include the proposed operating conditions of 

the turbine during the tests, the identity of the testing lab, a statement from the 

testing lab certifying that it meets the criteria of Rule 304, and a description of all 

sampling and analyt

The test shall be conducted when this equipment is operating at maximum, 

average, and minimum loads.

The test shall be conducted for compliance verification of the BACT VOC 2.0 

ppmv limit.

For natural gas fired turbines only, VOC compliance shall be demonstrated as 

follows: a) Stack gas samples are extracted into Summa canisters maintaining a 

final canister pressure between 400-500 mm Hg absolute, b) Pressurization of 

canisters are done with zero gas analyzed/certified to contain less than 0.05 ppmv 

total hydrocarbon as carbon, and c) Analysis of canisters are per EPA Method 

TO-12 (with pre concentration) and temperature of canisters when extracting 

samples for analysis is not below 7

The use of this alternative method for VOC compliance determination does not 

mean that it is more accurate than AQMD Method 25.3, nor does it mean that it 

may be used in lieu of AQMD Method 25.3 without prior approval except for the 

determination of compliance with the VOC BACT level of 2.0 ppmv calculated as 

carbon for natural gas fired turbines.

Because the VOC BACT level was set using data derived from various source test 

results, this alternate VOC compliance method provides a fair comparison and 
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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represents the best sampling and analysis technique for this purpose at this time. 

The test results shall be reported with two significant digits.

For the purpose of this condition, alternative test method may be allowed for each 

of the above pollutants upon concurrence of AQMD, EPA and CARB.

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002; RULE 

1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)-Offset, 12-6-2002; RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

D82.1 The operator shall install and maintain a CEMS to measure the following parameters:
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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CO concentration in ppmv

Concentrations shall be corrected to 15 percent oxygen on a dry basis

The CEMS shall be installed and operated to measure CO concentrations over a 

15 minute averaging time period.

The CEMS shall be installed and operated to measure CO concentrations over a 

15 minute averaging time period.

The CEMS would convert the actual CO concentrations to mass emission rates 

(lbs/hr) using the equation below and record the hourly emission rates on a 

continuous basis.

The CEMS would convert the actual CO concentrations to mass emission rates 

(lbs/hr) using the equation below and record the hourly emission rates on a 

continuous basis.

CO Emission Rate, lbs/hr = K Cco Fd[20.9% - %O2 d)][(Qg * HHV)/1.0^6], 

where

K = 7.267 *10^-8 (lb/scf)/ppm

Cco = Average of four consecutive 15 min. ave. CO concentration, ppm

Fd = 8710 dscf/MMBTU natural gas

%O2 d = Hourly ave. % by vol. O2 dry, corresponding to Cco

Qg = Fuel gas usage during the hour, scf/hr

HHV = Gross high heating value of fuel gas, BTU/scf

[RULE 1703(a)(2) - PSD-BACT, 10-7-1988; RULE 218, 8-7-1981; RULE 218, 

5-14-1999]
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

D82.2 The operator shall install and maintain a CEMS to measure the following parameters:

NOx concentration in ppmv

Concentrations shall be corrected to 15 percent oxygen on a dry basis.

The CEMS shall be installed and operating no later than 90 days after initial 

start-up of the turbine and shall comply with the requirements of Rule 2012. 

During the interim period between the initial start-up and the provisional 

certification date of the CEMS, the operator shall comply with the monitoring 

requirements of Rule 2012(h)(2) and 2012(h)(3). Within two weeks of the 

turbine start-up date, the operator shall provide written notification to the District 

of the exact date of start-up

The CEMS shall be installed and operating (for BACT purposes only) no later than 

90 days after initial start up of the turbine.

[RULE 1703(a)(2) - PSD-BACT, 10-7-1988; RULE 2005, 5-6-2005; RULE 2012, 

5-6-2005]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

E. Equipment Operation/Construction Requirements

The operator shall vent this equipment, during filling, only to the vessel from which it is 

being filled.

E144.1

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002]

[Devices subject to this condition : D52, D53]

For the purpose of the following condition number(s), condition number(s), 

continuously record shall be defined as measuring at least once every month and shall be 

calculated based upon the average of the continuous monitoring for that month.

E179.1
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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Condition Number D 12- 4

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002]

[Devices subject to this condition : C4, C10, C16, C22, C28, C34, C40, C46]

For the purpose of the following condition number(s), continuously record shall be 

defined as recording at least once every hour and shall be calculated based upon the 

average of the continuous monitoring for that hour.

E179.2

Condition Number D 12- 2

Condition Number D 12- 3

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002; RULE 

1703(a)(2) - PSD-BACT, 10-7-1988; RULE 2005, 5-6-2005]

[Devices subject to this condition : C4, C10, C16, C22, C28, C34, C40, C46]

For the purpose of the following condition number(s), continuously record shall be 

defined as measuring at least once every month and shall be calculated based upon the 

average of the continuous monitoring for that month.

E179.3

Condition Number D 12- 2

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002; RULE 

1703(a)(2) - PSD-BACT, 10-7-1988; RULE 2005, 5-6-2005]

[Devices subject to this condition : C4, C10, C16, C22, C28, C34, C40, C46]

The operator shall upon completion of construction, operate and maintain this equipment 

according to the following specifications:

E193.1

In accordance with all mitigation measures stipulated in the final California 

Energy Commission decision for the 07-AFC-3 project

[CA PRC CEQA, 11-23-1970]
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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[Devices subject to this condition : D1, C4, D7, C10, D13, C16, D19, C22, D25, C28, 

D31, C34, D37, C40, C46, D52, D53]

H. Applicable Rules

This equipment is subject to the applicable requirements of the following rules or 

regulations:

H23.1

Contaminant Rule Rule/Subpart

NOX 40CFR60, SUBPART KKKK

SOX 40CFR60, SUBPART KKKK

[40CFR 60 Subpart KKKK, 7-6-2006]

[Devices subject to this condition : D1, D13, D19, D25, D31, D37, D43]

I. Administrative

This equipment shall not be operated unless the operator demonstrates to the Executive 

Officer that the facility holds sufficient RTCs to offset the prorated annual emissions 

increase for the first compliance year of operation. In addition, this equipment shall not 

be operated unless the operator demonstrates to the Executive Officer that, at the 

commencement of each compliance year after the first compliance year of operation, 

the facility holds sufficient RTCs in an amount equal to the annual emissions increase.

