Part 70 Operating Permit Amendment

Permit Amendment No.: 4911-103-0012-V-04-1 Effective Date: May 30, 2012 

Facility Name: Effingham County Power, LLC 

 3440 McCall Road 

 Rincon, Georgia 31326, Effingham County 

Mailing Address: 3440 McCall Road 

 Rincon, Georgia 31326 

Parent/Holding 

Company: 

Effingham County Power, LLC 

Facility AIRS Number: 04-13-103-00012

In accordance with the provisions of the Georgia Air Quality Act, O.C.G.A. Section 12-9-1, et seq and the Georgia 

Rules for Air Quality Control, Chapter 391-3-1, adopted pursuant to and in effect under the Act, the Permittee 

described above is issued a construction and operating permit for: 

A nominal net 668 megawatt (MW) combined cycle power generation facility to consist of two natural gas fired and 

distillate fuel oil fired combustion turbines (CTs) and associated heat recovery steam generators (HRSGs) 

including duct burners, one steam turbine, one fuel heater, one auxiliary boiler, one 10-cell mechanical draft 

cooling tower, one six-cell mechanical draft cooling tower and one distillate fuel oil storage tank. 

This Permit Amendment is conditioned upon compliance with all provisions of The Georgia Air Quality Act, 

O.C.G.A. Section 12-9-1, et seq, the Rules, Chapter 391-3-1, adopted and in effect under that Act, or any other 

condition of this Permit Amendment and Permit No. 4911-103-0012-V-04-0. Unless modified or revoked, this 

Permit Amendment expires upon issuance of the next Part 70 Permit for this source. 

This Permit Amendment may be subject to revocation, suspension, modification or amendment by the Director for 

cause including evidence of noncompliance with any of the above; or for any misrepresentation made in Application 

No. 19810 dated July 22, 2010; any other applications upon which this Permit Amendment or Permit No. 4911-103-

0012-V-04-0 are based; supporting data entered therein or attached thereto; or any subsequent submittal or 

supporting data; or for any alterations affecting the emissions from this source. 

This Permit Amendment is further subject to and conditioned upon the terms, conditions, limitations, standards, or 

schedules contained in or specified on the attached 35 pages, which pages are a part of this Permit Amendment, 

and which hereby become part of Permit No. 4911-103-0012-V-04-0. 

[Signed] 

Director 

Environmental Protection Division 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

i 

Table of Contents 

PART 1.0 FACILITY DESCRIPTION................................................................................................1

1.3 Process Description of Modification................................................................................................1

PART 3.0 REQUIREMENTS FOR EMISSION UNITS......................................................................2

3.1.1 Additional Emission Units ...............................................................................................................2

3.3 Equipment Federal Rule Standards ..................................................................................................4

PART 4.0 REQUIREMENTS FOR TESTING .................................................................................12

4.1 General Testing Requirements .......................................................................................................12

4.2 Specific Testing Requirements.......................................................................................................13

PART 5.0 REQUIREMENTS FOR MONITORING (RELATED TO DATA COLLECTION) ............17

5.2 Specific Monitoring Requirements ................................................................................................17

PART 6.0 OTHER RECORD KEEPING AND REPORTING REQUIREMENTS ............................21

6.1 General Record Keeping and Reporting Requirements .................................................................21

6.2 Specific Record Keeping and Reporting Requirements.................................................................24

PART 7.0 OTHER SPECIFIC REQUIREMENTS ...........................................................................33

7.9 Acid Rain Requirements ................................................................................................................33

ATTACHMENTS .................................................................................................................................35
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 1 of 35 

PART 1.0 FACILITY DESCRIPTION 

1.3 Process Description of Modification 

Effingham Power proposes to permit to construct and operate a nominal net 668-megawatt (MW) 

combined cycle power generation facility. The proposed project will consist of: 

• Two (2) nominal 180-MW GE Model 7FA combustion turbines (CTs) that will be operated in 

combined cycle mode fired primarily by natural gas with ultra low sulfur diesel fuel as backup fuel. 

The combustion turbines are equipped with dry low-NOx (DLN) combustor technology for natural 

gas combustion and water injection for fuel oil combustion; 

• Two (2) heat recovery steam generators (HRSGs) each equipped with a natural gas fired duct burner; 

• The combined CT/HRSG stack is equipped with selective catalytic reduction (SCR) and catalytic 

oxidation for control of nitrogen oxides (NOx) and carbon monoxide (CO)emissions, respectively; 

• One (1) 325-MW steam turbine generator; 

• One (1) natural gas-fired auxiliary boiler with a heat input capacity of 17 million British Thermal 

Units per hour (106 Btu/hr). The boiler will be equipped with low-NOx burners (LNBs) to control 

NOx emissions; 

• One (1) natural gas-fired fuel gas heater with a heat input capacity of 8.75 x 106

 Btu/hr. The heater 

will be equipped with low-NOx burners (LNBs) to control NOx emissions; 

• One (1) 10-cell cooling tower to provide cool water to the condensing steam turbine. The tower has 

a mechanical draft counter flow design and equipped with high efficiency drift eliminators to control 

particulate emissions; 

• One (1) 6-cell cooing tower to provide cool water for the inlet chiller systems. The tower has a 

mechanical draft counter flow design and equipped with high efficiency drift eliminators to control 

particulate emissions; 

• One (1) fixed-roof distillate fuel oil storage tank with a nominal capacity of 2,350,000 gallons. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 2 of 35 

PART 3.0 REQUIREMENTS FOR EMISSION UNITS 

Note: Except where an applicable requirement specifically states otherwise, the 

averaging times of any of the Emissions Limitations or Standards included in this 

permit are tied to or based on the run time(s) specified for the applicable 

reference test method(s) or procedures required for demonstrating compliance. 

3.1.1 Additional Emission Units 

Emission Units Specific Limitations/Requirements Air Pollution Control Devices 

ID No. Description Applicable 

Requirements/Standards 

Corresponding 

Permit Conditions ID No. Description 

AB2 Natural Gas-Fired 

Auxiliary Boiler with a 

17 x 106

 Btu/hr Heat 

Input Capacity 

40 CFR 52.21 

40 CFR 60 Subpart A 

40 CFR 60 Subpart Dc 

391-3-1-.02(2)(d) 

391-3-1-.02(2)(g) 

3.3.11, 3.3.12, 3.3.15, 

3.3.21, 3.3.30, 3.3.34, 

3.3.37, 3.3.38, 3.3.39, 

4.1.4, 5.2.9, 6.1.8, 

6.2.15, 6.2.17, 6.2.22, 

6.2.30, 6.2.31, 6.2.33, 

6.2.34, 6.2.35 

LNAB Low NOx Combustor AB 

FP2 Natural Gas-Fired Fuel 

Gas Heater with a 8.75 x 

106

 Btu/hr Heat Input 

Capacity 

40 CFR 52.21 

391-3-1-.02(2)(d) 

391-3-1-.02(2)(g) 

3.3.11, 3.3.12, 3.3.31, 

3.3.34, 3.3.37, 4.1.4, 

5.2.9, 6.1.8, 6.2.15, 

6.2.17, 6.2.30, 6.2.31, 

6.2.32, 6.2.34, 6.2.35 

LNFP Low NOx Combustor FP 

CT3 155,000 Gallon per 

Minute Mechanical Draft 

Counter Flow 10 Cell 

Cooling Tower 

40 CFR 52.21 3.3.11, 3.3.12, 3.3.40, 

4.1.4, 6.2.32, 6.2.33 DE3 Drift Eliminators 3 

CT4 10,042 Gallon per 

Minute Mechanical Draft 

Counter Flow 6 Cell 

Cooling Tower 

40 CFR 52.21 3.3.11, 3.3.12, 3.3.40, 

4.1.4, 6.2.32, 6.2.33 DE4 Drift Eliminators 4 

T01 2,350,000-Gallon Fixed 

Roof Distillate Fuel Oil 

Storage Tank 

40 CFR 52.21 3.3.11, 3.3.12, 3.3.41, 

4.1.4, 6.2.33 None NA 

CTG3 

GE 7FA Natural GasFired and Distillate Fuel 

Oil-Fired Combustion 

Turbine, nominal 180 

MW output 

40 CFR 52.21 

40 CFR 60 Subpart A 

40 CFR 60 Subpart KKKK 

Acid Rain 

391-3-1-.02(2)(b) 

391-3-1-.02(2)(g) 

3.3.11, 3.3.12, 3.3.13, 

3.3.14, 3.3.16, 3.3.17, 

3.3.18, 3.3.19, 3.3.22, 

3.3.23, 3.3.24, 3.3.25, 

3.3.26, 3.3.27, 3.3.28, 

3.3.32, 3.3.33, 3.3.35, 

3.3.36, 3.3.37, 4.1.4, 

4.2.1, 4.2.2, 4.2.3, 

4.2.4, 4.2.5, 5.2.8, 

5.2.9, 5.2.10, 5.2.11, 

5.2.12, 5.2.13, 5.2.14, 

6.1.8, 6.2.15, 6.2.16, 

6.2.17, 6.2.18, 6.2.19, 

6.2.21, 6.2.23, 6.2.24, 

6.2.25, 6.2.26, 6.2.27, 

6.2.28, 6.2.29, 6.2.30, 

6.2.31, 6.2.33, 6.2.34, 

6.2.35, 7.9 

SCR3, 

WI3, 

CO3, 

DLNT3 

Selective Catalytic 

Reduction (SCR), 

Water Injection System, 

Catalytic Oxidizer, 

Dry Low NOx

 Combustor 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 3 of 35 

Emission Units Specific Limitations/Requirements Air Pollution Control Devices 

ID No. Description Applicable 

Requirements/Standards 

Corresponding 

Permit Conditions ID No. Description 

DB3 

HRSG, for CTG3 with 

Supplemental Natural 

Gas- Fired Duct Burner 

with a 470 x 106 Btu/hr 

Heat Input Capacity 

40 CFR 52.21 

40 CFR 60 Subpart A 

40 CFR 60 Subpart KKKK 

391-3-1-.02(2)(g) 

391-3-1-.02(2)(b) 

3.3.11, 3.3.12, 3.3.14, 

3.3.16, 3.3.20, 3.3.24, 

3.3.25, 3.3.26, 3.3.29, 

3.3.32, 3.3.34, 3.3.35, 

3.3.36, 3.3.37, 4.1.4, 

4.2.1, 4.2.2, 4.2.3, 

4.2.4, 4.2.5, 5.2.8, 

5.2.9, 5.2.10, 5.2.11, 

5.2.12, 5.2.13, 5.2.14, 

6.1.8, 6.2.15, 6.2.17, 

6.2.18, 6.2.20, 6.2.23, 

6.2.24, 6.2.25, 6.2.26, 

6.2.27, 6.2.28, 6.2.29, 

6.2.30, 6.2.31, 6.2.33, 

6.2.34, 6.2.35 

SCR3, 

CO3 

Selective Catalytic 

Reduction (SCR), 

Catalytic Oxidizer 

CTG4 

GE 7FA Natural GasFired and Distillate Fuel 

Oil-Fired Combustion 

Turbine, nominal 180 

MW output 

40 CFR 52.21 

40 CFR 60 Subpart A 

40 CFR 60 Subpart KKKK 

Acid Rain 

391-3-1-.02(2)(b) 

391-3-1-.02(2)(g) 

3.3.11, 3.3.12, 3.3.13, 

3.3.14, 3.3.16, 3.3.17, 

3.3.18, 3.3.19, 3.3.22, 

3.3.23, 3.3.24, 3.3.25, 

3.3.26, 3.3.27, 3.3.28, 

3.3.32, 3.3.33, 3.3.35, 

3.3.36, 3.3.37, 4.1.4, 

4.2.1, 4.2.2, 4.2.3, 

4.2.4, 4.2.5, 5.2.8, 

5.2.9, 5.2.10, 5.2.11, 

5.2.12, 5.2.13, 5.2.14, 

6.1.8, 6.2.15, 6.2.16, 

6.2.17, 6.2.18, 6.2.19, 

6.2.21, 6.2.23, 6.2.24, 

6.2.25, 6.2.26, 6.2.27, 

6.2.28, 6.2.29, 6.2.30, 

6.2.31, 6.2.33, 6.2.34, 

6.2.35, 7.9 

SCR4, 

WI4, 

CO4, 

DLNT4 

Selective Catalytic 

Reduction (SCR), 

Water Injection System, 

Catalytic Oxidizer, 

Dry Low NOx Combustor 

DB4 

HRSG, for CTG4 with 

Supplemental Natural 

Gas- Fired Duct Burner 

with a 470 x 106 Btu/hr 

Heat Input Capacity 

40 CFR 52.21 

40 CFR 60 Subpart A 

40 CFR 60 Subpart KKKK 

391-3-1-.02(2)(b) 

391-3-1-.02(2)(g) 

3.3.11, 3.3.12, 3.3.14, 

3.3.16, 3.3.20, 3.3.24, 

3.3.25, 3.3.26, 3.3.29, 

3.3.32, 3.3.34, 3.3.35, 

3.3.36, 3.3.37, 4.1.4, 

4.2.1, 4.2.2, 4.2.3, 

4.2.4, 4.2.5, 5.2.8, 

5.2.9, 5.2.10, 5.2.11, 

5.2.12, 5.2.13, 5.2.14, 

6.1.8, 6.2.15, 6.2.17, 

6.2.18, 6.2.20, 6.2.23, 

6.2.24, 6.2.25, 6.2.26, 

6.2.27, 6.2.28, 6.2.29, 

6.2.30, 6.2.31, 6.2.33, 

6.2.34, 6.2.35 

SCR4, 

CO4 

Selective Catalytic 

Reduction (SCR), 

Catalytic Oxidizer 

* Generally applicable requirements contained in this permit may also apply to emission units listed above. 

The lists of applicable requirements/standards and corresponding permit conditions are intended as a 

compliance tool and may not be definitive.
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 4 of 35 

3.3 Equipment Federal Rule Standards 

NEW CONDITIONS 

3.3.11 The Permittee shall construct and operate the source or modification as defined in 

Application No. 19810 that is subject to Georgia Rule 391-3-1-.02(7) in accordance 

with the application submitted pursuant to that rule. If the Permittee constructs or 

operates a source or modification not in accordance with the application submitted 

pursuant to that rule or with the terms of any approval to construct, the Permittee shall 

be subject to appropriate enforcement action. 

[40 CFR 52.21(r)(1)] 

3.3.12 Approval to construct source or modification as defined in Application No. 19810 

shall become invalid if construction is not commenced within 18 months after receipt of 

such approval, if construction is discontinued for a period of 18 months or more, or if 

construction is not completed within a reasonable time. The Director may extend the 

18-month period upon a satisfactory showing that an extension is justified. This 

provision does not apply to the time period between construction of the approved 

phases of a phased construction project; each phase must commence construction 

within 18 months of the projected and approved commencement date. 

[40 CFR 52.21(r)(2)] 

3.3.13 The Permittee shall comply with all applicable provisions of the Acid Rain Program as 

found in 40 CFR Part 72 “Permit Regulations”, 40 CFR Part 73 “Sulfur Dioxide 

Allowance System”, 40 CFR Part 75 “Continuous Emissions Monitoring”, and 40 CFR 

Part 77 “Excess Emissions” for operation of each of the combustion turbines (emission 

unit ID Nos: CTG3 and CTG4). 

[40 CFR Parts 72, 73, 75, and 77] 

3.3.14 The Permittee shall comply with all applicable provisions of the New Source 

Performance Standards (NSPS) as found in 40 CFR 60 Subpart A - "General 

Provisions" and 40 CFR 60 Subpart KKKK - "Standards of Performance for Stationary 

Combustion Turbines," for operation of each of the combustion turbines and duct 

burners (emission unit ID Nos: CTG3, CTG4, DB3, and DB4). 

[40 CFR 60 Subparts A and KKKK] 

3.3.15 The Permittee shall comply with all applicable provisions of the New Source 

Performance Standards (NSPS) as found in 40 CFR 60 Subpart A "General Provisions" 

and 40 CFR 60 Subpart Dc "Standards of Performance for Small IndustrialCommercial-Institutional Steam Generating Units," for operation of the Auxiliary 

Boiler with emission unit ID No. AB2. 

[40 CFR 60 Subparts A and Dc] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 5 of 35 

3.3.16 The following stacks are defined for purposes of this Permit: 

[40 CFR 52.21(j)] 

a. Combustion Turbine with emission unit ID No. CTG3 and Duct Burner with 

emission unit ID No. DB3 share a common stack. 

b. Combustion Turbine with emission unit ID No. CTG4 and Duct Burner with 

emission unit ID No. DB4 share a common stack. 

3.3.17 The following definitions of startup and shutdown, as used in this Permit, shall apply to 

combustion turbines with emission unit ID Nos. CTG3 and CTG4: 

[40 CFR 52.21(j)] 

a. Cold startup is defined as a startup to combined cycle operation following a 

complete shutdown lasting more than forty-eight hours. 

i. The Permittee shall not combust fuel oil in the combustion turbines (emission 

unit ID Nos. CTG3 and CTG4) until the turbine load is at least 10.4 percent of 

maximum load adjusted for ambient conditions. 

ii. Time allocated to a cold startup for fuel oil combustion is zero to 300 minutes 

or the time for reception of an operating load of seventy (70) percent of 

maximum load adjusted for ambient conditions. 

iii. Time allocated to a cold startup for natural gas combustion is zero to 300 

minutes or the time for the turbine to reach operating stage equivalent to mode 

6Q and ammonia injection has occurred. 

b. Warm startup is defined as a startup to combined cycle operation following a 

complete shutdown lasting two hours or more, but less than or equal to fortyeight. 

i. The Permittee shall not combust fuel oil in the combustion turbines (emission 

unit ID Nos. CTG3 and CTG4) until the turbine load is at least 10.4 percent of 

maximum load adjusted for ambient conditions. 

ii. Time allocated to a warm startup for fuel oil combustion is zero to 155 

minutes or the time for reception of an operating load of seventy (70) percent 

of maximum load adjusted for ambient conditions. 

iii. Time allocated to a warm startup for natural gas combustion is zero to 155 

minutes or the time for the turbine to reach operating stage equivalent to mode 

6Q and ammonia injection has occurred. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 6 of 35 

c. Hot startup is defined as a startup to combined cycle operation following a 

complete shutdown lasting less than 2 hours. 

i. The Permittee shall not combust fuel oil in the combustion turbines 

(emission unit ID Nos. CTG3 and CTG4) until the turbine load is at least 

10.4 percent of maximum load adjusted for ambient conditions. 

ii. Time allocated to a warm startup for fuel oil combustion is zero to 60 

minutes or the time for reception of an operating load of seventy (70) 

percent of maximum load adjusted for ambient conditions. 

iii. Time allocated to a hot startup for natural gas combustion is zero to 60 

minutes or the time for the turbine to reach operating stage equivalent to 

mode 6Q and ammonia injection has occurred. 

d. Unit shutdown is defined as the period of time from steady state operation to 

cessation of combustion turbine firing. Time allocated to a shutdown is zero to 

sixty minutes. 

3.3.18 The Permittee shall limit the hours of startup and shutdown of combustion turbines 

with emission unit ID Nos. CTG3 and CTG4, each, to 1,099 hours during any twelve 

consecutive month period. 

[40 CFR 52.21(j)] 

3.3.19 The Permittee shall limit the hours of operation (including startup and shutdown) of 

combustion turbines with emission unit ID Nos. CTG3 and CTG4, each, to 1,000 

hours during any twelve consecutive month period during fuel oil combustion. 

[40 CFR 52.21(j); and PSD Avoidance for SO2 and Sulfuric Acid Mist] 

3.3.20 The Permittee shall limit the hours of operation of each duct burner with emission unit 

ID Nos. DB3 and DB4 to 4,000 hour during any twelve consecutive month period. 

[40 CFR 52.21(j)] 

3.3.21 The Permittee shall limit the hours of operation of auxiliary boiler with emission unit 

ID No. AB2 to 2,500 hours during any twelve consecutive month period. 

[40 CFR 52.21(j)] 

3.3.22 The Permittee shall install and operate, as Best Available Control Technology 

(BACT), for NOx on each combustion turbine with emission unit ID Nos. CTG3 and 

CTG4 a dry low NOx combustor for natural gas combustion. 

[40 CFR 52.21(j)] 

3.3.23 The Permittee shall install and operate, as BACT, for NOx on each combustion turbine 

with emission unit ID Nos. CTG3 and CTG4 water or steam injection for distillate fuel 

oil combustion. 

[40 CFR 52.21(j)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 7 of 35 

3.3.24 The Permittee shall install and operate, as BACT, for NOx on the combined exhaust of 

CTG3/DB3 and on the combined exhaust of CTG4/DB4, selective catalytic reduction 

add-on control equipment. 

[40 CFR 52.21(j)] 

3.3.25 The Permittee shall install and operate, as BACT, for CO and VOC on the combined 

exhaust of CTG3/DB3 and on the combined exhaust of CTG4/DB4, catalytic 

oxidation add-on control equipment. 

[40 CFR 52.21(j)] 

3.3.26 The Permittee shall not discharge, or cause to be discharged, into the atmosphere, from 

the combined exhaust of each combustion turbine and its paired duct burner (emission 

unit ID Nos. CTG3/DB3 and CTG4/DB4): 

[40 CFR 52.21(j)] 

a. Nitrogen Oxides (NOx) emissions, including emissions occurring during startup, 

shutdown, and malfunction, in excess of 210 tons during any twelve consecutive 

months during natural gas combustion. 

b. Nitrogen Oxides (NOx) emissions, including emissions occurring during startup, 

shutdown, and malfunction, in excess of 67 tons during any twelve consecutive 

months during fuel oil combustion. 

c. Carbon Monoxide (CO) emissions, including emissions occurring during startup, 

shutdown, and malfunction, in excess of 236 tons during any twelve consecutive 

months during natural gas combustion. 

d. Carbon Monoxide (CO) emissions, including emissions occurring during startup, 

shutdown, and malfunction, in excess of 46 tons during any twelve consecutive 

months during fuel oil combustion. 

3.3.27 The Permittee shall not discharge, or cause to be discharged, into the atmosphere from 

any of the combustion turbines with emission unit ID Nos. CTG3 and CTG4, each, 

while firing natural gas during all periods of operation, greenhouse gas (GHG, 

expressed as CO2e) emissions in excess of 863,953 tons during any twelve consecutive 

months. 

[40 CFR 52.21(j)] 

3.3.28 The Permittee shall not discharge, or cause to be discharged, into the atmosphere from 

any of the combustion turbines with emission unit ID Nos. CTG3 and CTG4, each, 

while firing fuel oil during all periods of operation, greenhouse gas (GHG, expressed as 

CO2e) emissions in excess of 159,603 tons during any twelve consecutive months. 

[40 CFR 52.21(j)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 8 of 35 

3.3.29 The Permittee shall not discharge, or cause to be discharged, into the atmosphere from 

any of the duct burners with emission unit ID Nos. DB3 and DB4, each, while firing 

natural gas, during all periods of operation, greenhouse gas (GHG, expressed as CO2e) 

emissions in excess of 111,837 tons during any twelve consecutive months. 

[40 CFR 52.21(j)] 

3.3.30 The Permittee shall not discharge, or cause to be discharged, into the atmosphere from 

the auxiliary boiler with emission unit ID No. AB2 during all periods of operation, 

greenhouse gas (GHG, expressed as CO2e) emissions in excess of 2,528 tons during any 

twelve consecutive months. 

[40 CFR 52.21(j)] 

3.3.31 The Permittee shall not discharge, or cause to be discharged, into the atmosphere from 

the fuel gas heater with emission unit ID No. FP2 during all periods of operation, 

greenhouse gas (GHG, expressed as CO2e) emissions in excess of 4,560 tons during any 

twelve consecutive months. 

[40 CFR 52.21(j)] 

3.3.32 The Permittee shall not discharge, or cause to be discharged, into the atmosphere from 

any of the combustion turbines and their paired duct burners with emission unit ID Nos. 

CTG3/DB3 and CTG4/DB4: 

[40 CFR 60.4330(a)1) and (a)(2)] 

a. Any fuel which contains total potential sulfur emissions in excess of 0.060 lb 

SO2/MMBtu heat input; or 

b. Any gases which contain SO2 in excess of 0.90 lb/MW-hr, gross output. 

3.3.33 The Permittee shall only fire the following fuels in the combustion turbines with 

emission unit ID Nos. CTG3 and CTG4: 

a. Pipeline quality natural gas with a fuel sulfur content not to exceed 0.5 grains per 

100 standard cubic feet. 

[40 CFR 52.21(j) for PM, PM10, PM2.5, 391-3-1-.02(2)(g)(subsumed); PSD 

Avoidance for SO2 and Sulfuric Acid Mist; and 40 CFR 60.4365 (subsumed for 

SO2)] 

b. Ultra low sulfur diesel fuel that contains no more than 0.0015 percent sulfur by 

weight (15 ppm). 

[40 CFR 52.21(j) for PM, PM10, PM2.5, 391-3-1-.02(2)(g)(subsumed); PSD 

Avoidance for SO2 and Sulfuric Acid Mist; and 40 CFR 60.4365 (subsumed for 

SO2)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 9 of 35 

3.3.34 The Permittee shall only fire pipeline quality natural gas with a fuel sulfur content not 

to exceed 0.5 grains per 100 standard cubic feet in each duct burner (emission unit ID 

Nos. DB3 and DB4), auxiliary boiler with emission unit ID No. AB2, and fuel gas 

heater with emission unit ID No. FP2. 

[40 CFR 52.21(j) for NOx and CO from FP2; 40 CFR 52.21(j) for PM, PM10, PM2.5 for 

DB3, DB4, AB2, and FP2, 40 CFR 52.21(j) for VOC from AB2 and FP2; 391-3-1-

.02(2)(d)(subsumed) for AB2 and FP1; 391-3-1-.02(g)(subsumed); PSD Avoidance for 

SO2 and Sulfuric Acid Mist] 

3.3.35 The Permittee shall not discharge, or cause to be discharged, into the atmosphere from 

each combined combustion turbine and duct burner stack with emission unit ID Nos. 

CTG3/DB3 and CTG4/DB4, excluding periods of startup and shutdown, while firing 

natural gas, any gases which: 

a. Contain nitrogen oxides (NOx) in excess of 2.0 ppmvd, corrected to 15% oxygen, 

on a 3-hour average. 

[40 CFR 52.21(j) and 40 CFR 60.4320(a) (subsumed)] 

b. Contain carbon monoxide (CO) in excess of 2.0 ppmvd, corrected to 15% oxygen, 

on a 3-hour average. 

[40 CFR 52.21(j)] 

c. Contain volatile organic compounds (VOC) in excess of 2.0 ppmvd, corrected to 

15% oxygen, on a 3-hour average. 

[40 CFR 52.21(j)] 

3.3.36 The Permittee shall not discharge, or cause to be discharged, into the atmosphere from 

each combined combustion turbine and duct burner stack with emission unit ID Nos. 

CTG3/DB3 and CTG4/DB, while firing fuel oil in each combustion turbine, any gases 

which: 

a. Contain nitrogen oxides (NOx) in excess of 10.0 ppmvd, corrected to 15% 

oxygen, on a 3-hour average, excluding periods of startup and shutdown. 

[40 CFR 52.21(j) and 40 CFR 60.4320(a) for (subsumed)] 

b. Contain carbon monoxide (CO) in excess of 2.0 ppmvd, corrected to 15% oxygen, 

on a 3-hour average, excluding periods of startup and shutdown. 

[40 CFR 52.21(j)] 

c. Contain volatile organic compounds (VOC) in excess of 2.0 ppmvd, corrected to 

15% oxygen, on a 3-hour average, excluding periods of startup and shutdown. 

[40 CFR 52.21] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 10 of 35 

d. Contain particulate matter (PM) in excess of the following numerical limits, on a 

3-hour average, including periods of startup and shutdown 

[40 CFR 52.21(j)] 

i. 0.0103 lb/MMBtu with duct firing; and 

ii. 0.0153 lb/MMBtu without duct firing. 

e. Contain particulate matter less than 10 microns (PM10) in excess of the following 

numerical limits, on a 3-hour average, including periods of startup and shutdown 

[40 CFR 52.21(j)] 

i. 0.0103 lb/MMBtu with duct firing; and 

ii. 0.0153 lb/MMBtu without duct firing. 

f. Contain particulate matter less than 2.5 microns (PM2.5) in excess of the following 

numerical limits, on a 3-hour average, including periods of startup and shutdown 

[40 CFR 52.21(j)] 

i. 0.0103 lb/MMBtu with duct firing; and 

ii. 0.0153 lb/MMBtu without duct firing. 

3.3.37 The Permittee shall not discharge, or cause the discharge, into the atmosphere, from 

each combustion turbines and its paired duct burner (emission unit ID Nos. CTG3/DB3 

and CTG4/DB4), the boiler (emission unit ID No. AB2) and the fuel gas heater 

(emission unit ID No. FP2), any gases exhibit greater than ten (10) percent opacity. 

[40 CFR 52.21(j); 391-3-1-.02(2)(b)(subsumed) for CTG3/DB3 and CTG4/DB4; and 

391-3-1-.02(2)(d)(subsumed) for AB2 and FP2] 

3.3.38 The Permittee shall not discharge, or cause the discharge, into the atmosphere from the 

Auxiliary Boiler AB2, any gases which contain NOx in excess of 0.098 lb/MMBtu. 

[40 CFR 52.21(j)] 

3.3.39 The Permittee shall not discharge, or cause the discharge, into the atmosphere from the 

Auxiliary Boiler AB2, any gases which contain CO in excess of 0.082 lb/MMBtu. 

[40 CFR 52.21(j)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 11 of 35 

3.3.40 The Permittee shall not cause, let, suffer, permit or allow a mass flow rate on either of 

the cooling towers with emission unit ID Nos. CT3 or CT4 equal to or greater than as 

determined to allow a drift eliminator effectiveness of 0.0005% guaranteed. The 

cooling towers will utilize high efficiency drift eliminators as best available control 

technologies (BACT) to limit particulate matter emissions from the cooling towers. The 

limit of this permit condition applies during all times of operation, including startup, 

shutdown, and malfunction. 

[40 CFR 52.21(j)] 

3.3.41 The Permittee shall institute the following best available control technologies (BACT) 

as specified in this permit condition. 

[40 CFR 52.21(j)] 

a. Installation and operation of conservation vents and proper operating and 

maintenance practices as specified by the manufacturer for fuel storage tank with 

emission unit ID No. T01. This equipment shall be employed at all times 

applicable equipment is in operation, including startup, shutdown, and 

malfunction. 

b. Installation and operation of submerged fuel fill pipes on the fuel storage tank 

with emission unit ID No. T01. This equipment shall be employed at all times 

applicable equipment is in operation, including startup, shutdown, and 

malfunction. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 12 of 35 

PART 4.0 REQUIREMENTS FOR TESTING 

4.1 General Testing Requirements 

NEW CONDITION

4.1.4 Performance and compliance tests shall be conducted and data reduced in accordance with 

applicable procedures and methods specified in the Division’s Procedures for Testing and 

Monitoring Sources of Air Pollutants. This Permit Condition pertains to project 

defined in Application No. 19810. The methods for the determination of compliance with 

emission limits listed under Sections 3.2, 3.3, 3.4 and 3.5 which pertain to the emission 

units listed in Section 3.1 are as follows: 

a. Method 1 shall be used for the determination of sample point locations, 

b. Method 2 shall be used for the determination of stack gas flow rate, 

c. Method 3 or 3A shall be used for the determination of stack gas molecular weight, 

d. Method 3B shall be used for the determination of the emissions rate correction factor 

for excess air; Method 3A may be used as an alternative, 

e. Method 4 shall be used for the determination of stack gas moisture, 

f. Method 5 shall be used for the determination of particulate matter concentration, 

g. Method 5T shall be used for the determination of the particulate matter 

concentration for the combustion turbines. The sampling time for each run shall be 

one hour, 

h. Method 6 or 6C shall be used to determine the sulfur dioxide concentration, 

i. Method 7E shall be used to determine the nitrogen oxides concentration, 

j. Method 9 and the procedures contained in Section 1.3 of the above reference 

document shall be used for the determination of opacity, 

k. Method 10 shall be used for the determination of carbon monoxide concentration. 