I296.1
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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To comply with this condition, the operator shall prior to the 1st compliance year 

hold a minimum NOx RTCs of 35767 lbs/yr. This condition shall apply during the 

1st 12 months of operation, commencing with the initial operation of the gas 

turbine.

To comply with this condition, the operator shall, prior to the beginning of all 

years subsequent to the 1st compliance year, hold a minimum of 30,039 lbs/yr fo 

NOx RTCs for operation of the gas turbine

In accordance with Rule 2005(f), unused RTC's may be sold only during the 

reconciliation period for the fourth quarter of the applicable compliance year 

inclusive of the 1st compliance year.

This condition shall apply to each turbine individually.

[RULE 2005, 5-6-2005]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

This equipment shall not be operated unless the operator demonstrates to the Executive 

Officer that the facility holds sufficient RTCs to offset the prorated annual emissions 

increase for the first compliance year of operation. In addition, this equipment shall not 

be operated unless the operator demonstrates to the Executive Officer that, at the 

commencement of each compliance year after the first compliance year of operation, 

the facility holds sufficient RTCs in an amount equal to the annual emissions increase.

I296.3

To comply with this condition, the operator shall prior to the 1st compliance year 

hold a minimum NOx RTCs of 77 lbs/yr. This condition shall apply during the 1st 

12 months of operation, commencing with the initial operation of the fire pump

In accordance with Rule 2005(f), unused RTC's may be sold only during the 

reconciliation period for the fourth quarter of the applicable compliance year 

inclusive of the 1st compliance year.

[RULE 2005, 5-6-2005]

[Devices subject to this condition : D49]
SECTION H: PERMIT TO CONSTRUCT AND TEMPORARY PERMIT TO OPERATE

The operator shall comply with the terms and conditions set forth below:

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K. Record Keeping/Reporting

The operator shall provide to the District a source test report in accordance with the 

following specifications:

K40.1

Source test results shall be submitted to the District no later than 60 days after 

the source test was conducted

Emission data shall be expressed in terms of concentration (ppmv) corrected to 

15 percent oxygen (dry basis), mass rate (lb/hr), and lb/MMCF. In addition, solid 

PM emissions, if required to be tested, shall also be reported in terms of 

grains/DSCF

All exhaust flow rate shall be expressed in terms of dry standard cubic feet per 

minute (DSCFM) and dry actual cubic feet per minute (DACFM).

All moisture concentration shall be expressed in terms of percent corrected to 15 

percent oxygen

Source test results shall also include the oxygen levels in the exhaust, fuel flow 

rate (CFH),heating content of the fuel, the flue gas temperature, and the generator 

power output (MW) under which the test was conducted

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002; RULE 

1303(b)(2)-Offset, 5-10-1996; RULE 1303(b)(2)-Offset, 12-6-2002; RULE 1703(a)(2) - 

PSD-BACT, 10-7-1988; RULE 2005, 5-6-2005]

[Devices subject to this condition : D1, D7, D13, D25, D31, D37, D43]

The operator shall keep records, in a manner approved by the District, for the following 

parameter(s) or item(s):

K67.1
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The operator shall comply with the terms and conditions set forth below:

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Natural gas fuel use after CEMS certification

Natural gas fuel use during the commissioning period

Natural gas fuel use after the commissioning period and prior to CEMS 

certification

[RULE 2005, 5-6-2005]

[Devices subject to this condition : D1, D7, D13, D19, D25, D31, D37, D43]

The operator shall keep records, in a manner approved by the District, for the following 

parameter(s) or item(s):

K67.2

The operator shall document an inspection each time the tank is filled to insure 

the vapor recovery equipment is consistently and properly used

[RULE 1303(a)(1)-BACT, 5-10-1996; RULE 1303(a)(1)-BACT, 12-6-2002]

[Devices subject to this condition : D52, D53]

The operator shall keep records, in a manner approved by the District, for the following 

parameter(s) or item(s):

K67.3
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The operator shall comply with the terms and conditions set forth below:

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Manual and automatic operation and shall list all engine operations in each of the 

following areas:

Emergency use hours of operation

Maintenance and testing hours

Other operating hours (describe the reason for operation)

In addition, each time the engine is started manually, the log shall include the date 

of operation and the timer reading in hours at the beginning and end of operation. 

the log shall be kept for a minimum of five calendar years prior to the current 

year and made available to district personnel upon request. the total hours of 

operation for the previous calendar year shall be recorded sometime during the 

first 15 days of January of each year.

[RULE 1110.2, 2-1-2008; RULE 1470, 6-1-2007]

[Devices subject to this condition : D49]
SECTION I: PLANS AND SCHEDULES

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This section lists all plans approved by AQMD for the purposes of meeting the requirements of applicable 

AQMD rules.

NONE

NOTE: This section does not list compliance schedules pursuant to the requirements of Regulation XXX - Title 

V Permits; Rule 3004(a)(10)(C). For equipment subject to a variance, order for abatement, or alternative 

operating condition granted pursuant to Rule 518.2, equipment specific conditions are added to the equipment in 

Section D or H of the permit.
FACILITY PERMIT TO OPERATE

SECTION J: AIR TOXICS

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 1 

NOT APPLICABLE
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Section K

Revision #:

SECTION K: TITLE V Administration
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This facility is subject to the following rules and regulations

FACILITY RULES

With the exception of Rule 402, 473, 477, 1118 and Rules 1401 through 1420, the following 

rules that are designated as non-federally enforceable are pending EPA approval as part of the 

state implementation plan. Upon the effective date of that approval, the approved rule(s) will 

become federally enforceable, and any earlier versions of those rules will no longer be federally 

enforceable.

RULE SOURCE Adopted/Amended Date FEDERAL Enforceability

RULE 1110.2 2-1-2008 Non federally enforceable

RULE 1113 11-8-1996 Federally enforceable

RULE 1113 7-13-2007 Non federally enforceable

RULE 1171 11-7-2003 Federally enforceable

RULE 1171 2-1-2008 Non federally enforceable

RULE 1303 5-10-1996 Federally enforceable

RULE 1303(a)(1)-BACT 12-6-2002 Non federally enforceable

RULE 1303(a)(1)-BACT 5-10-1996 Federally enforceable

RULE 1303(b)(2)-Offset 12-6-2002 Non federally enforceable

RULE 1303(b)(2)-Offset 5-10-1996 Federally enforceable

RULE 1401 3-4-2005 Non federally enforceable

RULE 1470 6-1-2007 Non federally enforceable

RULE 1703 - PSD Analysis 10-7-1988 Federally enforceable

RULE 1703(a)(2) - 

PSD-BACT

10-7-1988 Non federally enforceable

RULE 1703(a)(3) PSD 

Analysis

10-7-1988 Non federally enforceable

RULE 2005 4-20-2001 Federally enforceable

RULE 2005 5-6-2005 Federally enforceable

RULE 2012 5-6-2005 Federally enforceable

RULE 218 5-14-1999 Non federally enforceable

RULE 218 8-7-1981 Federally enforceable
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RULE SOURCE Adopted/Amended Date FEDERAL Enforceability

RULE 3002 11-14-1997 Federally enforceable

RULE 3003 11-14-1997 Federally enforceable

RULE 3003 3-16-2001 Non federally enforceable

RULE 3004 12-12-1997 Federally enforceable

RULE 3005 11-14-1997 Federally enforceable

RULE 3005 3-16-2001 Non federally enforceable

RULE 3007 10-8-1993 Federally enforceable

RULE 401 11-9-2001 Non federally enforceable

RULE 401 3-2-1984 Federally enforceable

RULE 407 4-2-1982 Federally enforceable

RULE 408 5-7-1976 Federally enforceable

RULE 409 8-7-1981 Federally enforceable

RULE 431.2 5-4-1990 Federally enforceable

RULE 431.2 9-15-2000 Non federally enforceable

RULE 475 10-8-1976 Federally enforceable

RULE 475 8-7-1978 Non federally enforceable

RULE 701 6-13-1997 Federally enforceable

CA PRC CEQA 11-23-1970 Non federally enforceable

40CFR 51 Subpart S 3-8-2007 Federally enforceable

40CFR 60 Subpart KKKK 7-6-2006 Federally enforceable

40CFR 72 - Acid Rain 

Provisions

11-24-1997 Federally enforceable
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[RULE 1113 11-08-1996] 
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[40CFR 72 - Acid Rain Provisions 11-24-1997] 


































1 | Page

APPENDIX N

Emissions Offset Evaluation Prepared for  

Addendum to Determination of Compliance Submitted to CEC

CPV Sentinel Energy Project

(March 2, 2010)

This document is being submitted by the South Coast Air Quality Management District (AQMD)

as part of its Determination of Compliance (DOC) for the CPV Sentinel Energy Project (CPV

Sentinel).  Under federal, state and local laws, rules and regulations, it is required that emission

increases of specified nonattainment air contaminants and their precursors be offset for the

CPV Sentinel.  This evaluation is done pollutant specific for compliance with local, state and

federal laws based on AQMD Regulations XIII (Rule 1303) and XX (Rule 2005); the federal Clean

Air Act and NSR Regulations; and State of California Clean Air Act No Net Increase and Assembly

Bill (AB) 1318 provisions.  

Emission offsets for Volatile Organic Compounds (VOCs) will be provided by CPV Sentinel in the

form of Emission Reduction Credits (ERCs) purchased by CPV Sentinel in the open market

pursuant to AQMD Regulation XIII (Rule 1303).  Emission offsets for Nitrogen Oxides (NOx) will

also be provided by CPV Sentinel in the form of RECLAIM Trading Credits (RTCs) purchased by

CPV Sentinel in the open market pursuant to AQMD Regulation XX (Rule 2005).  Emission

offsets for Sulfur Oxides (SOx) and Particulate Matter‐less than 10 micron in diameter‐ (PM10)

will be provided by AQMD from offset credits pursuant to AB 1318 (Health & Safety Code

Section 40440.14(a)).  CPV Sentinel will pay AQMD mitigation fees for SOx and PM10 offsets,

which in turn AQMD will invest in emission reduction projects pursuant to AB 1318.  Emission

offsets for Carbon Monoxide (CO) and Particulate Matter‐less than 2.5 micron in diameter‐ 

(PM2.5) are not required, since the Salton Sea Air Basin (SSAB), where CPV Sentinel is to be

located, is not classified as nonattainment with respect to CO or PM2.5.   

The CPV offset evaluation for SOx and PM10, which is provided under this DOC to CEC, pursuant

to AB 1318 (Health & Safety Code Section 40440.14(c)), will also be submitted to the U.S.

Environmental Protection Agency (EPA) for approval and inclusion into the State

Implementation Plan (SIP).  Table 1 below shows the CPV Sentinel emissions and the source of

offsets for each air contaminant.  Emissions in the first year are higher due to initial

commissioning of the CPV Sentinel power plant.
2 | Page

Table 1 – Maximum Emissions and Offsets

Pollutant Maximum Emissions Needing Offsets Offset Source

VOC 441 lbs/day*   ERCs – supplied by CPV Sentinel, LLC.

NOx

Commissioning Year RTCs – 286,786.05

lbs/year

Other Years RTCs – 240,958.05 lbs/year

RTCs – supplied by CPV Sentinel, LLC.

SOx Commissioning Year – 13,928 lbs/year

Other Years – 13,560 lbs/year AQMD’s internal offset accounts, per

AB1318. PM10 Commissioning Year –118,120 lbs/year

Other Years – 112,180 lbs/year

CO Worst case – 188 tons/year Not Nonattainment pollutant in SSAB.

Offsets not required.**

PM2.5 Worst case*** – 59.06 tons/year Not Nonattainment pollutant in SSAB.

Offsets not required.****

*Includes 1.2‐to‐1.0 offset ratio, as per Rule 1303(b)(2)(A.)

** SSAB is not classified as Nonattaiment for federal and state ambient air quality standards for CO. (SSAB is classified as

Attainment for state and is Unclassified/Attainment for federal.) Therefore, no CO offsets are required. The worst case

maximum yearly CO emission of 188 tons/year is below the 250 ton/year threshold for Prevention of Significant Deterioration

(PSD) as specified by Rule 1701(b)(2). Therefore, does not require a PSD permit.

***Assuming all (100%) of PM10 emissions are PM2.5.

****SSAB is not classified as Nonattainment for federal and state ambient air quality standards for PM2.5. (SSAB is Unclassified

for state and Unclassified/Attainment for federal.) Therefore, no PM2.5 offsets are required. The worst case maximum yearly

PM2.5 emission of 59.06 tons/year is below the 250 ton/year threshold for PSD and, therefore, it does not require a PSD

permit.  

VOC Emissions

The CPV Sentinel project complies with all of the VOC offset requirements (at a 1.2‐to‐1.0 offset

ratio) through CPV Sentinel providing VOC ERCs prior to issuance of the PC, as specified in

AQMD Rule 1303(b)(2).  As shown in Table 2 below, CPV Sentinel has already purchased

adequate amounts of VOC ERCs to offset 412 lbs/day of VOC emissions and will provide an

additional 29 lbs/day of VOC ERCs prior to issuance of the final Title V permit to cover the

maximum offset liability of 441 lbs/day of VOC emissions (see Table 1 above).