The sampling time for each run shall be one hour, 

l. Method 19 shall be used, when applicable, to convert particulate matter, carbon 

monoxide, sulfur dioxide, and nitrogen oxide concentrations (i.e., grains/dscf for 

PM, ppm for gaseous pollutants), as determined using other methods specified in 

this section, to emission rates (i.e., lb/MMBtu), 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 13 of 35 

m. As allowed by Conditions 4.2.3 and 4.2.4, if the Permittee chooses to periodically 

determine the sulfur content of the fuel combusted in each combustion turbine with 

emission unit ID No. CTG3 and CTG4 in lieu of annual performance tests to satisfy 

the requirements of 40 CFR 60.4415 as it relates to 40 CFR 60.4330(a)(2), a 

representative fuel sample shall be collected following the ASTM methods specified 

in 40 CFR 60.4415(a)(1), 

[40 CFR 60.4415(a)(1)] 

n. ASTM Test Methods D129, D1552, D2622, or D4294 shall be used for the 

determination of fuel oil sulfur content. 

o. Method 25A shall be used for the determination of concentrations of volatile organic 

compounds. The concentration of formaldehyde measured using Method 320 shall 

be added to the results of Method 25A to determine the VOC concentration. The 

Permittee may use Method 18 for determining methane and ethane concentrations to 

subtract from the results of Method 25A. The sampling time for each run shall be 

one hour to demonstrate compliance with Condition 3.3.35c and 3.3.36c. 

p. Methods 201A, in conjunction with Method 202, shall be used to determine 

concentrations of PM10 and PM2.5 to demonstrate compliance with emission limits 

in Permit Condition 3.3.36d, 3.3.36e, and 3.3.36f. 

Minor changes in methodology may be specified or approved by the Director or his 

designee when necessitated by process variables, changes in facility design, or 

improvement or corrections that, in his opinion, render those methods or procedures, or 

portions thereof, more reliable. 

[391-3-1-.02(3)(a)] 

4.2 Specific Testing Requirements 

NEW CONDITIONS 

4.2.1 Within 60 days after achieving the maximum production rate at which each affected 

facility will be operated on natural gas, but not later than 180 days after the initial startup 

of each affected facility, the Permittee shall conduct the following performance tests when 

the combustion turbine (emission unit ID Nos. CTG3 and CTG4) is fired with natural 

gas and furnish to the Division a written report of the results of each performance tests: 

a. For purposes of this condition, the term “affected facility” is defined as each combined 

cycle combustion turbine and duct burner system with emission unit ID Nos. 

CTG3/DB3 and CTG4/DB4. The duct burner system does not have to operate when 

the combustion turbine is operating at partial load if that represents normal operation of 

the affected facility at partial load. 

b. Performance tests on each affected facility, for NOx, emissions in accordance with 40 

CFR 60.4400 to verify compliance with 3.3.35a. The performance test for each NOx 

CEMS specified in Permit Condition 5.2.8a for each affected facility must be 

performed in accordance with 40 CFR 60.4405. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 14 of 35 

[40 CFR 52.21, 40 CFR 60.4400, 40 CFR 60.4405, 391-3-1-.02(6)(b)1.(i)] 

c. Performance tests on each affected facility for carbon monoxide emissions, at base load 

and at approximately seventy (70) percent load, to verify compliance with Condition 

3.3.35b. 

[40 CFR 52.21 and 391-3-1-.02(6)(b)1.(i)] or 

d. Performance tests on each affected facility for volatile organic compounds, at base load 

and at approximately seventy (70) percent load, to verify compliance with Condition 

3.3.35c. 

[40 CFR 52.21 and 391-3-1-.02(6)(b)1.(i)] 

e. Performance tests on each affected facility to satisfy the initial performance test 

requirements for SO2 emissions in accordance with 40 CFR 60.4415. 

[40 CFR 60.4415 for SO2, PSD Avoidance for SO2 and Sulfuric Acid Mist emissions] 

The performance tests for carbon monoxide and volatile organic compounds shall be 

conducted concurrently. 

4.2.2 Within 60 days after achieving the maximum production rate at which each affected 

facility will be operated on fuel oil, but not later than 180 days after the initial startup of 

each affected facility, the Permittee shall conduct the following performance tests when 

the combustion turbine (emission unit ID Nos. CTG3 and CTG4) is fired with fuel oil and 

furnish to the Division a written report of the results of each performance tests: 

a. For purposes of this condition, the term “affected facility” is defined as each combined 

cycle combustion turbine and duct burner system with emission unit ID Nos. 

CTG3/DB3 and CTG4/DB4. 

b. Performance tests on each affected facility, for NOx, emissions in accordance with 40 

CFR 60.4400 to verify compliance with 3.3.36a. The performance test for each NOx 

CEMS specified in Condition 5.2.8a for each affected facility must be performed in 

accordance with 40 CFR 60.4405. 

[40 CFR 52.21, 40 CFR 60.4400, 40 CFR 60.4405, 391-3-1-.02(6)(b)1.(i)] 

c. Performance tests on each affected facility for carbon monoxide emissions, at base 

load and at approximately seventy (70) percent load, to verify compliance with 

Condition 3.3.36b. 

[40 CFR 52.21 and 391-3-1-.02(6)(b)1.(i)] 

d. Performance tests on each affected facility for volatile organic compounds, at base 

load and at approximately seventy (70) percent load, to verify compliance with 

Condition 3.3.36c. 

[40 CFR 52.21 and 391-3-1-.02(6)(b)1.(i)] 

e. Performance tests on each affected facility for particulate matter (PM) emissions, at 

base load with duct firing, to verify compliance with Condition 3.3.36d.i. 

[40 CFR 52.21 and 391-3-1-.02(6)(b)1.(i)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 15 of 35 

f. Performance tests on each affected facility for PM10 emissions, at base load with duct 

firing to verify compliance with Condition 3.3.36e.i. 

[40 CFR 52.21 and 391-3-1-.02(6)(b)1.(i)] 

g. Performance tests on each affected facility for PM2.5 emissions, at base load with duct 

firing to verify compliance with Condition 3.3.36f.i. 

[40 CFR 52.21 and 391-3-1-.02(6)(b)1.(i)] 

h. Performance tests on each affected facility for visible emissions at base load to verify 

compliance with Condition 3.3.37. The performance tests for PM and visible 

emissions shall be conducted concurrently. 

[40 CFR 52.21 and 391-3-1-.02(6)(b)1.(i)] 

i. Performance tests on each affected facility to satisfy the initial performance test 

requirements for SO2 emissions in accordance with 40 CFR 60.4415. 

[40 CFR 60.4415 for SO2, PSD Avoidance for SO2 and Sulfuric Acid Mist emissions] 

The performance tests for carbon monoxide and volatile organic compounds shall be 

conducted concurrently. 

4.2.3 Subsequent SO2 performance tests shall be conducted on an annual basis(no more than 14 

calendar months following the previous performance test) for each affected facility 

combusting natural gas. The Permittee shall furnish to the Division a written report of 

the results of each performance tests: 

[40 CFR 60.4415] 

a. For purposes of this condition, the term “affected facility” is defined as each combined 

cycle combustion turbine and duct burner system with emission unit ID Nos. 

CTG3/DB3 and CTG4/DB4. 

b. The Permittee may use one of three methodologies to conduct the required 

performance tests and the methods are specified in 40 CFR 60.4415(a). 

4.2.4 Subsequent SO2 performance tests shall be conducted on an annual basis (no more than 14 

calendar months following the previous performance test) for each affected facility 

combusting fuel oil. The Permittee shall furnish to the Division a written report of the 

results of each performance tests: 

[40 CFR 60.4415] 

a. For purposes of this condition, the term “affected facility” is defined as each combined 

cycle combustion turbine and duct burner system with emission unit ID Nos. 

CTG3/DB3 and CTG4/DB4. 

b. The Permittee may use one of three methodologies to conduct the required 

performance tests and the methods are specified in 40 CFR 60.4415(a). 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 16 of 35 

4.2.5 All CEMS and continuous monitoring systems required by Conditions 5.2.8 and 5.2.9 and 

all control technologies required by Conditions 3.3.22 through 3.3.25 shall be installed and 

operating during all performance testing required in Permit Conditions 4.2.1 through 4.2.4. 

[40 CFR 52.21; 40 CFR 60 Subpart KKKK] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 17 of 35 

PART 5.0 REQUIREMENTS FOR MONITORING (Related to Data Collection) 

5.2 Specific Monitoring Requirements 

NEW CONDITIONS 

5.2.8 The Permittee shall install, calibrate, maintain, and operate a system to continuously 

monitor and record the indicated pollutants on the following equipment. Each system 

shall meet the applicable performance specification(s) of the Division's monitoring 

requirements. 

a. A Continuous Emissions Monitoring System (CEMS) for measuring NOx

concentration and diluent concentration (either oxygen or carbon dioxide) discharge to 

the atmosphere from each combined turbine and duct burner stack specified in 

Condition 3.3.16. The one-hour average nitrogen oxides emissions rates shall also be 

recorded in pound per million Btu heat input, and ppm corrected to 15 percent oxygen 

on a dry basis. The diluent concentration shall be expressed in percent. 

[40 CFR 52.21, 40 CFR 60.4350, 40 CFR 60.4335, 40 CFR 70.6(a)(3)(i), and 391-3-

1-.02(6)(b)1)] 

b. A Continuous Emissions Monitoring System (CEMS) for measuring CO concentration 

and diluent concentration (either oxygen or carbon dioxide) discharge to the 

atmosphere from each combined turbine and duct burner stack specified in Condition 

3.3.16. The one-hour average carbon monoxide emissions rates shall also be recorded 

in pound per million Btu heat input, and ppm corrected to 15 percent oxygen on a dry 

basis. The diluent concentration shall be expressed in percent. Each CO diluent 

CEMS must be installed and certified according to Performance Specification 4 and 

4A in appendix B of The Procedures for Testing and Monitoring Sources of Air 

Pollutants, except the 7-day calibration drift shall be based on unit operating days and 

not calendar days. 

[40 CFR 52.21, 40 CFR 70.6(a)(3)(i), and 391-3-1-.02(6)(b)1)] 

5.2.9 The Permittee shall install, calibrate, maintain, and operate monitoring devices for the 

measurement of the indicated parameters on the following equipment. Data shall be 

recorded at the frequency specified below. Where such performance specification(s) 

exist, each system shall meet the applicable performance specification(s) of the Division's 

monitoring requirements. 

a. The quantity of natural gas, in cubic feet, burned in each combustion turbine with 

emission unit ID Nos. CTG3 and CTG4. Data shall be recorded continuously. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21, 40 CFR 70.6(a)(3)(i), and 40 CFR 60, Subpart 

KKKK (subsumed)] 

b. The quantity of fuel oil, in gallons, burned in each combustion turbine with emission 

unit ID Nos. CTG3 and CTG4. Data shall be recorded continuously. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21, 40 CFR 70.6(a)(3)(i), and 40 CFR 60, Subpart 

KKKK (subsumed)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 18 of 35 

c. The quantity of natural gas, in cubic feet, burned in each duct burner with emission 

unit ID Nos. DB3 and DB4. Data shall be recorded continuously. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21, 40 CFR 70.6(a)(3)(i), and 40 CFR 60, Subpart 

KKKK (subsumed)] 

d. The quantity of natural gas, in cubic feet, burned in the auxiliary boiler with 

emission unit ID No. AB2. Data shall be recorded monthly. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21, and 40 CFR 70.6(a)(3)(i)] 

e. The quantity of natural gas, in cubic feet, burned in the fuel gas heater with emission 

unit ID No. FP2. Data shall be recorded monthly. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21, and 40 CFR 70.6(a)(3)(i)] 

f. The cumulative total hours of operation, during all periods of operation, for each 

duct burner with emission unit ID Nos. DB3 and DB4. Data shall be recorded 

monthly. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21, and 40 CFR 70.6(a)(3)(i)] 

g. The cumulative total hours of operation, during all periods of operation, for each 

combustion turbine with emission unit ID Nos. CTG3 and CTG4 while firing fuel 

oil. Data shall be recorded monthly. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21, and 40 CFR 70.6(a)(3)(i)] 

h. The cumulative total hours of startup and shutdown, for each combustion turbine 

with emission unit ID Nos. CTG3 and CTG4 while firing natural gas. Data shall be 

recorded monthly. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21, and 40 CFR 70.6(a)(3)(i)] 

i. The cumulative total hours of operation, during all periods of operation, for the 

auxiliary boiler with emission unit ID No. AB2. Data shall be recorded monthly. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21, and 40 CFR 70.6(a)(3)(i)] 

5.2.10 The Permittee shall, using the procedures of Appendix F, Procedure 1 (Quality Assurance 

Requirements for Gas Continuous Emissions Monitoring Systems Used for Compliance 

Determination) contained in the Division’s Procedures for Testing and Monitoring 

Sources of Air Pollutants, to assess the quality and accuracy of the data acquired by the 

carbon monoxide CEMS required by Condition 5.2.8b. The Permittee shall maintain 

records specifying the results of the daily CEMS drift tests and quarterly accuracy 

assessments under Appendix F, Procedure 1. In addition, the Permittee shall maintain 

records which identify the Out-of-Control Periods (as defined in Appendix F, Procedure 

1) for the CO CEMS during each calendar quarter. The following exceptions to Appendix 

F, Procedure 1 are allowed: 

[391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

a. The cylinder gas audit (CGA) is only required to be conducted in a calendar quarter 

if the turbine is operated during the quarter. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 19 of 35 

b. The Relative Accuracy Test Audit (RATA) shall be conducted annually or every 

four operating quarters (not to exceed eight calendar quarters) whichever is greater. 

For the purpose of this condition an operating quarter is defined as any calendar 

quarter during which the turbine is operated. 

5.2.11 The Permittee shall obtain CO emissions data for at least 75 percent of the operating hours 

for each turbine during each calendar month that a turbine is operated. If this minimum 

data requirement is not met using the CO CEMS required by Condition 5.2.8b, the 

Permittee may supplement the emissions data with data obtained by conducting sampling 

using the methods prescribed in Condition 4.1.4. The Permittee shall maintain records, 

which identify periods during each calendar month for which CO emissions data have not 

been obtained for 75 percent of the turbine operating hours during the month, include 

reasons for not obtaining sufficient data and a description of corrective actions taken. 

[391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

5.2.12 The following pollutant specific emission unit(s) (PSEU) are subject to the Compliance 

Assurance Monitoring (CAM) Rule in 40 CFR 64. 

Emission Unit Pollutant 

CTG3/DB3 CO 

CTG4/DB4 CO 

CTG3/DB3 NOx 

CTG4/DB4 NOx 

Permit conditions in this permit for the PSEU(s) listed above with the regulatory citation 

40 CFR 70.6(a)(3)(i) are included for the purpose of complying with 40 CFR 64. In 

addition, the Permittee shall meet the requirements, as applicable, of 40 CFR 64.7, 64.8, 

and 64.9. 

[40 CFR 64] 

5.2.13 The Permittee shall comply with the performance criteria listed in the table below for the 

CO emissions from CTG3/DB3 and/or CTG4/DB4. 

[40 CFR 64.6(c)(1)(iii)] 

Performance Criteria 

[64.4(a)(3)] 

Indicator No. 1 

CEMS CO Value 

A. Data Representativeness 

 [64.3(b)(1)] 

CO and O2 (or CO2) are monitored with a CEMS 

that is Performance Specification 4 and 4A in 

appendix B of the Procedures for Testing and 

Monitoring Sources of Air Pollutants 

B. Verification of Operational Status (new/modified 

monitoring equipment only) 

 [64.3(b)(2)] 

 

Meet requirements of Performance Specification 4 

or 4A. 

C. QA/QC Practices and Criteria 

 [64.3(b)(3) 

QA/QC procedures include calibration, 

maintenance following manufacturer’s 

specifications and specific to the plant. 

D. Monitoring Frequency 

 [64.3(b)(4)] 

Measurements are taken continuously except during 

periods of calibration and maintenance. 

E. Data Collection Procedures 

 [64.3(b)(4)] 

The data acquisitions systems (DAS) retains all 

hourly average CO data. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 20 of 35 

Performance Criteria 

[64.4(a)(3)] 

Indicator No. 1 

CEMS CO Value 

F. Averaging Period 

 [64.3(b)(4)] 

Per minute data is used to calculate 1-hour averages 

which is used to calculate a 3-hour rolling average. 

5.2.14 The Permittee shall comply with the performance criteria listed in the table below for the 

NOx emissions from CTG3/DB3 and CTG4/DB4. 