Table 2 – Maximum VOC Emission Rates and Offsets

ERC

Certificate

No.

ERC Certificate Registered Owner ERC Certificate Amount  

(lbs/day)

AQ007877 Tenasko   348

AQ007879 Tenasko   64

Total Amounts of VOC ERCs Provided 412

Additional VOC ERCs to be Provided 29

Total Emissions & VOC ERCs   441
3 | Page

NOX Emissions

The CPV Sentinel project complies with all of the NOx offset requirements (at a 1.0‐to‐1.0 offset

ratio) through requiring CPV Sentinel to hold sufficient NOx RTCs to offset the annual emission

increase for the first year of operation prior to commencement of initial operation, as specified

in Rule 2005(b)(2). AQMD provides a programmatic demonstration, as approved by EPA, in

March of each year in its Annual  RECLAIM Audit report to the Governing Board that the 1.2 to

1 offset ratio required by federal law is met on an aggregate basis for RECLAIM new and

modified sources. CPV Sentinel shall also, at the commencement of each subsequent

compliance year, hold NOx RTCs equal to the amount required by permit conditions, as

specified in Rule 2005(f)(1).

CO Emissions

The CPV Sentinel project complies with the CO offset requirements on the basis that the SSAB is

not classified as “Nonattainment” for federal and state ambient air quality standards for CO.

(SSAB is classified as Attainment for state and Unclassified/Attainment for federal.) Therefore  

offsets are not required.   Also the maximum worst case yearly CO emission is 188 tons/year,

which is below the PSD threshold of 250 tons/year.  Therefore, no PSD permit is required.

PM2.5 Emissions

The CPV Sentinel project complies with the PM2.5 offset requirements on the basis that the

SSAB is not classified as “Nonattainment” for federal and state ambient air quality standards for

PM2.5. (SSAB is Unclassified for state and Unclassified/Attainment for federal.)  Therefore,

offsets are not required.  Also the maximum worst case yearly PM2.5 emission, even assuming

that all (100%) of the PM10 emissions are PM2.5, is 59.06 tons/year, which is below the PSD

threshold of 250 tons/year.  Therefore, no PSD permit is required.  

PM10 and SOx Emissions

Emission Offsets ‐ The SSAB is attainment with both federal and state SO2 and Sulfate ambient

air quality standards, as applicable.  However, SO2 is also considered a precursor to PM10.  

Presently the SSAB is still designated as “Nonattainment” with both federal and state PM10

ambient air quality standards.   
4 | Page

CPV Sentinel is obtaining offsets for both PM10 and SOx from the AQMD internal bank pursuant

to AB 1318.  Under federal law any required PM10 and SOx offsets have to be provided at an

offset ratio of 1.0‐to‐1.0.  In addition, California state law offset requirements, if applicable to

any project, requires actual (not maximum potential) emissions to be offset at the same 1.0‐to‐

1.0 offset ratio as the actual emissions.  Therefore, the maximum amount of offsets that are

being provided for the CPV Sentinel project’s emissions in the initial commissioning year1 are

118,120 lbs/year and 13,928 lbs/year of PM10 and SOx, respectively, as shown earlier in Table

1.   These amounts of offsets are obtained by CPV Sentinel and provided by AQMD from

AQMD’s internal emission credit accounts pursuant to AB 1318.

In Attachment I, AQMD has provided an internal emission offset account tracking system

pursuant to AB 1318.  The amounts of emission offsets presently deposited by AQMD in the AB

1318 tracking system cover the amounts needed by CPV Sentinel (please see Attachment 1).  As

indicated earlier, the offset evaluations for PM10 and SOx and the AB 1318 tracking system will

also be submitted to EPA in the form of a SIP revision.   

Redesignation & Maintenance Plan – Although CPV Sentinel is obtaining and AQMD is

providing emission offsets for PM10 and SOx (as precursor to PM10), the AQMD and CARB

Governing Boards have already approved the SSAB PM10 Redesignation and Maintenance Plan

(RMP) for submittal to EPA  for inclusion into the SIP.  Under federal NSR offsets are required

prior to start of operation.  Upon EPA’s approval of this RMP and redesignation of SSAB as

attainment with federal PM10 NAAQS, this project will not be subject to the Nonattainment

federal NSR requirements and will not be required to provide any PM10 or SOx offsets to meet

federal requirements.   

In addition, the CPV Sentinel project maximum worst case year (i.e. the initial commissioning

year) PM10 emissions are 118,120 lbs/year (or 59.06 tons/year).  The federal Major Source

threshold for PM10 offsets is 70 tons/year, below which no offsets are required under federal

NSR regulations.  Although the CPV Sentinel project maximum potential to emit PM10

emissions are below the federal Major Source threshold for offsets, CPV Sentinel is obtaining

offsets for both PM10 and SOx from the AQMD internal bank pursuant to AB 1318.  

                                                           

1 Although the amount of maximum annual emissions after the initial commissioning and start up are 112,180

lbs/year of PM10 and 13,560 lbs/year of SOx, the amount of offsets that are provided from AQMD’s internal offset

account for the CPV Sentinel project are to offset the commissioning year’s emissions of 118,120 lbs/year and

13,928 lbs/year of PM10 and SOx, respectively.  This is the maximum worst case, because it assumes that all eight

gas turbines are commissioned and started up in the same year.
5 | Page

Attachment I

Assembly Bill (AB) 1318 – Tracking System

OBJECTIVES:

AB 1318, which went into effect on January 1, 2010, requires AQMD, upon making a specified finding, to

transfer SOx and PM10 emission offsets from its internal offset accounts to eligible electric generating

facilities.  In implementing this emission offset transfer, AB 1318 requires AQMD to rely on the internal

offset tracking system used prior to adoption of Rule 1315 or a new tracking system approved by EPA.  

Therefore, this new AB 1318 offset tracking system will be submitted to EPA for approval and inclusion

into the SIP.   