[40 CFR 64.6(c)(1)(iii)] 

Performance Criteria 

[64.4(a)(3)] 

Indicator No. 1 

CEMS NOx Value 

A. Data Representativeness 

 [64.3(b)(1)] 

NOx and O2 are monitored with a CEMS that is 

certified under 40 CFR Part 75, Appendix A. 

B. Verification of Operational Status (new/modified 

monitoring equipment only) 

 [64.3(b)(2)] 

 

NA 

C. QA/QC Practices and Criteria 

 [64.3(b)(3) 

QA/QC procedures include calibration, 

maintenance following manufacturer’s 

specifications and specific to the plant. 

D. Monitoring Frequency 

 [64.3(b)(4)] 

Measurements are taken continuously except during 

periods of calibration and maintenance. 

E. Data Collection Procedures 

 [64.3(b)(4)] 

The data acquisitions systems (DAS) retains all 

hourly average NOx data. 

F. Averaging Period 

 [64.3(b)(4)] 

Per minute data is used to calculate 1-hour averages 

which is used to calculate a 3-hour rolling average. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 21 of 35 

PART 6.0 OTHER RECORD KEEPING AND REPORTING REQUIREMENTS 

6.1 General Record Keeping and Reporting Requirements 

NEW CONDITION 

6.1.8 For the purpose of reporting excess emissions, exceedances or excursions in the report 

required in Condition 6.1.4, the following excess emissions, exceedances, and excursions 

shall be reported as it relates to the project specified in Application No. 19810: 

[391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

a. Excess emissions: (means for the purpose of this Condition and Condition 6.1.4, 

any condition that is detected by monitoring or record keeping which is specifically 

defined, or stated to be, excess emissions by an applicable requirement) 

i. Any unit operating period in which the 30 unit operating day rolling average 

NOx emission rate from each combined combustion turbine/duct burner stack 

exceeds 15 ppmvd @ 15% oxygen while burning natural gas. The definition 

of a “30 unit operating day average NOx emission rate” is defined in 40 CFR 

60.4380(b)(1). 

[40 CFR 60.4350 and 40 CFR 60.4380(b)] 

ii. Any unit operating period in which the 30 unit operating day rolling average 

NOx emission rate from each combined combustion turbine/duct burner stack 

exceeds 42 ppmvd @ 15% oxygen while burning fuel oil. The definition of a 

“30 unit operating day average rolling average NOx emission rate” is defined 

in 40 CFR 60.4380(b)(1). 

[40 CFR 60.4350 and 40 CFR 60.4380(b)] 

iii. Excess emissions are defined as described in 40 CFR 60.4385(a) and (b) as 

they relate to Condition 3.3.32. 

[40 CFR 60.4385] 

b. Exceedances: (means for the purpose of this Condition and Condition 6.1.4, any 

condition that is detected by monitoring or record keeping that provides data in 

terms of an emission limitation or standard and that indicates that emissions (or 

opacity) do not meet the applicable emission limitation or standard consistent with 

the averaging period specified for averaging the results of the monitoring) 

i. Any twelve consecutive month total hours of operation of auxiliary boiler with 

emission unit ID No. AB2 which exceeds 2,500 hours during all periods of 

operation. 

[40 CFR 52.21] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 22 of 35 

ii. Any twelve consecutive month total hours of operation from burning ultra low 

sulfur diesel fuel, for each combustion turbine with emission unit ID No. 

CGT3 and/or CGT4 which exceeds 1,000 hours during all periods of 

operation. 

[40 CFR 52.21 and PSD Avoidance for SO2 and Sulfuric Acid Mist] 

iii. Any twelve consecutive month total hours of operation for each duct burner 

with emission unit ID No. DB3 and/or DB4 which exceeds 4,000 hours during 

all periods of operation. 

[40 CFR 52.21] 

iv. Any twelve consecutive month total hours of startup and shutdown for each 

combustion turbine with emission unit ID Nos. CTG3 and CTG4, each, which 

exceeds 1,099 hours while firing natural gas. 

[40 CFR 52.21] 

v. Any time natural gas is burned in any of the following emission units which 

has a sulfur content in excess of 0.5 grains per 100 standard cubic feet: 

combustion turbines (emission unit ID Nos. CTG3 and CTG4), duct burners 

(emission unit ID Nos. DB3 and DB4), boiler (emission unit ID No. AB2), 

fuel gas heater (emission unit FP2). 

[40 CFR 52.21 for PM, PM10, and PM2.5; 391-3-1-.02(2)(g)(subsumed); 

PSD Avoidance for SO2 and Sulfuric Acid Mist; and 40 CFR 

60.4365(subsumed)] 

vi. Any time fuel oil is burned in the combustion turbines (emission unit ID Nos. 

CTG3 and CTG4) which has a weight percent sulfur content in excess of 

0.0015. 

[40 CFR 52.21 for PM, PM10, and PM2.5; 391-3-1-.02(2)(g)(subsumed); 

PSD Avoidance for SO2 and Sulfuric Acid Mist; and 40 CFR 

60.4365(subsumed)] 

vii. Any three-hour rolling average NOx emission rate, determined in accordance 

with Condition 5.2.8a, which exceeds 2.0 ppmvd at 15% oxygen for each 

combined combustion turbine and duct burner stack specified in Condition 

3.3.16 when the combustion turbine is fired with natural gas, excluding 

periods of startup and shutdown. For purposes of this condition, each clock 

hour begins a new one-hour average. 

[40 CFR 52.21 and 40 CFR 60.4320(a)(subsumed)] 

viii. Any three-hour rolling average NOx emission rate, determined in accordance 

with Condition 5.2.8a, which exceeds 10.0 ppmvd at 15% oxygen for each 

combined combustion turbine and duct burner stack specified in Condition 

3.3.16 when the combustion turbine is fired with fuel oil excluding periods of 

startup and shutdown. For purposes of this condition, each clock hour begins 

a new one-hour average. 

[40 CFR 52.21 and 40 CFR 60.4320(a)(subsumed)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 23 of 35 

ix. Any twelve consecutive month total NOx emissions (tons) from each 

combined combustion turbine and duct burner stack specified in Condition 

3.3.16 when the combustion turbine is fired with natural gas, which exceeds 

210 tons during all periods of operation. 

[40 CFR 52.21] 

x. Any twelve consecutive month total NOx emissions (tons) from each 

combined combustion turbine and duct burner stack specified in Condition 

3.3.16 when the combustion turbine is fired with fuel oil, which exceeds 67 

tons during all periods of operation. 

[40 CFR 52.21] 

xi. Any three-hour rolling average CO emission rate, determined in accordance 

with Condition 5.2.8b, which exceeds 2.0 ppmvd at 15% oxygen for each 

combined combustion turbine and duct burner stack specified in Condition 

3.3.16 when the combustion turbine is fired with natural gas excluding periods 

of startup and shutdown. For purposes of this condition, each clock hour 

begins a new one-hour average. 

[40 CFR 52.21] 

xii. Any three-hour rolling average CO emission rate, determined in accordance 

with Condition 5.2.8b, which exceeds 2.0 ppmvd at 15% oxygen for each 

combustion turbine and duct burner stack specified in Condition 3.3.16 when 

the combustion turbine is fired with fuel oil excluding periods of startup and 

shutdown. For purposes of this condition, each clock hour begins a new onehour average. 

[40 CFR 52.21] 

xiii. Any twelve consecutive month total CO emissions (tons) from each combined 

combustion turbine and duct burner stack specified in Condition 3.3.16 when 

the combustion turbine is fired with natural gas which exceeds 236 tons during 

all periods of operation. 

[40 CFR 52.21] 

xiv. Any twelve consecutive month total CO emissions (tons) from each combined 

combustion turbine and duct burner stack specified in Condition 3.3.16 when 

the combustion turbine is fired with fuel oil which exceeds 46 tons during all 

periods of operation. 

[40 CFR 52.21] 

xv. Any twelve consecutive month total GHG emissions (expressed as CO2e) from 

each combustion turbine with emission unit ID Nos. CTG3 and CTG4 while 

firing natural gas which exceeds 863,953 tons during all periods of operation. 

[40 CFR 52.21] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 24 of 35 

xvi. Any twelve consecutive month total GHG emissions (expressed as CO2e) from 

each combustion turbine with emission unit ID Nos. CTG3 and CTG4 while 

firing fuel oil which exceeds 159,603 tons during all periods of operation. 

[40 CFR 52.21] 

xvii. Any twelve consecutive month total GHG emissions (expressed as CO2e) from 

each duct burner with emission unit ID Nos. DB3 and DB4 while firing 

natural gas which exceeds 111,837 tons during all periods of operation. 

[40 CFR 52.21] 

xviii. Any twelve consecutive month total GHG emissions (expressed as CO2e) 

from the boiler with emission unit ID No. AB2 while firing natural gas which 

exceeds 2,528 tons during all periods of operation.

[40 CFR 52.21] 

xix. Any twelve consecutive month total GHG emissions (expressed as CO2e) from 

the fuel gas heater with emission unit ID No. FP2 while firing natural gas 

which exceeds 4,560 tons during all periods of operation. 

[40 CFR 52.21] 

c. Excursions: (means for the purpose of this Condition and Condition 6.1.4, any 

departure from an indicator range or value established for monitoring consistent 

with any averaging period specified for averaging the results of the monitoring) 

None to be reported. 

6.2 Specific Record Keeping and Reporting Requirements 

NEW CONDITIONS 

Recordkeeping Requirements 

6.2.15 The Permittee shall monitor the sulfur content of the natural gas burned in the combustion 

turbines (emission unit ID Nos. CTG3 and CTG4), the duct burners (emission unit ID 

Nos. DB3 and DB4), the boiler (emission unit ID No. AB2), and the fuel gas heater 

(emission unit ID No. FP2) by the submittal of a semiannual analysis of the gas by the 

supplier. 

[391-3-1-.02(6)(b)1; 40 CFR 52.21; 391-3-1-.02(2)(g)(subsumed); PSD Avoidance for 

SO2 and Sulfuric Acid Mist] 

6.2.16 The Permittee shall verify and document that each shipment of fuel oil received for 

combustion in the combustion turbines (emission unit ID Nos. CTG3 and CTG4) 

complies with the requirements of Condition 3.3.33 by either of the following means: 

[391-3-1-.02(6)(b)1; 40 CFR 52.21; 391-3-1-.02(2)(g)(subsumed); PSD Avoidance for 

SO2 and Sulfuric Acid Mist] 

a. Fuel oil receipts obtained from the fuel supplier certifying that the fuel oil contains 

less than or equal to 0.0015 percent sulfur, by weight. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 25 of 35 

b. Analysis of the fuel oil conducted by methods of sampling and analysis which have 

been specified or approved by the Division which demonstrates that the fuel oil 

contains less than or equal to 0.0015 percent sulfur, by weight. 

6.2.17 The Permittee shall retain the following fuel usage records based on monitoring required 

by Condition 5.2.9. These records (including calculations) shall be maintained as part of 

the monthly record suitable for inspection or submittal. 

[391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

a. Monthly natural gas usage in each combustion turbine with emission unit ID Nos. 

CTG3 and CTG4. 

[40 CFR 52.21 and 40 CFR 60, Subpart KKKK] 

b. Monthly natural gas usage in each duct burner with emission unit ID Nos. DB3 and 

DB4. 

[40 CFR 52.21 and 40 CFR 60, Subpart KKKK] 

c. Monthly fuel oil usage in each combustion turbine with emission unit ID Nos. 

CTG3 and CTG4. 

[40 CFR 52.21 and 40 CFR 60, Subpart KKKK] 

d. The twelve consecutive month total natural gas usage in each combustion turbine 

with emission unit ID Nos. CTG3 and CTG4. A twelve consecutive month total 

shall be the total for a month in the reporting period plus the totals for the previous 

eleven consecutive months. 

[40 CFR 52.21] 

e. The twelve consecutive month total natural gas usage in each duct burner with 

emission unit ID Nos. DB3 and DB4. A twelve consecutive month total shall be 

the total for a month in the reporting period plus the totals for the previous eleven 

consecutive months. 

[40 CFR 52.21] 

f. The twelve consecutive month total fuel oil usage in each combustion turbine with 

emission unit ID Nos. CTG3 and CTG4. A twelve consecutive month total shall be 

the total for a month in the reporting period plus the totals for the previous eleven 

consecutive months. 

[40 CFR 52.21] 

g. The twelve consecutive month total natural gas usage in the boiler with emission 

unit ID No. AB2. A twelve consecutive month total shall be the total for a month 

in the reporting period plus the totals for the previous eleven consecutive months. 

[40 CFR 52.21] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 26 of 35 

h. The twelve consecutive month total natural gas usage in the fuel gas heater with 

emission unit ID No. FP2. A twelve consecutive month total shall be the total for a 

month in the reporting period plus the totals for the previous eleven consecutive 

months. 

[40 CFR 52.21] 

6.2.18 The Permittee shall develop and maintain an on-site quality assurance plan as specified on 

40 CFR 60.4345(e) for all of the continuous monitoring equipment described in 40 CFR 

60.4345 (a), (c), and (d) as it relates to emission unit ID Nos. CTG3/DB3 and CTG4/DB4. 

[40 CFR 60.4345(e)] 

Verification of Compliance with Operational Limits 

6.2.19 The Permittee shall maintain the following records as they relate to the startup and 

shutdown of each combustion turbine with emission unit ID Nos. CTG3 and CTG4: 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

a. The time (minutes) attributed to the startup, type of startup (cold, warm or hot 

start), and the time (minutes) attributed to shutdown. If the turbine was not in 

operation on any given day, the record shall so note. 

b. The monthly total hours attributed to startup and shutdown on a combined basis. 

c. The twelve consecutive month total hours attributed to startup and shutdown on a 

combined basis. 

d. The turbine load at which the Permittee initiated fuel oil combustion for each 

startup to verify compliance with Conditions 3.3.17a.i, 3.3.17b.i, and 3.3.17c.i. 

6.2.20 The Permittee shall use the hour meter required by Condition 5.2.9f to determine and 

record the total twelve consecutive month operating hours for each duct burner with 

emission unit ID Nos. DB3 and DB4 at the end of each calendar month. A twelve 

consecutive month total shall be the total for a month in the reporting period plus the 

totals for the previous eleven consecutive months. These records (including calculations) 

shall be maintained as part of the monthly record suitable for inspection or submittal. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

6.2.21 The Permittee shall use the hour meter required by Condition 5.2.9g to determine and 

record the total twelve consecutive month operating hours for each combustion turbine 

with emission unit ID Nos. CTG3 and CTG4 at the end of each calendar month. A twelve 

consecutive month total shall be the total for a month in the reporting period plus the 

totals for the previous eleven consecutive months. These records (including calculations) 

shall be maintained as part of the monthly record suitable for inspection or submittal. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 27 of 35 

6.2.22 The Permittee shall use the hour meter required by Condition 5.2.9d to determine and 

record the total twelve consecutive month operating hours for the auxiliary boiler with 

emission unit ID No. AB2. A twelve consecutive month total shall be the total for a 

month in the reporting period plus the totals for the previous eleven consecutive months. 

These records (including calculations) shall be maintained as part of the monthly record 

suitable for inspection or submittal. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

Verification of Compliance with NOx Emission Limits

6.2.23 The Permittee shall determine and record a 30-day rolling average NOx emission rate (in 

ppm at 15 percent oxygen) for each combustion turbine and its paired duct burner 

(emission unit ID Nos. CTG3/DB3 and CTG4/DB4), using the NOx hourly emission rate 

determined in accordance with Condition 5.2.8a. For purposes of this Condition, a 30-day 

rolling average is based on natural gas combustion only and a separate 30-day rolling 

average for fuel oil combustion. 

[40 CFR 60.4250 and 40 CFR 60.4380] 

6.2.24 The Permittee shall determine and record the mass emission rate (lb/hr) of NOx from each 

combustion turbine and its paired duct burner (emission unit ID Nos. CTG3/DB3 and 

CTG4/DB4) for each hour or portion of each hour of operation for each fuel type 

combusted. The hourly mass emission rate shall be calculated by multiplying the total 

NOx emissions in units of pounds per million Btu, determined in accordance with the 

procedures of 40 CFR Part 75, Section 3 of Appendix F, by the total heat input for that 

hour determined in accordance with the procedures of 40 CFR Part 75 Section 5.5 of 

Appendix F. These records (including calculations) shall be maintained in a form suitable 

for inspection or submittal. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

6.2.25 The Permittee shall use the records required by Condition 6.2.24 to determine and record 

the monthly mass emission rate for each fuel type combusted, in tons per month, of NOx, 

from each combustion turbine and its paired duct burner (emission unit ID Nos. 

CTG3/DB3 and CTG4/DB4) for each fuel type combusted. These records (including 

calculations) shall be maintained as part of the monthly record suitable for inspection or 

submittal. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

6.2.26 The Permittee shall use the records required by Condition 6.2.25 to determine and record 

the twelve consecutive month total of nitrogen oxides emissions (in tons) from each 

combustion turbine and its paired duct burner (emission unit ID Nos. CTG3/DB3 and 

CTG4/DB4) for each fuel type combusted. A twelve consecutive month total shall be the 

total for a month in the reporting period plus the totals for the previous eleven consecutive 

months. These records (including calculations) shall be maintained as part of the monthly 

record suitable for inspection or submittal. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 28 of 35 

Verification of Compliance with CO Emission Limits 

6.2.27 The Permittee shall determine and record the mass emission rate (lb/hr) of carbon 

monoxide from each combustion turbine and its paired duct burner (emission unit ID Nos. 

CTG3/DB3 and CTG4/DB4) for each fuel type combusted. The mass emission rate shall 

be calculated from the hourly heat input rate (million Btu per hour), determined in 

accordance with the procedures of Appendix F, 40 CFR 75, and the one-hour average 

carbon monoxide emission rate (pound per million Btu), determined in accordance with 

Condition 5.2.8b. Only the one-hour carbon monoxide emission rates (pound per million 

Btu) that have been determined to be valid hourly emission rates shall be used to calculate 

hourly mass emission rates. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

6.2.28 The Permittee shall use the valid hourly carbon monoxide mass emission rates (lb/hr) to 

determine and record in accordance with the requirements of Condition 6.2.27, and all 

hourly carbon monoxide mass emissions rates acquired in order to meet the minimum data 

requirement of Condition 5.2.11 to determine the monthly carbon monoxide mass 

emission rate, in tons per month, from each combustion turbine and its paired duct burner 

(emission unit ID Nos. CTG3/DB3 and CTG4/DB4) for each fuel type combusted. The 

monthly carbon monoxide mass emission rate from each turbine and duct burner 

combination shall be calculated as follows: 

Carbon Monoxide emissions (tons/month) = ECO*(TOT/TGD)/2000 

Where, ECO equals the total carbon monoxide mass emissions (sum of the valid hours of 

mass emissions including all hourly mass emissions data acquired to meet the minimum 

data requirement) for the month, TOT equals the total operating time (hours) of the 

combustion turbine/duct burner combination during the month, and TGD equals the 

number of hours of valid emissions data including all hourly emissions data acquired to 

meet the minimum data requirement contained in Condition 5.2.12. These records 

(including calculations) shall be maintained as part of the monthly record suitable for 

inspection or submittal. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

6.2.29 The Permittee shall use the records required by Condition 6.2.28 to determine and record 

the twelve consecutive month total of carbon monoxide emissions (in tons) from each 

combustion turbine and its paired duct burner (emission unit ID Nos. CTG3/DB3 and 

CTG4/DB4) for each fuel type combusted. A twelve consecutive month total shall be the 

total for a month in the reporting periods plus the totals for the previous eleven 

consecutive months. These records (including calculations) shall be maintained as part of 

the monthly record suitable for inspection or submittal. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 29 of 35 

Verification of Compliance with the GHG Emission Limits

6.2.30 The Permittee shall use the records required by Condition 6.2.17 to determine and record 

the monthly total greenhouse gas emissions (expressed as CO2e), in tons, from each of the 

following units and fuel types during all periods of operation. The Permittee shall use the 

applicable greenhouse gas emission factors and global warming potentials used in 

Application No. 19810. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

a. Combustion turbines with emission unit ID Nos. CTG3 and CTG4 while firing natural 

gas. 

b. Combustion turbines with emission unit ID Nos. CTG3 and CTG4 while firing fuel 

oil. 

c. Duct burners with emission unit ID Nos. DB3 and DB4 while firing natural gas. 

d. Auxiliary boiler with emission unit ID No. AB2 while firing natural gas. 

e. Fuel gas heater with emission unit ID Nos. FP2 while firing natural gas. 

These records (including calculations) shall be maintained as part of the monthly record 

suitable for inspection or submittal. 

6.2.31 The Permittee shall use the records required by Condition 6.2.30 to determine and record 

the twelve consecutive month total greenhouse gas emissions (expressed as CO2e), in tons, 

from each of the following units and fuel type during all periods of operation. The 

Permittee shall use the applicable greenhouse gas emission factors and global warming 

potentials used in Application No. 19810. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

a. Combustion turbines with emission unit ID Nos. CTG3 and CTG4 while firing natural 

gas. 

b. Combustion turbines with emission unit ID Nos. CTG3 and CTG4 while firing fuel 

oil. 

c. Duct burners with emission unit ID Nos. DB3 and DB4 while firing natural gas. 

d. Auxiliary boiler with emission unit ID No. AB2 while firing natural gas. 

e. Fuel gas heater with emission unit ID Nos. FP2 while firing natural gas. 

A twelve consecutive month total shall be the total for a month in the reporting period 

plus the totals for the previous eleven consecutive months. These records (including 

calculations) shall be maintained as part of the monthly record suitable for inspection or 

submittal. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 30 of 35 

6.2.32 To demonstrate compliance with Permit Condition 3.3.40, the Permittee shall maintain 

records documenting that the drift eliminators on the cooling tower with emission unit ID 

Nos. CT3 and CT4 have been designed to meet the applicable limit. Such records shall be 

submitted for review during the first quarterly report required by Permit Condition 6.1.4. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)] 

Reporting Requirements 

6.2.33 The Permittee shall furnish the Division written notification as follows: 

[40 CFR 52.21 and 40 CFR 60.7] 

a. A notification of the actual date of initial startup of each combustion turbine 

(emission unit ID Nos. CTG3, CTG4), each duct burner (emission unit ID Nos. 

DB3 and DB4); the boiler (emission unit ID No. AB2); the fuel gas heater 

(emission unit ID No. FP2), the cooling towers (emission unit ID Nos. CT1 and 

CT2); and the fuel oil storage tank (emission unit ID No. T01) within 15 days of 

such date of initial startup. 

b. Certification that a final inspection has shown that construction of each unit 

specified in Condition 1.3 has been completed in accordance with the application, 

plans, specifications and supporting documents submitted in support of this permit. 

The certification shall be submitted within 30 days of the date of certification. 

6.2.34 The Permittee shall submit a report of the following information for each quarterly period 

ending March 31, June 30, September 30, and December 31 of each year as part of the 

quarterly report required by Condition 6.1.4. 

[391-3-1-.02(6)(b)1, 40 CFR 52.21 and 40 CFR 70.6(a)(3)(i) 

a. The twelve consecutive month total hours of operation of boiler (emission unit ID 

No. AB2), each duct burner (emission unit ID Nos. DB3 and DB4), each 

combustion turbine (emission unit ID No. CTG3 and CTG4) including periods of 

startup and shutdown while firing fuel oil for each month during the quarter, and 

each combustion turbine (emission unit ID Nos. CTG3 and CTG4) while firing 

natural gas for periods of startup and shutdown for each month during the quarter. 

The reports shall be prepared from the records retained in Conditions 6.2.20, 

6.2.21, and 6.2.22. 

b. The twelve consecutive month total NOx emissions (tons) from each combined 

combustion turbine/duct burner stack (emission unit ID Nos. CTG3/DB3 and 

CTG4/DB4) while burning natural gas in the combustion turbines, for each month 

in the quarterly reporting period. The reports shall be prepared from the records 

retained in Condition 6.2.26. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 31 of 35 

c. The twelve consecutive month total CO emissions (tons) from each combined 

combustion turbine/duct burner stack (emission unit ID Nos. CTG3/DB3 and 

CTG4/DB4) while burning natural gas in the combustion turbines, for each month 

in the quarterly reporting period. The reports shall be prepared from the records 

retained in Condition 6.2.29. 

d. The twelve consecutive month total NOx emissions (tons) from each combined 

combustion turbine/duct burner stack (emission unit ID Nos. CTG3/DB3 and 

CTG4/DB4) while burning fuel oil in the combustion turbines, for each month in 

the quarterly reporting period. The reports shall be prepared from the records 

retained in Condition 6.2.26. 

e. The twelve consecutive month total CO emissions (tons) from each combined 

combustion turbine/duct burner stack (emission unit ID Nos. CTG3/DB3 and 

CTG4/DB4) while burning fuel oil in the combustion turbines, for each month in 

the quarterly reporting period. The reports shall be prepared from the records 

retained in Condition 6.2.29. 

f. The twelve consecutive month total GHG emissions (reported as CO2e in tons) 

from each combustion turbine with emission unit ID Nos. CTG3 and CTG4 while 

burning natural gas for each month in the quarterly reporting period. The reports 

shall be prepared from the records retained in Condition 6.2.31. 

g. The twelve consecutive month total GHG emissions (reported as CO2e in tons) 

from each combustion turbine with emission unit ID Nos. CTG3 and CTG4 while 

burning fuel oil for each month in the quarterly reporting period. The reports shall 

be prepared from the records retained in Condition 6.2.31. 

h. The twelve consecutive month total GHG emissions (reported as CO2e in tons) 

from each duct burner with emission unit ID Nos. DB3 and DB4 for each month in 

the quarterly reporting period. The reports shall be prepared from the records 

retained in Condition 6.2.31. 

i. The twelve consecutive month total GHG emissions (reported as CO2e in tons) 

from the boiler with emission unit ID No. AB2 for each month in the quarterly 

reporting period. The reports shall be prepared from the records retained in 

Condition 6.2.31. 

j. The twelve consecutive month total GHG emissions (reported as CO2e in tons) 

from the fuel gas heater with emission unit ID No. FP2 for each month in the 

quarterly reporting period. The reports shall be prepared from the records retained 

in Condition 6.2.31. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 32 of 35 

6.2.35 The Permittee shall verify the compliance with fuel sulfur content limitations as specified 

in Permit Conditions 3.3.33 and 3.3.34. The Permittee shall submit the following as part 

of the quarterly report required by Permit Condition 6.1.4. 

[40 CFR 52.21, 391-3-1-.02(6)(b)1, 40 CFR 70.6(a)(3)(i), and PSD Avoidance for SO2

and Sulfuric Acid Mist Emissions] 

a. For natural gas, the Permittee shall submit the fuel quality characteristics in a current, 

valid purchase contract, tariff sheet or transportation contract for the fuel, specifying 

that the maximum total sulfur content 0.5 grains of sulfur or less per 100 standard 

cubic feet. 

b. For distillate fuel oil, the Permittee shall verify and document that each shipment of 

ultra low sulfur distillate fuel oil received for combustion in CGT3 and/or CGT4 

complies by either of the following means: 

i. Fuel oil receipts obtained from the fuel supplier certifying that the oil is distillate 

fuel oil and contains less than or equal to 0.0015 percent sulfur, by weight. 

ii. Analysis of the fuel oil conducted by methods of sampling and analysis which 

have been specified or approved by the Division which demonstrates that the 

distillate fuel oil contains less than or equal to 0.0015 percent sulfur, by weight. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 33 of 35 

PART 7.0 OTHER SPECIFIC REQUIREMENTS 

MODIFIED CONDITION 

7.9 Acid Rain Requirements 

7.9.7 SO2 Allowance Allocations and NOX Requirements for each affected unit 

[40 CFR 73 (SO2) and 40 CFR 76 (NOx)] 

 2012 2013 2014 2015 2016 

SO2

allowances, 

under 

Tables 2, 3, 

or 4 of 40 

CFR part 

73. 

0 0 0 0 0 

EMISSION 

UNIT ID 

 CTG1 

EPA 

ID 

T1 

NOX limit This affected unit is not subject to the NOX

requirements in 40 CFR part 76. 

 2012 2013 2014 2015 2016 

SO2

allowances, 

under 

Tables 2, 3, 

or 4 of 40 

CFR part 

73. 

0 0 0 0 0 

EMISSION 

UNIT ID 

CTG2 

EPA 

ID 

T2 

NOX limit This affected unit is not subject to the NOX

requirements in 40 CFR Part 76. 

 2012 2013 2014 2015 2016 

SO2

allowances, 

under 

Tables 2, 3, 

or 4 of 40 

CFR part 

73. 

0 0 0 0 0 

EMISSION 

UNIT ID 

CTG3 

EPA 

ID 

T3 

NOX limit This affected unit is not subject to the NOX

requirements in 40 CFR Part 76. 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 34 of 35 

 2012 2013 2014 2015 2016 

SO2

allowances, 

under 

Tables 2, 3, 

or 4 of 40 

CFR part 

73. 

0 0 0 0 0 

EMISSION 

UNIT ID 

CTG4 

EPA 

ID 

T4 

NOX limit This affected unit is not subject to the NOX

requirements in 40 CFR Part 76. 

Note: The number of allowances allocated to Phase II affected units by U.S. EPA may change as a 

result of revisions to 40 CFR Part 73. In addition, the number of allowances actually held by 

an affected source in a unit account may differ from the number allocated by U.S. EPA. 

Neither of the aforementioned conditions necessitate a revision to the unit SO2 allowance 

identified in this permit (See CFR 72.84). 
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

PAGE 35 of 35 

Attachments 

D. U.S. EPA Acid Rain Program Phase II Permit Application
Title V Permit Amendment 

Effingham County Power, LLC Permit No.: 4911-103-0012-V-04-1 

Appendix Page 1 of 1 

ATTACHMENT D 

U.S. EPA Acid Rain Program Phase II Application 





Y:\Projects\2011\113-87509 Mackinaw RAI\120310 RAI\Final\R032211_509 Effingham RAI.docx

Golder Associates Inc.

6026 NW 1st Place

Gainesville, FL 32607 USA

Tel: (352) 336-5600 Fax: (352) 336-6603 www.golder.com

Golder Associates: Operations in Africa, Asia, Australasia, Europe, North America and South America

March 22, 2011 113-87509

Ms. Susan Jenkins, Environmental Engineer

Stationary Source Permitting Program

Georgia Department of Natural Resources

4244 International Parkway, Suite 120

Atlanta, Georgia 30354

RE: APPLICATION NO. 19810

MACKINAW POWER – EFFINGHAM COUNTY POWER PLANT

RESPONSE TO COMMENTS IN LETTERS OF DECEMBER 3, 2010 AND JANUARY 25, 2011

Dear Ms. Jenkins:

Mackinaw Power received comments from the Georgia Environmental Protection Division (EPD) in letters

dated December 3, 2010 and January 25, 2011, regarding the Prevention of Significant Deterioration 

(PSD) Application for the Effingham County Power Plant expansion project submitted in July 2010. 

Responses to Georgia EPD’s comments are presented as follows.

RESPONSES TO DECEMBER 3, 2010 LETTER

Comment 1. Georgia EPD is required to address both filterable and condensable particulate 

matter (CPM) in establishing enforceable emissions limits for particulate matter less 

than 10 microns (PM10) and fine particulate matter (PM2.5) in New Source Review 

(NSR) permits as of January 1, 2011. Mackinaw Power notes that PM10 and PM2.5

emissions for the combustion turbines (CTs) include filterable and back-half 

emissions. Is it correct to assume that the phrase “back-half emissions”

corresponds to CPM? Do the projected potential emissions of PM10 and PM2.5

include both filterable and CPM from the other applicable pieces of equipment? If 

not, please update the projected potential emissions for these two regulated NSR 

pollutants as found in the application.

Response: The projected potential PM emission for the project is based on total PM (filterable and 

condensable) for the proposed emission units, as appropriate. The phrase “back-half emissions” does 

correspond to CPM. Detailed calculations of back-half emissions for the proposed emission units were

presented in Appendix A (Tables A-2, A-4, A-6, A-8, A-10, and A-12). CPM emissions are based on a 

fraction of sulfur dioxide (SO2) converted to sulfur trioxide (SO3) in the combustion turbine (CT), in the 

duct burner, and in the selective catalytic reduction (SCR) and assuming all SO3 converts to ammonium 

sulfate. Potential hourly PM emissions presented in Table 2-1 and 2-2 for the CT include both filterable 

and condensable PM.