AB 1318 PROVISIONS:

The specified findings required to be made in order to determine whether or not an electrical generating

facility is eligible to receive emission offsets from AQMD’s internal offset account are as follows:

• “In order to be eligible for emission reduction credits pursuant to this section, an electrical

generating facility shall meet all of the following requirements:” [Health & Safety Code Section

40440.14(d)]

o “Be subject to the permitting jurisdiction of the State Energy Resources Conservation

and Development Commission.” [Health & Safety Code Section 40440.14(d)(1)]

o “Have a purchase agreement, executed on or before December 31, 2008, to provide

electricity to a public utility, as defined in Section 216 of the Public Utilities Code,

subject to regulation by the Public Utilities Commission, for use within the Los Angeles

Basin Local Reliability Area.” [Health & Safety Code Section 40440.14(d)(2)]

o “Be under the jurisdiction of the south coast district, but not within the South Coast

Air Basin.” [Health & Safety Code Section 40440.14(d)(3)]

AQMD’s requirements for implementation of the emission offset credit transfer from its internal offset

credit account and offset tracking system, as specified in AB1318, are as follows:

  

• “The executive officer of the south coast district, upon finding that the eligible electrical

generating facility proposed for certification by the State Energy Resources Conservation and

Development Commission meets the requirements of the applicable new source review rule

and all other applicable district regulations that must be met under Section 1744.5 of Title 20

of the California Code of Regulations, shall credit to the south coast district's internal emission

credit accounts and transfer from the south coast district's internal emission credit accounts

to eligible electrical generating facilities emission credits in the full amounts needed to issue

permits for eligible electrical generating facilities to meet requirements for sulfur oxides (SOx)

and particulate matter (PM2.5 and PM10) emissions.” [Health and Safety Code Section

40440.14(a)]
6 | Page

• In implementing this permitting action, “the south coast district shall rely on the offset tracking

system used prior to the adoption of Rule 1315 of the south coast district until a new tracking

system is approved by the United States Environmental Protection Agency and is in effect, at

which point that new system shall be used by the south coast district.” [Health & Safety Code

Section 40440.14(b)(1)]

• “In addition to using the prior offset tracking system, the district shall also make use of any

emission credits that have resulted from emission reductions and shutdowns from minor

sources since 1990.  The district shall make any necessary submissions to the United States

Environmental Protection Agency with regard to the crediting and use of emission reductions

and shutdowns from minor sources.” [Health & Safety Code Section 40440.14(b)(2)]

In addition, AQMD is required to report the emission offsets to CEC as follows:

• “Within 60 days of the effective date of this section, for each eligible electrical generating

facility, the south coast district shall report to the State Energy Resources Conservation and

Development Commission the emission credits to be credited and transferred pursuant to

subdivision (a). The State Energy Resources Conservation and Development Commission shall

determine whether the emission credits to be credited and transferred satisfy all applicable

legal requirements. In the exercise of its regulatory responsibilities under its power facility

and site certification authority, the State Energy Resources Conservation and Development

Commission shall not certify an eligible electrical generation facility if it determines that the

credit and transfer by the south coast district do not satisfy all applicable legal requirements.”

[Health & Safety Code Section 40440.14(c)]

Finally, the transfer of offsets to an electrical generating facility is subject to the following:

• “The executive officer shall not transfer emission reduction credits to an electrical generating

facility pursuant to this section until the receipt of payment of the mitigation fees set forth in

the south coast district's Rule 1309.1, as adopted on August 3, 2007. The mitigation fees shall

only be used for emission reduction purposes. The south coast district shall ensure that at

least 30 percent of the fees are used for emission reductions in areas within close proximity to

the electrical generating facility and at least 30 percent are used for emission reductions in

areas designated as "Environmental Justice Areas" in Rule 1309.1.” [Health & Safety Code

Section 40440.14(e)]

AB 1318 TRACKING SYSTEM:

For the purposes of AB 1318 Tracking System, AQMD has identified a series of emission offsets for PM10

and SOx which have been created as a result of reductions from permitted equipment that permanently

ceased operation in AQMD.  These offsets all meet the integrity criteria for qualifying as offsets,

meaning they are all Real, Permanent, Quantifiable, Enforceable and Surplus.  These offsets are all result

of emission reductions from permitted equipment that permanently ceased operation in AQMD and the

AQMD has not issued any ERCs to the companies who operated the equipment as a result of the
7 | Page

reductions.  These PM10 and SOx offsets have been removed from the AQMD’s internal offset accounts

and have not been used by any other source permitted by AQMD.

The amounts of emission offsets are based on actual PM10 and SOx emissions reported to AQMD under

AQMD’s Annual Emissions Reporting Program.  In addition, for each source of credit, the equipment has

been shutdown and the permits have been inactivated by AQMD.  The emission reductions have

occurred during the calendar years 2002 and 2008 for PM10 credits and during the period of calendar

years 2002 through 2006 for SOx credits.  

Tables A and B below include a listing of the PM10 and SOx offsets, respectively, deposited in the AB

1318 Tracking System for use by electrical generating facilities eligible to use the offsets pursuant to AB

1318 requirements.  Tables A and B below show the PM10 and  SOx offsets in the AB 1318 Tracking

System available for use by eligible electric generating facilities.  These offsets are available for transfer

to any electrical generating facility which is eligible to obtain offsets from AQMD and upon receipt of

payment of mitigation fees set forth in AQMD’s Rule 1309.1, as adopted on August 3, 2007, pursuant to

AB 1318.

   
8 | Page

Table A ‐ PM10 Reductions from Sources Which Ceased Operation

Company Name Location Equipment Description

Emission

Credits

(lb/year)

AAA GLASS CORP LOS ANGELES             GLASS MELTING FURNACE 1,877.8

AES ALAMITOS, LLC LONG BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 604.8

AES ALAMITOS, LLC LONG BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 604.8

AES ALAMITOS, LLC LONG BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 604.8

AES ALAMITOS, LLC LONG BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 604.8

AES HUNTINGTON BEACH, LLC

HUNTINGTON

BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 1,417.2

AES HUNTINGTON BEACH, LLC

HUNTINGTON

BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 1,417.2

AES HUNTINGTON BEACH, LLC

HUNTINGTON

BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 1,417.2

ANAHEIM MARRIOTT HOTEL ANAHEIM                   BOILER ‐ NATURAL GAS 20.4

ANAHEIM MARRIOTT HOTEL ANAHEIM                   BOILER ‐ NATURAL GAS 20.4

ANAHEIM MARRIOTT HOTEL ANAHEIM                   BOILER ‐ NATURAL GAS 19.3

ANAHEIM MARRIOTT HOTEL ANAHEIM                   BOILER ‐ NATURAL GAS 19.3

ASSOCIATED READY MIXED CONCRETE

INC   CORONA                    CONCRETE BATCH EQUIPMENT 27.4

ASTECHENGINEEREDPRODUCTSINC. SANTA ANA                ABRASIVE BLASTING ‐ OPEN 16.0

AURORA MODULAR INDUSTRIES MORENO VALLEY      OPEN SPRAY EQUIPMENT 451.4

AURORA MODULAR INDUSTRIES MORENO VALLEY      OPEN SPRAY EQUIPMENT 451.4

AURORA MODULAR INDUSTRIES MORENO VALLEY      OPEN SPRAY EQUIPMENT 451.4

AURORA MODULAR INDUSTRIES MORENO VALLEY      OPEN SPRAY EQUIPMENT 451.4

AURORA MODULAR INDUSTRIES MORENO VALLEY      OPEN SPRAY EQUIPMENT 451.4

BLACKHAWK FURNITURE, INC RIVERSIDE                 SPRAY BOOTH 604.0

BOCCHI LABORATORIES INC WALNUT                    BOILER ‐ NATURAL GAS 87.6

CALIFORNIA PORTLAND CEMENT CO  

SAN JUAN

CAPISTRANO        CEMENT STORAGE SILO 12.0

CBS INC LOS ANGELES             BOILER ‐ NATURAL GAS/OIL 89.6

CBS INC LOS ANGELES             BOILER ‐ NATURAL GAS/OIL 89.6

CENTURY RIM CORP BREA                        BAKERY OVEN 32.1

CENTURY RIM CORP BREA                       SPRAY BOOTH 5,272.0

CHANDLER AGGREGATES CORONA                    AGGREGATE PRODUCTION 1,411.2

CLEAN STEEL INC LONG BEACH             MATERIAL SIZE REDUCTION 4,112.5

CMC PRINTED BAG INC   WHITTIER                  AFTERBURNER 29.0

COLOR MASTER PRINTEX, INC   VERNON                    TENTER FRAME OVEN 75.6

COLOR MASTER PRINTEX, INC   VERNON                    BOILER ‐ NATURAL GAS 75.6
9 | Page

Company Name Location Equipment Description

Emission

Credits

(lb/year)

COLOR MASTER PRINTEX, INC   VERNON                    BOILER ‐ NATURAL GAS 75.6

COLORGRAPHICS   LOS ANGELES             PRINTING PRESS ‐ HEAT SET 5.0

COLORGRAPHICS   LOS ANGELES             PRINTING PRESS ‐ HEAT SET 5.0

COLORGRAPHICS   LOS ANGELES             PRINTING PRESS ‐ HEAT SET 5.0

COLORGRAPHICS   LOS ANGELES             AFTERBURNER 5.0

COMMONWEALTH ALUMINUM

CONCAST INC TORRANCE                

COATING EQUIPMENT WITH

AFTERBURNER 671.7

CREST GRAPHICS INC COMMERCE               PRINTING PRESS WITH AFTERBURNER 48.7

CREST GRAPHICS INC COMMERCE               DRYING OVEN WITH AFTERBURNER 77.0

DIAMOND PACIFIC PRODUCTS CO PERRIS                     BOILER ‐ NATURAL GAS 92.8

DOUGLAS FURNITURE OF CALIFORNIA

LLC REDONDO BEACH    

BOILER ‐ WOOD FIRED WITH

BAGHOUSE 32.5

DYNAMITE INC DIAMOND BAR          PORTABLE DIESEL ICE   1,704.0

DYNAMITE INC DIAMOND BAR          PORTABLE DIESEL ICE   1,118.0

EL CAMINO COLLEGE TORRANCE                 BOILER ‐ NATURAL GAS 192.0

ELSINORE READY‐MIX CO INC LAKE ELSINORE         AGGREGATE SIZE REDUCTION 13.7

EQUITABLE REAL EST/COMPASS MGMT

LEASING IRVINE                     BOILER ‐ NATURAL GAS 4.9

FALCON FOAM, A DIV OF ATLAS

ROOFING CORP LOS ANGELES             BOILER ‐ NATURAL GAS 293.1

FALCON FOAM, A DIV OF ATLAS

ROOFING CORP LOS ANGELES             AFTERBURNER 230.2

FORD AUTO BODY INC SAN FERNANDO        SPRAY BOOTH 6.0

FS PRECISION TECH LLC   COMPTON                  ABRASIVE BLASTING CABINET 77.2

FS PRECISION TECH LLC   COMPTON                  ABRASIVE BLASTING CABINET 30.3

FS PRECISION TECH LLC   COMPTON                  ABRASIVE BLASTING CABINET 30.3

FS PRECISION TECH LLC   COMPTON                  ABRASIVE BLASTING CABINET 30.3

GREAT AMERICAN PICTURE FRAME CO   LOS ANGELES             OPEN SPRAY EQUIPMENT 104.5

GREAT AMERICAN PICTURE FRAME CO   LOS ANGELES             SPRAY BOOTH 104.5

GREAT AMERICAN PICTURE FRAME CO   LOS ANGELES             OPEN SPRAY EQUIPMENT 104.5

HOLGA INC   VAN NUYS                  PAINT BURNOFF FURNACE 18.6

HONEYWELL INTERNATIONAL INC   TORRANCE                 JET ENGINE TEST EQUIPMENT 59.0

INTERMETRO INDUSTRIES CORP

RANCHO

CUCAMONGA          HEAT TREATING FURNACE 65.0

INTERMETRO INDUSTRIES CORP

RANCHO

CUCAMONGA          NICKEL PLATING TANK 17.0

INTERMETRO INDUSTRIES CORP

RANCHO

CUCAMONGA          BOILER ‐ NATURAL GAS 87.5

INTERSTATE BRANDS CORP/DICARLO SAN PEDRO                 BAKERY OVEN 131.2

INTERSTATE BRANDS CORP/DICARLO SAN PEDRO                 BAKERY OVEN 133.5
10 | Page

Company Name Location Equipment Description

Emission

Credits

(lb/year)