The PM emissions from the fuel gas heater and the auxiliary boiler were calculated using the emission 

factors from AP-42 for total PM, which includes filterable and condensable PM. The PM emissions from 

the cooling tower have no back-half component because there is no combustion process associated with 

the cooling tower. The PM emissions are calculated based on total dissolved solids in the amount of 

circulating water that is emitted from the tower in the form of drift.

Comment 2. Will the proposed new equipment use the same source of water as the existing 

equipment? Please explain.

Response: Yes, the proposed new equipment will use the same source of water as the existing 

equipment. The source of water for the facility is from the City of Savannah.
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Comment 3. Mackinaw Power proposes to combust fuel oil in the combustion turbines (CTs) 

and natural gas in the duct burners. Mackinaw Power has proposed best available 

control technology (BACT) emission limits for carbon monoxide (CO), volatile 

organic compounds (VOCs), and particulate matter (PM, PM10, and PM2.5) for fuel 

oil firing of the CTs with duct firing. This operational scenario is not included as a 

potential operating scenario in Tables 2-4 or 4-8 which define the facility‟s potential 

emissions as well as BACT economic analysis. Georgia EPD cannot consider 

permitting this operational scenario without the applicant providing for the 

scenario in the facility‟s potential emissions and subsequent BACT economic 

analysis and air impact assessment. Please revise Tables 2-4 and 4-8 and the air 

impact assessment (if applicable) to account for this operational scenario

Response: This scenario was not presented in the potential annual emissions calculation in Table 2-4

because this scenario does not produce the highest annual emissions among the oil-firing scenarios. The 

duct burner will always be fired with natural gas regardless of the CT fired with natural gas or oil. Since 

oil-firing is limited to 1,000 hours per year (hr/yr) and duct-firing is limited to 4,000 hr/yr per CT, if the CT 

is fired with oil for 1,000 hrs and the duct burner is also operating, then for the same annual scenario, the 

CT and duct burner, both firing natural gas, will be limited to 3,000 hr/yr. A revised Table 2-4 is attached, 

which includes two additional annual operating scenarios including oil-firing case based on CT and duct 

burner – one without startup and shutdown and one with startup and shutdown.

As shown, potential annual emissions for both new scenarios that include oil-firing based on CT and duct 

burner are less than the potential annual emissions for respective similar scenarios that include oil-firing 

case based on CT only. As a result, there is no need to revise Table 2-8, which is based on the worstcase annual emissions for the CTs and duct burners.

Comment 4. Mackinaw Power proposes a BACT emissions limit for CO for the operational 

scenario of natural gas combustion in the CT with duct firing of 10.5 ppmvd @ 15% 

oxygen. This emission rate corresponds to a CT operating at baseload at an 

ambient temperature of 95 deg F. This limit cannot be considered because the 

applicant used a limit of 10.0 ppmvd @15% oxygen in the BACT economic analysis 

noted in Table 4-8. Please update the application accordingly if Mackinaw Power 

request a CO BACT emissions limit of 10.5 ppmvd @15% oxygen. Note: The limit 

of 10.0 ppmvd @15% oxygen corresponds to the operational scenario of natural 

gas combustion in the CT with duct firing at an ambient temperature of 59 deg F.

Response: The economic analysis presented in Table 4-8 is based on an annualized cost of 

installing an oxidation catalyst system. Therefore, the annual operating scenario that produces the worstcase potential annual emissions was used to determine the cost-effectiveness value. As shown in 

Table 2-4, the potential annual emissions are based on operating scenarios at an annualized ambient 

temperature of 59 degrees Fahrenheit (°F). The carbon monoxide (CO) emission limit of 10.5 ppmvd at 

15-percent oxygen (O2) is based on ambient temperature of 95°F and does not represent the average 

annual operation. The purpose of the economic analysis is to present an annualized cost-effectiveness 

value based on the estimated potential annual emissions. The estimated emissions at 95°F and 20°F

provide a range of potential emissions that could occur for shorter durations and were considered in the 

air impact analysis.

Please note that the warm startup hourly emission rate of 153.6 pounds per hour (lb/hr) used in Table 4-8 

should have been 238.2 lb/hr. A revised Table 4-8 is attached with the corrected warm startup hourly 

emission rate for CO. This did not affect any other parts of the application.

Comment 5. On page 4 of the application, Mackinaw Power notes that, “For this Project, the

combustion process is based on lean premix staged combustion.... also referred 

to as DLN combustors.” On page 5 of the application, Mackinaw Power notes that, 

“... the CTs typically will operate between 50 and 100 percent of load for an annual 

average capacity factor of approximately 40 to 60 percent.”
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a. At what minimum CT load, for each fuel type, does DLN combustion begin (i.e., 

at what maximum load does diffusion flame combustion end)?

b. What is the maximum percent load at the end of a „warm startup”? Is it 

approximately 23.7% as stated in Table 2-3?

c. What is the maximum percent load at the end of a “cold startup”? Is it 

approximately 68.5% as stated in Table 2-3?

d. At what minimum CT load (per fuel type) is the SCR operational?

e. At what minimum CT load is water injection operational?

Response: a. The minimum load for Mode 6Q for natural gas is approximately 60 percent of the 

maximum load adjusted for ambient conditions.

Fuel oil combustion does not use the Mode 6Q combustion; rather water injection is used to reduce 

nitrogen oxides (NOx) emissions. DLN combustion is not used during fuel oil combustion.

b. The warm startup load of 23.7 percent is a time-period average instead of the actual load value at the 

end of warm startup. Based on data from the existing CTs, the actual load at the initiation of Mode 6Q 

was 112 MW or 68 percent load. The maximum percent load at the end of warm startup would be 

approximately 70 percent.

c. The maximum percent load at the end of cold startup would be approximately 70 percent.

d. For natural gas, the SCR is operational when required temperature and volumetric flow parameters are 

achieved and Mode 6Q has been initiated. Under most circumstances ammonia flow to the SCR is 

initiated within 5 minutes of achieving Mode 6Q. For fuel oil the SCR is operational when temperature 

and volumetric flow parameters are met at approximately 60 percent of maximum load adjusted for 

ambient conditions.

e. For fuel oil, water injection is operational at approximately 50 percent of maximum load adjusted for 

ambient conditions.

Comment 6. Mackinaw Power proposes BACT emissions limits for the applicable regulated 

NSR pollutants. The proposal does not include the following:

a. At what minimum loads (per fuel type) do these limits apply?

b. Averaging periods for each proposed BACT emission limit.

c. A discussion of BACT for periods of startup and shutdown of the combustion

turbines.

d. Short-term BACT emission limits or work practice standards for periods of 

startup and shutdown.

Response: a. For each natural gas and fuel oil-firing scenario, BACT emission limits for NOx, CO, 

and volatile organic compound (VOC) emissions from the CTs with and without duct burner firing are 

based on the maximum exhaust concentration expected for normal steady operation. Therefore, the 

proposed limits apply at operating loads between approximately 50 percent load and base load. Similarly, 

for particulate matter equal to or less than 10 microns (PM10) and particulate matter equal to or less than 

2.5 microns (PM2.5), the proposed BACT emission limits for the CTs, in units of lb/MMBtu, apply to 

operating loads between 50-percent load and base load.

b. The proposed averaging period for the NOx, CO, VOC, and PM10/PM2.5 BACT limits is a 24-hour block 

average. Continuous compliance with CO and NOx emissions limits will also be monitored with 

continuous emissions monitoring systems (CEMS).
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c. The proposed BACT emission limits for the CTs apply to steady-state normal operation between 

approximately 50-percent load and base load. Even though startup and shutdown of the CTs are a 

normal part of the power plant operation, they are not part of the steady-state CT operation.

Startup of the CTs is defined by the period when the CTs, the heat recovery steam generators (HRSGs), 

and the steam turbine are started in a sequential order until the combined-cycle system is in a steadystate fully operational mode. During the initial part of the startup, the CT must be held at low load as the 

other process equipment is started, and the load is gradually increased until the normal operating load

(approximately 50 percent or higher in this case) is achieved. The proposed CTs will be equipped with 

SCR, a post-combustion NOx control technology. However, during low CT loads (i.e., less than 50-

percent load), the SCR system cannot be turned on until the exhaust flow, temperature, and other 

operational parameters are within range. When temperatures are low, ammonia will not react completely 

with the NOx. The use of SCR during startup will also increase ammonia slip. Since SCR cannot be 

operated, NOx emissions during startup are higher than normal operation.

In addition, incomplete combustion at low loads results in higher CO and VOC emission rates. Postcombustion control, such as the oxidation catalyst system, requires specific exhaust temperature ranges 

to be fully effective. As a result, CO and VOC emissions are also higher during startup and shutdown 

than normal operation.

However, SO2 and PM10 emissions result from the characteristics and amount of the fuel burned. During 

low-load operation, the amount of fuel burned is less than during normal operation. Therefore, SO2 and 

PM10/PM2.5 emissions during startup and shutdown are lower than for normal operation.

d. The annual emissions rates proposed for the project includes emissions expected during 300 startups

and 300 shutdowns expected for the proposed CTs. The expected startup and shutdown emissions are

based on similar CTs currently operating at the facility. Since emission control is not technically feasible 

during startup and shutdown, the total annual emissions, which include startup and shutdown emissions 

are proposed as long-term BACT emissions limits (example: 12-month rolling NOx limit). Best practices 

will be used to minimize the number of startups.

Comment 7. Please conduct an air impact assessment for a requested operational scenario for 

the combustion of fuel oil in the combustion turbines during startup and 

shutdown.

Response: At this time, fuel oil startup and shutdown emissions data have not been obtained. When 

data are received, an air impact assessment shall be conducted.

Comment 8. On page 7 of the application Mackinaw Power notes, “To provide a conservative 

estimate of maximum pollutant emissions, the maximum emissions assume that 

the inlet chillers would be used when the ambient temperature is 95 deg F.”

a. Will the inlet chillers be used at non-base load operational scenarios that occur 

at 95 deg F?

b. Do the emission estimates in Tables 2-1, 2-2, and 2-4 reflect an operational 

scenario of use of inlet chillers at 95 deg F?

c. Is the use of inlet chillers irrespective of fuel burned in the combustion turbines?

Response: a. It is not anticipated that the inlet chillers will be used at non-base load operation that 

occur at 95 deg F. The inlet chillers are used to optimize the output of the facility.

b. Yes, inlet chiller operation at 95 deg F is assumed to be the same as operation at 59 deg F. The inlet 

chillers are expected to maintain the inlet air at 59 deg F on a 95 deg F day.

c. Yes, the use of inlet chillers are irrespective of fuel burned in the combustion turbines.
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Comment 9. The application appears to be silent on whether Mackinaw Power intends on 

construction and operating additional storage tanks for ammonia.

a. Will Mackinaw Power construct and operate additional ammonia storage at the

existing site? If so, please complete the applicable air permit application forms 

and please include the concentration of ammonia stored in these proposed new 

storage tanks.

Response: Mackinaw Power will construct two additional 17,000-gallon storage tanks containing 

19 percent aqueous ammonia. There are no applicable forms for tanks containing ammonia, which is an 

inorganic compound.

Comment 10. Please address the potential applicability of the proposed Boiler MACT standard to

applicable equipment.

Response: On June 4, 2010, the U.S. Environmental Protection Agency (EPA) proposed Maximum 

Achievable Control Technology standards for boilers (“Boiler MACT”). This rule, which was finalized on 

February 21, 2011, will reduce emissions of toxic air pollutants from existing and new industrial, 

commercial, and institutional boilers located at facilities classified as major and area source facilities. An 

area source facility emits or has the potential to emit less than 10 tons per year (TPY) of any single air 

toxic or less than 25 TPY of any combination of air toxics. The existing Effingham power plant is

classified as an area source facility and would remain as an area source facility after the proposed 

expansion project.

The final rule covers boilers located at area source facilities that burn coal, oil, or biomass or non-waste 

materials, but not boilers that burn only gaseous fuels or any solid waste. The proposed 17 million British 

thermal units per hour (MMBtu/hr) auxiliary boiler and the 8.75 MMBtu/hr fuel heater will be fired by 

natural gas only. Therefore, these units are not covered by the air toxics standards for industrial, 

commercial, and institutional boilers at area source facilities.

Comment 11. Greenhouse gas (GHG) emissions from the largest stationary sources will, for the 

first time, be covered by the Prevention of Significant Deterioration (PSD) and title v

Operating Permit Programs beginning January 2, 2011. In light of this requirement,

Georgia EPD requests that Mackinaw Power provide the following information:

a. Please conduct a “five-step” top-down BACT analysis for GHGs proposed to be

emitted by the new equipment. The U.S. EPA‟s website for Clean Air Act 

Permitting for Greenhouse Gases is at www.epa.gov/nsr/ghgpermitting.html.

Response: A five-step top-down BACT analysis for greenhouse gas (GHG) emissions for the 

proposed project is presented in Attachment A.

RESPONSES TO JANUARY 25, 2011 LETTER

Mackinaw Power proposes to install an oxidation catalyst as the best available control technology (BACT) 

for carbon monoxide (CO) and proposes an emission limit of 2.0 ppmvd at 15 percent oxygen when firing 

natural gas. For fuel oil firing, Mackinaw Power proposes an emission limit of 4.0 ppmvd at 15 percent

oxygen.

As requested by Georgia EPD, the air modeling performed for the project was reevaluated. Based on

information presented in the air permit application, the air modeling analysis is sufficient to address 

compliance with the National Ambient Air Quality Standards (NAAQS). From Table 6-9 of the application, 

the project’s CO impacts were predicted to be below the 1-hour and 8-hour average PSD Class II 

significant impact levels with the higher emission rates proposed in the application. With the lower CO 

emission rate now accepted with installation of CO oxidation catalyst, the project’s CO impacts will be 

lower and remain well below the significant impact levels and, therefore, well below the NAAQS, with no 

additional modeling needed to demonstrate compliance.
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As shown in Table 6-9 in the application, the project’s annual average NO2 impacts were predicted to be 

lower than the annual average PSD Class II significant impact level, using the 0.75 factor for conversion 

of NOx to NO2 emissions. This factor is recommended by EPA in the Guidelines on Air Quality Models 

(GAQM), updated through 2005 in Appendix W, 40 CFR 51. 

For the 1-hour average NO2 impacts, project impacts are presented without and with applying the 

0.75 factor, indicating in both cases that the project’s impacts are predicted to be greater than the 1-hour 

average significant impact level. As such, additional modeling was performed which including modeling 

background sources and adding in a non-modeled background concentration provided by GEPD. As 

shown in Table 6-11 of the application, model results for the 1-hour average NO2 concentrations are 

presented for 3 cases: modeling assumed 100 percent (1.0 factor) of predicted NOx concentrations were 

converted to NO2 concentrations; modeling assumed 75 percent (0.75 factor) of NOx concentrations were 

converted to NO2 concentrations, and modeling was based on using the plume volume molar ratio method 

(PVMRM) approach with NO2/NOx ambient equilibrium ratio of 0.90 and in-stack NO2/NOx ratio of 0.10. 

In all cases, the maximum 1-hour average NO2 concentrations were predicted to be less than the NAAQS 

even with the assumption that 100 percent of NOx concentrations were assumed to be NO2

concentrations. For that case, the maximum total 1-hour average NO2 concentration was predicted to be 

130.4 micrograms per cubic meter (μg/m3

), less than the NAAQS of 188 μg/m3. For the other cases, the 

maximum total 1-hour average NO2 concentrations were also predicted to be less than the NAAQS. 

Therefore, no additional modeling is required to demonstrate compliance the NAAQS. 

It should be noted that on March 1, 2011, EPA released guidance memorandum for modeling NO2

impacts (Additional Clarification Regarding Applications of Appendix W Modeling Guidance for the 1-hour 

NO2 National Ambient Air Quality Standard). In that memorandum, EPA recommended use of the 

0.80 factor as a default ambient ratio for the 1-hour NO2 standard under Tier 2 without additional 

justification. In addition, EPA recommended general acceptance of 0.50 as a default in-stack NO2/NOx

ratio for input to PVMRM option, in the absence of more appropriate source-specific information on instack ratios. These recommendations are consistent with the approaches used for the later two cases 

discussed previously. 

Thank you for your consideration of this information. If you have any questions, please do not hesitate to 

call us at (352) 336-5600. 

Sincerely, 

GOLDER ASSOCIATES INC. 