INTERSTATE BRANDS CORP/DICARLO SAN PEDRO                 BAKERY OVEN 93.0

INTERSTATE BRANDS CORP/DICARLO SAN PEDRO                BOILER ‐ NATURAL GAS 109.0

KMC WHEEL CO INC RIVERSIDE                 ALUMINUM FURNACE 2,940.8

KRACO ENTERPRISES INC COMPTON                  BOILER  ‐ OIL 429.5

KRAFT FOODS NORTH

AMERICA/NABISCO DIV BUENA PARK              BAKERY OVEN 110.1

KRAFT FOODS NORTH

AMERICA/NABISCO DIV BUENA PARK              BAKERY OVEN 110.1

KRAFT FOODS NORTH

AMERICA/NABISCO DIV BUENA PARK              BAKERY OVEN 110.1

LITHOGRAPHIX INC LOS ANGELES             AFTERBURNER 15.0

LITTLE COMPANY OF MARY HOSPITAL TORRANCE                 BOILER ‐ NATURAL GAS/OIL 404.7

LONG BEACH AQUARIUM OF THE

PACIFIC LONG BEACH             HEATER/FURNACE ‐ NATURAL GAS 301.3

MATTHEWS INTERNATIONAL CORP   ROMOLAND              

FOUNDRY SAND STORAGE WITH

BAGHOUSE 9,460.5

MOUNTAINVIEW GENERATING STATION REDLANDS UTILITY BOILER ‐ NATURAL GAS/OIL 3,365.5

MOUNTAINVIEW GENERATING STATION REDLANDS UTILITY BOILER ‐ NATURAL GAS/OIL 3,365.5

NEVILLE CHEM CO ANAHEIM                   CHEMICAL STORAGE TANK 268.4

NEVILLE CHEM CO ANAHEIM                   BOILER ‐ NATURAL GAS 239.7

OLDCASTLE WESTILE, INC. CORONA CEMENT SLURRY SYSTEM 2,111.0

ONE WILSHIRE, CARLYLE ONE WILSHIRE,

LLC LOS ANGELES             BOILER ‐ NATURAL GAS 19.1

ONTARIO SANDBLASTING CO ONTARIO                   ABRASIVE BLASTING CABINET 12.8

ONTARIO SANDBLASTING CO ONTARIO                  

ABRASIVE BLASTING CABINET WITH

BAGHOUSE 12.8

ONTARIO SANDBLASTING CO ONTARIO                  

ABRASIVE BLASTING CABINET WITH

BAGHOUSE 12.8

ORTIZ ENTERPRISES INC

VARIOUS

LOCATIONS AGGREGATE CRUSHING SYSTEM 1,233.0

PACIFIC SUN CASUAL FURN DIV OF PAC

OUTDO HEMET                      POWDER COATING SPRAY BOOTH 30.0

PARADISE TEXTILE CO   CHINO                      HEATER/FURNACE ‐ NATURAL GAS 1,109.5

PLASTI PERSONALITIES INC HARBOR CITY             BOILER ‐ NATURAL GAS 9.4

POLYCLAD LAMINATES INC SANTA ANA                BOILER ‐ NATURAL GAS 291.6

POLYCLAD LAMINATES INC SANTA ANA                BOILER ‐ NATURAL GAS 291.6

PRATT & WHITNEY ROCKETDYNE, INC. CANOGA PARK          BOILER ‐ NATURAL GAS 30.5

RELIANT ENERGY ETIWANDA, INC. ETIWANDA TURBINE ENGINE ‐ NATURAL GAS/OIL 1,959.1

RELIANT ENERGY ETIWANDA, INC. ETIWANDA TURBINE ENGINE ‐ NATURAL GAS/OIL 1,959.1

RELIANT ENERGY ETIWANDA, INC. ETIWANDA TURBINE ENGINE ‐ NATURAL GAS/OIL 1,959.1

RELIANT ENERGY ETIWANDA, INC. ETIWANDA TURBINE ENGINE ‐ NATURAL GAS/OIL 1,959.1
11 | Page

Company Name Location Equipment Description

Emission

Credits

(lb/year)

RELIANT ENERGY ETIWANDA, INC. ETIWANDA UTILITY BOILER ‐ NATURAL GAS/OIL 33,079.3

RELIANT ENERGY ETIWANDA, INC. ETIWANDA UTILITY BOILER ‐ NATURAL GAS/OIL 33,079.3

SCHEU MANUFACTURING COMPANY

RANCHO

CUCAMONGA          CURING OVEN 13.0

SHAWCOR PIPE PROTECTION LLC. FONTANA ABRASIVE BLASTING ‐ OPEN 7,677.0

SMURFIT‐STONE CONTAINER

ENTERPRISES  

SANTA FE

SPRINGS           BOILER ‐ NATURAL GAS/LPG   237.0

STATEWIDE SANDBLASTING

VARIOUS

LOCATIONS ABRASIVE BLASTING ‐ OPEN 2,313.0

SUNLAW COGENERATION PARTNERS I VERNON                    TURBINE ENGINE ‐ NATURAL GAS 1,295.4

SUNLAW COGENERATION PARTNERS I VERNON                    TURBINE ENGINE ‐ NATURAL GAS 2,467.4

TABC, INC LONG BEACH             CURING OVEN 121.5

TELAIR INTERNATIONAL

RANCHO

DOMINGUEZ           SPRAY BOOTH 69.5

THE BOEING COMPANY SEAL BEACH               EMERGENCY ICE ‐  DIESEL FIRE PUMP 868.0

TREND OFFSET PRINTING SERVICES, INC LOS ALAMITOS          AFTERBURNER 42.0

UNIVERSAL DIE CASTING CO VERNON                    BRASS CRUCIBLE 370.5

US POSTAL SERVICE, SANTA CLARITA

CENTER SANTA CLARITA         HEATER/FURNACE ‐ NATURAL GAS 66.0

VALMONT COATINGS, CALWEST  GALV LONG BEACH             PORTABLE DIESEL ICE   2.7

VOUGHT AIRCRAFT INDUSTRIES HAWTHORNE            BOILER ‐ NATURAL GAS 51.0

WEBB‐MASSEY CO INC ORANGE                    SPRAY BOOTH 572.7

WEBB‐MASSEY CO INC ORANGE                    SPRAY BOOTH 572.7

WHITEWATER ROCK & SUPPLY CO WHITE WATER ROCK CRUSHING SYSTEM 1,460.0

WINGS WEST INC SANTA ANA                SPRAY BOOTH 498.0

WINGS WEST INC SANTA ANA                SPRAY BOOTH 498.0

WINGS WEST INC SANTA ANA                SPRAY BOOTH 498.0

WOODARD, LLC. ONTARIO                   POWDER COATING OVEN 10.2

WOODARD, LLC. ONTARIO                   DRYING OVEN 5.1

Total 148,582.7

   
12 | Page

Table B ‐ SOx Reductions from Sources Which Ceased Operation

Company Name Location Equipment Description

Emission

Credits

(lb/year)

AAA GLASS CORP LOS ANGELES             GLASS MELTING FURNACE 6,295.4

AES ALAMITOS, LLC LONG BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 108.0

AES ALAMITOS, LLC LONG BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 108.0

AES ALAMITOS, LLC LONG BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 108.0

AES ALAMITOS, LLC LONG BEACH TURBINE ENGINE ‐ NATURAL GAS/OIL 108.0

CBS INC LOS ANGELES             BOILER ‐ NATURAL GAS/OIL 7.1

CBS INC LOS ANGELES             BOILER ‐ NATURAL GAS/OIL 7.1

CENTURY RIM CORP BREA                        BAKERY OVEN 3.5

COLOR AMERICA TEXTILE PROCESSING

INC LOS ANGELES             CARPET PROCESSING SYS WITH ESP 3.3

EL CAMINO COLLEGE TORRANCE                  BOILER ‐ NATURAL GAS 15.2

GATEWAY SANDBLASTING

VARIOUS

LOCATIONS OPEN ABRASIVE BLASTING 455.2

HOLGA INC   VAN NUYS                  PAINT BURNOFF FURNACE 2.0

HONEYWELL INTERNATIONAL INC   TORRANCE                  JET ENGINE TEST EQUIPMENT 4.5

MOUNTAINVIEW GENERATING

STATION REDLANDS UTILITY BOILER ‐ NATURAL GAS/OIL 265.5

MOUNTAINVIEW GENERATING

STATION REDLANDS UTILITY BOILER ‐ NATURAL GAS/OIL 265.5

RELIANT ENERGY ETIWANDA, INC. ETIWANDA TURBINE ENGINE ‐ NATURAL GAS/OIL 169.6

RELIANT ENERGY ETIWANDA, INC. ETIWANDA TURBINE ENGINE ‐ NATURAL GAS/OIL 169.6

RELIANT ENERGY ETIWANDA, INC. ETIWANDA TURBINE ENGINE ‐ NATURAL GAS/OIL 169.6

RELIANT ENERGY ETIWANDA, INC. ETIWANDA TURBINE ENGINE ‐ NATURAL GAS/OIL 169.6

RELIANT ENERGY ETIWANDA, INC. ETIWANDA UTILITY BOILER ‐ NATURAL GAS/OIL 2,611.3

RELIANT ENERGY ETIWANDA, INC. ETIWANDA UTILITY BOILER ‐ NATURAL GAS/OIL 2,611.3

SUNLAW COGENERATION PARTNERS I VERNON                    TURBINE ENGINE ‐ NATURAL GAS 2,506.4

SUNLAW COGENERATION PARTNERS I VERNON                    TURBINE ENGINE ‐ NATURAL GAS 2,193.5

THE BOEING COMPANY SEAL BEACH                EMERGENCY ICE ‐  DIESEL FIRE PUMP 183.5

Total 18,540.6
1

 BEFORE THE ENERGY RESOURCES CONSERVATION AND DEVELOPMENT 

COMMISSION OF THE STATE OF CALIFORNIA

1516 NINTH STREET, SACRAMENTO, CA 95814 

1-800-822-6228 – WWW.ENERGY.CA.GOV

 

APPLICATION FOR CERTIFICATION FOR THE DOCKET NO. 07-AFC-3

CPV SENTINEL ENERGY PROJECT 

BY THE CPV SENTINEL, L.L.C PROOF OF SERVICE

(Revised 2/16/2010) 

APPLICANT 

CPV Sentinel, LLC 

Mark O. Turner, Director 

Competitive Power Ventures, Inc. 

55 2nd Street, Suite 525 

San Francisco, CA 94105 

mturner@cpv.com

APPLICANT’S CONSULTANT

Dale Shileikis - URS Corporation 

221 Main Street, Suite 600 

San Francisco, CA 94105-1916 

dale_shileikis@urscorp.com

COUNSEL FOR APPLICANT

Michael J. Carroll 

LATHAM & WATKINS LLP 

650 Town Center Drive, 20th Floor 

Costa Mesa, CA 92626-1925 

michael.carroll@lw.com

INTERESTED AGENCIES

 California ISO 

e-recipient@caiso.com 

Mohsen Nazemi, PE 

South Coast AQMD 

21865 Copley Drive 

Diamond Bar, CA 91765-4178 

mnazemi@aqmd.gov

INTERVENORS

Angela Johnson Meszaros 

CA Communities Against Toxics 

1107 Fair Oaks Avenue, #246 

South Pasadena, CA 91030 

Angela@CleanAirMatters.net 

ENERGY COMMISSION 

JAMES D. BOYD 

Vice Chair and Presiding Member 

jboyd@energy.state.ca.us

Kenneth Celli, Hearing Officer 

kcelli@energy.state.ca.us 

John Kessler, Project Manager 

jkessler@energy.state.ca.us 

Caryn Holmes, Staff Counsel 

cholmes@energy.state.ca.us

*Jennifer Jennings 

Public Adviser 

publicadviser@energy.state.ca.us
2

DECLARATION OF SERVICE

I, Maria Santourdjian, declare that on March 4, 2010, I served and a filed copy of the attached SCAQMD Addendum 

to DOC and POC. The original document, filed with the Docket Unit, is accompanied by a copy of the most recent 

Proof of Service list, located on the web page for this project at: 

[http://www.energy.ca.gov/sitingcases/sentinel/index.html] 

The documents has been sent to both the other parties in this proceeding (as shown on the Proof of Service list) and 

to the Commission’s Docket Unit, in the following manner: 

(Check all that Apply)

For service to all other parties: 

 x sent electronically to all email addresses on the Proof of Service list; 

 by personal delivery; 

 x by delivering on this date, for mailing with the United States Postal Service with first-class postage thereon 

fully prepaid, to the name and address of the person served, for mailing that same day in the ordinary 

course of business; that the envelope was sealed and placed for collection and mailing on that date to those 

addresses NOT marked “email preferred.” 

AND 

For filing with the Energy Commission: 

 x sending an original paper copy and one electronic copy, mailed and emailed respectively, to the address 

below (preferred method); 

OR 

_____depositing in the mail an original and 12 paper copies, as follows: 

CALIFORNIA ENERGY COMMISSION 

Attn: Docket No. 07-AFC-3 

1516 Ninth Street, MS-4 

Sacramento, CA 95814-5512 

docket@energy.state.ca.us

I declare under penalty of perjury that the foregoing is true and correct, that I am employed in the county where this 

mailing occurred, and that I am over the age of 18 years and not a party to the proceeding. 

 Originally Signed by 

 Maria Santourdjian