Robert C. McCann Salahuddin K. Mohammad 

Principal and Air Group Leader Senior Project Engineer 

cc: M. Lydon, Mackinaw Power 

Enclosures 

RCM/SKM/edk/nav/tz 
March 2011 113-87509

Operating

Scenario

CT(NG) Base Load 8,760 4,760 3,760 4,760 1,601 2,601

CT&DB(NG) Base Load 0 4,000 4,000 3,000 4,000 3,000

CT(Oil) Base Load 0 0 1,000 0 1,000 0

CT(Oil) DB(NG) Base Load 0 0 0 1,000 0 1,000

Warm start b0 0 0 0 749 749

Cold start b 0 0 0 0 50 50

Shutdown b 0 0 0 0 300 300

Fuel: NG NG Oil Oil d NG NG NG Downtime c 0 0 0 0 1060 1,060

Load: Base Base w/DB Base Base w/DB Warm Cold ShutPollutant Temp: 59 °F 59 °F 59 °F 59 °F start start down TOTAL 8,760 8,760 8,760 8,760 8,760 8,760

One Combustion Turbine

 SO2 2.5 3.2 3.1 3.7 0.39 1.12 0.11 11.1 12.4 12.6 12.6 10.1 10.1

 PM/PM10/PM2.5 9.7 13.5 17.8 18.3 2.25 6.38 0.63 42.3 50.1 54.1 52.4 44.8 43.1

 NOx 17.1 27.6 76.2 85.2 67.7 144.0 21.7 74.9 95.8 125.4 124.7 139.1 138.4

 CO 12.5 52.0 92.8 132.3 238.2 289.1 62.0 54.7 133.7 173.9 173.9 266.1 266.1

 VOC (as methane) 3.3 5.9 9.3 11.9 0.74 2.10 0.21 14.6 19.8 22.7 22.7 19.5 19.5

 Sulfuric Acid Mist 0.5 0.5 0.6 0.6 0.08 0.22 0.02 2.2 2.2 2.3 2.2 1.8 1.7

 Lead 0.00 0.00 0.027 0.027 0.00 0.00 0.00 0.0 0.0 0.0 0.0 0.0 0.0

Two Combustion Turbines

 SO2 5.1 6.3 6.2 7.4 0.8 2.2 0.2 22 25 25 25 20 20

 PM/PM10 19.3 27.1 35.6 36.5 4.5 12.8 1.3 84.6 100.1 108.3 104.9 90 86

 NOx 34.2 55.1 152 170 135 288 43 150 192 251 249 278 277

 CO 25.0 104 185.6 264.6 476 578 124 109 267 348 348 532 532

 VOC (as methane) 6.7 11.8 18.6 23.7 1.5 4.2 0.4 29.2 39.5 45.5 45.5 39.0 39.0

 Sulfuric Acid Mist 1.0 1.0 1.2 1.2 0.2 0.4 0.0 4.3 4.4 4.5 4.5 3.5 3.5

 Lead 0.00 0.00 0.055 0.055 0.000 0.000 0.000 0.000 0.000 0.027 0.027 0.027 0.027

a Based on 59 o

F ambient inlet air temperature. 

b Event min/event hr/event No. of events/yr hr/yr

Warm start 155 2.58 290 749

Cold start -- 5 10 50

Shutdown -- 1 300 300

c Unit downtime hours are based on a minimum 2 hours of shutdown before a warm start and a minimum of 48 hours shutdown before a cold start.

downtime hr downtime

Event before event No. of events/yr hr/yr

Warm start 2 290 580

Cold start 48 10 480

Total = 1060

d DB will be fired with natural gas only. So in this scenario, CT will be fired with oil and DB will be fired with natural gas.

Source: Mackinaw Power, 2010, Golder Associates, 2010.

Maximum emissions (lb/hr) a 

TABLE 2-4 (Revised 3/21/11)

SUMMARY OF MAXIMUM POTENTIAL ANNUAL EMISSIONS FOR THE PROPOSED COMBUSTION TURBINES AND DUCT BURNERS

EFFINGHAM PLANT EXPANSION PROJECT

Operating Hours

Maximum Emissions (tons/year)

Table 2-4 & GHG Effingham Expansion Emissions.xlsx/tab2-4 CT MAX ANNUAL
March 2011 113-87509

Oxidation Catalyst

System

Cost Items/Emissions Parameters for GE 7FA CT

ANNUALIZED COSTS (AC) ($): See Table 4-7 629,110

UNCONTROLLED CO EMISSIONS

CO emissions for NG Firing and without DB (TPY) : 3.0 ppmvd, 12.5 lb/hr for 1,601 hours (see Table 2-4) 10.0

CO emissions for NG Firing and with DB (TPY) : 10.0 ppmvd, 52.0 lb/hr for 4,000 hours (see Table 2-4) 104.0

CO emissions for fuel oil-firing (TPY) : 20.0 ppmvd, 92.8 lb/hr for 1,000 hours (see Table 2-4) 46.4

CO emissions from startup/shutdown (TPY) :

Warm - 238.2 lb/hr (749 hrs), Cold - 289.1 lb/hr (50 hrs), Shutdown - 

62 lb/hr (300 hrs) 105.7

Potential CO emissions from one CT (TPY) : 266.1

CONTROLLED CO EMISSIONS (a)

CO emissions for NG Firing and without DB (TPY) : 2.0 ppmvd 6.7

CO emissions for NG Firing and with DB (TPY) : 2.0 ppmvd, 80% control 20.8

CO emissions for fuel oil-firing (TPY) : 4.0 ppmvd, 80% control 9.3

CO emissions from startup/shutdown (TPY) : 80% Control 21.1

Potential controlled CO emissions from one CT (TPY) : 57.9

Reduction in CO Emissions (TPY): 208

UNCONTROLLED VOC EMISSIONS

VOC emissions for NG Firing and without DB (TPY) : 1.4 ppmvd, 3.3 lb/hr for 3,760 hours (see Table 2-4) 6.2

VOC emissions for NG Firing and with DB (TPY) : 2.0 ppmvd, 5.9 lb/hr for 4,000 hours (see Table 2-4) 11.8

VOC emissions for fuel oil-firing (TPY) : 3.5 ppmvd, 9.3 lb/hr for 1,000 hours (see Table 2-4) 4.7

Potential VOC emissions from one CT (TPY) : 22.7

CONTROLLED VOC EMISSIONS (b)

VOC emissions for NG Firing and without DB (TPY) : 1.0 ppmvd 4.4

VOC emissions for NG Firing and with DB (TPY) : 1.0 ppmvd, 50% control 5.9

VOC emissions for fuel oil-firing (TPY) : 1.75 ppmvd, 50% control 2.3

Potential Controlled VOC emissions from one CT (TPY) : 12.7

Reduction in VOC Emissions (TPY): 10

Total Reduction in CO and VOC Emissions (TPY): 218

Cost Effectiveness: $ per ton of CO and VOC Removed 2,883

Notes:

(a) Controlled emissions are calculated based on an estimated CO BACT limit of 2.0 ppmvd for natural gas firing with an oxidation catalyst system. For the 

 oil-firing case and startup/shutdown cases, controlled emissions are based on 80% control.

(b) Controlled emissions are calculated based on an estimated 50% control of VOC emissions. For NG-firing only case, controlled emissions are based on 

 the BACT limit of 1.0 ppmvd with an oxidation catalyst system.

TABLE 4-8 (Revised 3/22/11)

COST EFFECTIVENESS CALCULATION FOR OXIDATION CATALYST SYSTEM FOR ONE GE 7FA CT

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ATTACHMENT A
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1.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS

1.1 Introduction

The United States Environmental Protection Agency (EPA) published the Prevention of Significant 

Deterioration (PSD) and Title V Permitting Guidance for Greenhouse Gases (GHGs) in November, 2010.

On June 3, 2010, EPA issued a final rule that “tailors” the applicability provisions of the PSD and Title V 

programs to enable EPA and states to phase in permitting requirements for GHGs in a common sense 

manner (“Tailoring Rule”).

Since January 2, 2011, GHGs are a regulated NSR pollutant under the PSD major source permitting 

program when they are emitted by new sources or modifications in amounts that meet the Tailoring Rule’s 

set of applicability thresholds, which phase in over time.

For PSD purposes, GHGs are a single air pollutant defined as the aggregate group of the following six 

gases:

 Carbon dioxide (CO2)

 Nitrous oxide (N2O)

 Methane (CH4)

 Hydrofluorocarbons (HFCs)

 Perfluorocarbons (PFCs)

 Sulfur hexafluoride (SF6)

In Tailoring Rule Step 1, beginning on January 2, 2011 and continuing through June 30, 2011, GHG

sources will become subject to PSD if they increase GHG emissions by 75,000 TPY of CO2 equivalent 

(CO2e) or more if they undergo PSD permitting anyway, either for new construction or for modification 

projects based on emissions of non-GHG pollutants. These sources are referred to as “anyway” sources.

In Tailoring Rule Step 2, beginning on July 1, 2011, and continuing thereafter, anyway PSD sources will 

remain subject to PSD. In addition, sources with the potential to emit 100,000 TPY CO2e or more of GHG 

will be considered major sources for PSD permitting purposes. Additionally, any physical change or 

change in the method of operation at a major source resulting in a net GHG emissions increase of 75,000 

TPY CO2e or more will be subject to PSD review.

Once major sources become subject to PSD, these sources must, in order to obtain a PSD permit, meet 

the various PSD requirements such as, they must apply Best Available Control Technology (BACT),
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The proposed Effingham expansion project is a major modification and subject to PSD review. In light of 

the new Tailoring Rule requirements, the Georgia EPD has determined that the GHGs emitted from the 

proposed project is subject to PSD review and has requested a BACT analysis for the GHGs.

This section presents the proposed BACT for these pollutants. The approach to the BACT analysis is 

based on the regulatory definitions of BACT, as well as consideration of EPA’s current policy guidelines 

requiring a “top-down” approach. The CAA and corresponding implementing regulations require that a 

BACT analysis be conducted on a case-by-case basis taking into consideration the amount of emissions 

reductions that each available emissions-reducing technology or technique would achieve, as well as the 

energy, environmental, economic and other costs associated with each technology or technique.

EPA recommends that permitting authorities continue to use the Agency’s five-step “top down” BACT 

process to determine BACT for GHGs. In brief, the top-down process calls for all available control 

technologies for a given pollutant to be identified and ranked in descending order of control effectiveness.

The permit applicant should first examine the highest-ranked (“top”) option. The top-ranked options 

should be established as BACT unless the permit applicant demonstrates to the satisfaction of the 

permitting authority that technical considerations, or energy, environmental, or economic impacts justify a 

conclusion that the top ranked technology is not “achievable” in that case. If the most effective control 

strategy is eliminated in this fashion, then the next most effective alternative should be evaluated, and so 

on, until an option is selected as BACT.

EPA has broken down this analytical process into the following five steps:

Step 1: Identify all available control technologies.

Step 2: Eliminate technically infeasible options.

Step 3: Rank remaining control technologies.

Step 4: Evaluate most effective controls and document results.

Step 5: Select the BACT.

The Clean Air Act specifies that BACT cannot be less stringent than any applicable standard of 

performance under the New Source Performance Standards (NSPS). As of November, 2010, EPA has 

not promulgated any NSPS that contain emissions limits for GHGs.

EPA believes that in BACT reviews, it is important to consider options that improve the overall energy 

efficiency of the source or modification – through technologies, processes and practices at the emitting 

unit. In general, a more energy efficient technology burns less fuel than a less energy efficient technology 

on a per-unit-of-output basis. Thus, considering the most energy efficient technologies in the BACT 
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analysis helps reduce the products of combustion, which includes not only GHGs but other regulated 

NSR pollutants (e.g., NOX, SO2, PM/PM10/PM2.5, CO, etc.). Thus, EPA emphasizes that energy efficiency 

should be considered in BACT determinations for all regulated NSR pollutants (not just GHGs).

The following sections provide the required BACT analysis.

1.2 Combined Cycle CTs

This section contains the BACT analysis for the GHG emissions from the combined cycle CTs.

1.2.1 Step 1 – Identify All Available Control Technologies

The first step in the top-down BACT process is to identify all “available” control options. Available control 

options are those air pollution control technologies or techniques (including lower-emitting processes and 

practices) that have the potential for practical application to the emissions unit and the regulated pollutant 

under evaluation.

EPA has placed potentially applicable control alternatives identified and evaluated in the BACT analysis 

into the following three categories:

 Inherently Lower-Emitting Processes/Practices/Designs

 Add-on Controls

 Combinations of Inherently Lower Emitting Processes/Practices/Designs and Add-on 

Controls

EPA recommends that the BACT analysis should consider potentially applicable control techniques from 

all of the above three categories.

In the BACT analysis, GHGs are considered as a single air pollutant, which is the aggregate group of the 

six principal gases, CO2, N2O, CH4, HFCs, PFCs, and SF6. CO2 emissions result from the oxidation of

carbon in the fuel. CH4 emissions result from incomplete combustion and N2O emissions result primarily 

from low temperature combustion. CO2, N2O, and CH4 are the principal GHGs that will be emitted from 

the proposed CTs at the Effingham Power Plant.

The combustion of natural gas emits almost 30 percent less CO2 than oil, and just under 45 percent less 

CO2 than coal (source: www.naturalgas.org). The proposed CTs at the Effingham Power Plant will be 

fired primarily with natural gas. Ultra low sulfur diesel fuel will only be used as backup fuel and will be 

limited to a maximum of 1,000 hrs/yr per CT. The definition of BACT in 40 CFR 52.21(b)(12) includes use 

of clean fuels as a pollution control technique. The PSD and the Title V Permitting Guidance for GHGs 

states that clean fuels which would reduce GHG emissions should be considered while recognizing at the 

same time that the BACT analysis does not need to include a clean fuel option that would fundamentally 
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redefine the source. Therefore, the proposed CTs will be fired with “clean fuels” as included in the 

definition for BACT in the CAA Part 169(3).

EPA recommends that permit applicants and permitting authorities should identify all “available” GHG 

control options that have the potential for practical application to the source under consideration. In the 

PSD and Title V Permitting Guidance for GHGs, EPA emphasizes on two mitigation approaches for 

CO2 – energy efficiency and carbon capture and storage (CCS).

Emissions of CH4 and N2O from CTs are extremely low. As a result, control options for these pollutants 

are not discussed except the oxidation catalyst system, which controls CH4 as an added benefit. 

Effingham is proposing to install oxidation catalyst system for each CT.

Energy Efficiency

Energy efficiency falls under the general category of lower-polluting processes/practices. Applying

technologies, measures and options that are energy efficient translates not only in the reduction of 

emissions of the particular regulated NSR air pollutant undergoing BACT review, but it also may achieve 

collateral reductions of emissions of other pollutants. There are different categories of energy efficient 

improvements:

 Technologies or processes that maximize the efficiency of the individual emissions unit

 Options that could reduce emissions from a new green field facility by improving the 

utilization of thermal energy and electricity that is generated and used on site

When the efficiency of the power generation process is increased, less fuel is burned to produce the 

same amount of electricity. This provides the benefits of lower fuel costs and reduced air pollutant 

emissions (including CO2). Several recent BACT determinations for GHG emissions concluded that highefficiency power generation technology is the only available and feasible control technology. Efficient 

power generation is also considered to be technically feasible for the proposed CTs at the Effingham 

Power Plant.

Carbon Capture and Storage (CCS)

Carbon capture and storage (CCS) falls under the category of add-on controls, which are air pollution 

control technologies that remove pollutants from a facility’s emissions stream. EPA classifies CCS as an 

add-on pollution control technology that is “available” for large CO2-emitting facilities including fossil fuelfired power plants and industrial facilities with high-purity CO2 streams. As a result, EPA requires that 

CCS be considered in Step 1 of the BACT analysis.

CCS is composed of three main components: CO2 capture and/or compression, transport, and storage.

Carbon Capture - Before CO2 gas can be sequestered, it must be captured as a relatively pure gas, so 

that it can be feasibly stored. Most power plants and other large point sources use air-fired combustors, a 
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process that exhausts CO2 diluted with nitrogen. Based on US Department of Energy, flue gas from 

natural gas combined cycle plants contains only 3-6 percent CO2. For effective carbon sequestration, the 

CO2 in these exhaust gases must be separated and concentrated.

The most likely options currently identifiable for CO2 separation and capture include:

 Absorption (chemical and physical)

 Adsorption (physical and chemical)

 Low-temperature distillation

 Gas separation membranes

 Mineralization and biomineralization

Carbon Transport – After the CO2 is captured, it must be transported to a carbon sequestration site.

Pipelines are the most common method for transporting large quantities of CO2 over long distances. 

Shipping CO2 via pipeline involves compressing gaseous CO2 to a pressure above 1,160 pounds per 

square inch (psi), to increase CO2 density and make it easier and less expensive to ship. A CO2 pipeline 

would be similar to a high pressure natural gas pipeline and is technically feasible. CO2 also can be 

transported as a liquid in seagoing vessels or via tankers on roads or railways. In these instances, the 

CO2 is held in insulated tanks at low temperatures and relatively low pressures.

Carbon Storage – In a CCS system, CO2 is captured, it is transported, if necessary, and then stored. 

Geologic formations such as depleted oil and gas reservoirs, unmineable coal seams, and underground 

saline formations are potential options for long-term storage. Pressurized CO2 is injected into the deep 

geologic formations through drilled wells. Under high pressure, CO2 turns to liquid and can move through 

a formation as a fluid. Once injected, the liquid CO2 tends to be buoyant and will flow upward until it 

encounters a barrier of non-porous rock, which can trap the CO2 and prevent further upward migration. 

When CO2 is injected into a coal seam, it is adsorbed onto the coal surfaces, and methane gas is 

released and produced in adjacent wells. There are other mechanisms for CO2 trapping as well: CO2

molecules can dissolve in brine; react with minerals to form solid carbonates; or adsorb in the pores of the 

porous rock.

Deep saline formations, which are layers of porous rock saturated with brine present an enormous 

potential for geologic storage of CO2. However, the industry doesn’t have as much experience with saline 

formations as they have acquired through resource recovery from oil and gas reservoirs and coal seams. 

There are ongoing research focused on storage in organic rich shale, which is a thin horizontal layer of 

sedimentary rock with low vertical permeability and in basalt formations, which are geologic formations of 

solidified lava. Other possible options include liquid storage in the ocean.
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Oxidation Catalyst

Catalytic oxidation technology, which is primarily designed to reduce CO emissions (VOC emissions are 

also reduced to a lesser extent) will also reduce CH4 emissions. Oxidation catalysts operate at elevated 

temperatures. In the presence of an oxidation catalyst, excess O2 in the exhaust reacts with CH4 to form 

CO2. No chemical reagent is necessary. The oxidation catalyst is typically a precious metal catalyst. 

None of the catalyst components is considered toxic.

Oxidation catalysts are susceptible to fine particles suspended in the exhaust gases that can foul and 

poison the catalyst. Catalyst poisoning reduces catalyst activity and pollutant removal efficiencies. The 

most effective oxidation of CO and VOC emissions is achieved if the catalyst bed is located prior to the 

HRSG in the high-temperature region.

1.2.2 Step 2 – Identification of Technically Feasible Control Alternatives

Under the second step of the top-down BACT analysis, a potentially applicable control technique listed in 

Step 1 may be eliminated from further consideration if it is not technically feasible for the specific source 

under review. EPA considers a technology to be potentially applicable if it has been demonstrated in 

practice or is available.

Energy Efficiency

Efficient power generation is considered to be technically feasible for the proposed CTs at the Effingham 

Power Plant. This is discussed in detail in Step 5.

Carbon Capture and Storage (CCS)

In the PSD and Title V permitting guidance for GHGs, EPA states that it does not believe CCS will be a 

technically feasible BACT option in certain cases at this time. To establish that an option is technically 

feasible, the permitting record should show either that an available control option has been demonstrated 

in practice or is available and applicable, with the term “applicable” generally meaning a technology can 

reasonably be installed and operated on the source type under consideration. EPA recognizes the 

significant logistical hurdles that the installation and operation of a CCS system presents and that sets it 

apart from other add-on controls that are typically used to reduce emissions of other regulated pollutants 

and already have an existing reasonably accessible infrastructure in place to address waste disposal and 

other offsite needs. It should also be noted that while CCS may be available according to EPA, it is not 

“commercially available”. All current CCS projects for power plants are primarily in the demonstration 

stage.

Logistical hurdles for CCS may include obtaining contracts for offsite land acquisition (including the 

availability of land), the need for funding (including, for example, government subsidies), timing of 

available transportation infrastructure, and developing a site for secure long term storage. Not every 
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source has the resources to overcome the offsite logistical barriers necessary to apply CCS technology to 

its operations.

The Effingham Power Plant is located near Savannah, GA. Based on the maps presented at the NETL’s 

Carbon Sequestration Storage webpage, there are no oil and gas reservoirs or unmineable coal seams

near the facility. The nearest such geologic storage areas are more than 200 km away and a very long 

pipeline would be required if storage is desired in such areas. There are deep saline formations near the 

facility location. However, little is much less is known about saline formations because they lack the 

characterization experience that industry has acquired through resource recovery from oil and gas 

reservoirs and coal seams. Based on NETL maps, there are basalt formations near the facility, which are

geologic formations of solidified lava. However, carbon storage potential of basalt formations is currently 

being researched. Therefore, logistical hurdle does exist for the application of CCS at the Effingham 

Power Plant.

There are no CCS systems commercially available for full-scale power plants in the United States. On 

February 3, 2010, President Obama established an Interagency Task Force on Carbon Capture and 

Storage, composed of 14 Executive Departments and Federal Agencies. The Task Force, co-chaired by 

the Department of Energy (DOE) and the Environmental Protection Agency (EPA), was charged with 

proposing a comprehensive and coordinated strategy to overcome the barriers to the widespread, costeffective deployment of carbon capture and storage (CCS) within ten years, with a goal of bringing five to 

ten commercial demonstration projects online by 2016. These projects, to be deployed with the help of 

federal funding, are intended to demonstrate a range of current generation CCS technologies applied to 

coal-fired power plants and industrial facilities. Therefore, the application of CCS to power plants is very 

much in the development stage.

In November 2010, EPA published the final rule for Federal Requirements Under the Underground 

Injection Control (UIC) for CO2 Geologic Sequestration (GS) Wells, as authorized by the Safe Drinking 

Water Act (SDWA). The final rule establishes new federal requirements for the underground injection of 

carbon dioxide for the purpose of long-term underground storage, or geologic sequestration, and a new 

well class – Class VI – to ensure the protection of underground sources of drinking water (USDWs) from 

injection related activities. Therefore, authorization must be obtained from EPA prior to geologic 

sequestration. Permitting for a Class VI well may take a long time and may be very expensive, as this 

may include drilling deep holes, testing, etc., prior to use as an injection well. Indeed, these requirements 

may require an exploratory well to assess the formation that can take over 18 months to drill and test.

Based on these considerations, it can be reasonably concluded that CCS is not applicable to the 

Effingham Expansion project, and consequently not technically feasible, even if the type of equipment 

needed to accomplish the compression, capture, and storage of GHGs are determined to be generally 

available from commercial vendors.
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Oxidation Catalyst

Catalytic oxidation is a feasible control technology for CH4. As discussed in Section 1.1, oxidation 

catalyst system is primarily designed to control CO emissions with the following reaction:

2CO + O2 2CO2

The oxidation catalyst will reduce CH4 with the following reaction:

CH4 + 2O2 CO2 + 2H2O

Effingham is proposing to install oxidation catalyst system to control CO emissions, which will also reduce 

CH4 as an added benefit. However, there is a trade-off between controlling CH4 emissions and additional 

CO2 emissions generated. But since the global warming potential of CH4 is 21 times the global warming 

potential of CO2, there will be a reduction in the global warming potential by using the oxidation catalyst 

system.

1.2.3 Step 3 – Rank Remaining Control Technologies

After the list of all available controls is narrowed down to a list of the technically feasible control 

technologies in Step 2, Step 3 of the top-down BACT process calls for the remaining control technologies 

to be listed in order of overall control effectiveness for the regulated NSR pollutant under review. The 

most effective control alternative (i.e., the option that achieves the lowest emissions level) should be listed 

at the top and the remaining technologies ranked in descending order of control effectiveness.

Based on the discussion in Steps 1 and 2, the only technically feasible control option for GHGs is energy 

efficiency.

1.2.4 Step 4 – Economic, Energy, and Environmental Impacts

Under Step 4 of the top-down BACT analysis, economic, energy, and environmental impacts must be 

evaluated for each option remaining under consideration.

The “top” control option should be established as BACT unless the applicant demonstrates, and the 

permitting authority agrees, that the energy, environmental, or economic impacts justify a conclusion that 

the most stringent technology is not “achievable” in that case. If the most stringent technology is 

eliminated in this fashion, then the next most stringent alternative is considered, and so on.

Where GHG control strategies affect emissions of other regulated pollutants, EPA recommends that 

applicants should consider the potential trade-offs between emissions of GHGs and emissions of other 

regulated NSR pollutants. For example, controlling CO, VOC, or CH4 emissions with an oxidation catalyst 

system creates GHG emissions in the form of CO2. But because of the higher global warming potential of 

CH4, there will be a reduction in global warming potential. Energy efficiency improvements generally 
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reduce emissions of all pollutants resulting from combustion processes, so no significant trade offs in 

emissions expected from energy efficiency improvements.

The proposed CTs at the Effingham Power plant will be operating at the combined-cycle mode, which is 

more energy efficient than simple cycle. Therefore, no additional improvements are necessary.

The CCS option was eliminated in Step 2 as not technically feasible for the project. Although EPA 

considers CCS as available, it is not commercially available. Indeed, EPA recognizes that at present 

CCS is an expensive technology, largely because of the costs associated with CO2 capture and 

compression. In the Guidance, EPA states that even if not eliminated in Step 2 of the BACT analysis, on 

the basis of the current costs of CCS, CCS is more likely to be eliminated from consideration in Step 4 of 

the BACT analysis, even in some cases where underground storage of the captured CO2 near the power 

plant is feasible.

1.2.5 Step 5 – Select the BACT

In Step 5 of the BACT determination process, the most effective control option not eliminated in Step 4 

should be selected as BACT for the pollutant and emissions unit under review and included in the permit.

BACT

Energy efficiency, the only remaining and feasible control technology is selected as BACT for the GHG 

emissions from the proposed CTs at the Effingham Power Plant. Energy efficiency plays a major role in 

affecting GHG emissions and EPA expects that more emphasis will be given to energy efficiency in GHG 

BACT analysis in permit applications after July, 2011.

The efficiency of the generation technology in producing electricity and fuel utilized are the most important 

aspects in greenhouse gas (GHG) emissions from electric generation projects. Together, efficiency and 

fuel type dictate the amount of GHG emissions per unit of generation.

An important measure of the efficiency for an electrical generating facility is the units’ heat rate. Heat rate 

is a measurement of how efficiently a generator uses heat energy. It is expressed as the number of BTUs 

of heat required to produce a kilowatt-hour of energy. A heat rate of 3,413 Btu/kW-hr reflects a 

conversion efficiency of 100 percent from thermal energy to electrical energy.

The proposed CTs heat rate and energy efficiency was compared to data obtained from the US Energy 

Information Administration (US EIA). Based on data provided in the Annual Energy Review 2009, the 

approximate heat rate for electricity for fossil-fueled power plants in the U.S. in 2009 was 9,854 Btu/kW-hr 

(34.7 percent efficiency) (http://www.eia.doe.gov/emeu/aer/txt/ptb1306.html). Based on US EIA’s 2009 

annual review of the electrical power industry, the reported average heat rate for natural gas firing was 

8,157 Btu/kW-hr (41.8 percent efficiency) including all types of generation (http://www.eia.doe.gov/cneaf/ 
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electricity/epa/epat5p3.html). Of the generation types, the average heat rates are (http://www.eia.doe.gov/ 

cneaf/electricity/epa/epat5p4.html):

 Steam turbine – 10,399 Btu/kW-hr (32.8 percent efficiency)

 Gas turbine – 11,497 Btu/kW-hr (29.7 percent efficiency)

 Internal combustion – 9,973 Btu/kW-hr (34.2 percent efficiency)

 Combined cycle – 7,543 (45.3 percent efficiency) Btu/kW-hr

Using actual data to estimate the power output of the steam turbine (ST) and incremental power output 

due to duct firing, the heat rate and efficiency of the proposed 2x1 combined cycle power block can be 

estimated as follows:

 Gas-firing only – 6,852 Btu/kW-hr (49.8 percent efficiency) (Baseload at 59°F, heat input 

– 2 CTs at 1,859 MMBtu/hr each, power output – 2 CTs at 173.8 MW each and ST at 

195 MW for a total 542.6 MW)

 Gas-firing along with duct burner firing – 7,051 Btu/kW-hr (48.4 percent efficiency)

(Baseload at 59°F, heat input – 2 CTs at 1,859 MMBtu/hr each and 2 DBs at 

470 MMBtu/hr, power output – 2 CTs at 173.8 MW each, 59 MW incremental power for 

each DB, and ST at 195 MW for a total 660.6 MW)

 Oil-firing only – 7,032 (48.5 percent efficiency) (Baseload at 59°F, heat input – 2 CTs at 

1,962 MMBtu/hr each, power output – 2 CTs at 181.5 MW each and ST at 195 MW for a 

total 558 MW)

Using these heat rates and an operating scenario of 1000 hrs/yr of CT on oil-firing, 4000 hrs/yr of CT and 

DB on gas firing, and 3,760 hrs/yr of CT only on gas firing, the overall heat rate of the proposed power 

block can be estimated as 6,963 Btu-kW-hr (49 percent efficiency). These estimated heat rates are well 

below the approximate heat rate for all fossil-fueled power plants in the U.S. in 2009 and the proposed 

power block is 14.3 percent more efficient. When comparing to all types of generation using natural gas, 

the proposed power block will be 8 percent more efficient than all generation using natural gas.

When compared to existing combined cycle generation, the proposed power block will be more efficient

than existing combined cycle plants. This is a result of utilizing a combined cycle configuration where the 

exhaust heat from an efficient combustion turbine/electric generator is utilized to generate steam in the 

heat recovery steam generator (HRSG). The steam is used in a matching steam turbine to generate 

additional electrical energy. The proposed project will be designed to produce the maximum efficiency for 

the size of the project (approximately 660 MW).

BACT Emission Limit

The fuel utilized determines the amount of GHG emissions per unit of energy. For example, based on

40 CFR 75 (Acid Rain) Appendix G – Determination of CO2 Emissions, the emission factors for CO2 are 

118.86 lb CO2/MMBtu for natural gas and 162.29 lb CO2/MMBtu for distillate oil. For individual operating 

scenarios of the proposed power block, using the heat rate and the GHG emission factors, GHG 
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emissions can be calculated in units of mass/MWh, which is a measure of GHG emission per unit energy 

output. Emissions of CO2, N2O, and CH4 were calculated for the individual scenarios of natural gas-firing 

with no duct firing, natural gas-firing with duct firing, and fuel oil-firing, which are presented in Table A-1. 

The CO2 emission rates were determined to be as follows:

 Natural gas-firing with no duct firing – 814.2 lb CO2/MWh

 Natural gas-firing with duct firing – 837.9 lb CO2/MWh

 Fuel oil firing – 1,141.3 lb CO2/MWh

 Overall – 862.4 lb CO2/MWh (3,760 hrs/yr NG with no duct firing, 4,000 hrs/yr NG with 

duct firing, 1,000 hrs/yr fuel oil-firing) [(814.2 x 3760 + 837.9 x 4000 + 1141.3 x 

1000)/8760]

As part of EPA’s clean energy initiatives, EPA developed the Emissions & Generation Resource 

Integrated Database (eGRID) as a resource tool in assessing GHG emissions. eGrid is a comprehensive 

source of data on the environmental characteristics of almost all electric power generated in the United 

States with data available based on a variety of geographic regions and locations. Data is also available 

on a plant specific basis. Based on the latest available eGrid data the following are the emissions of CO2

on a generation basis for generation facilities located in the same sub-region as the project:

 SERC Reliability Corporation’s (SERC’s) Southeastern Sub-Region (major portions of 

Georgia, Alabama and a small portion of Mississippi) – Total Fossil Fuel –

1,894.3 lb CO2/MWh

 SERC Southeastern Sub-Region – Non-Baseload – 1,551.1 lb CO2/MWh, 21.7 lb 

N2O/GWh, 28.5 lb CH4/GWh

 Georgia Power Company – 1,617.5 lb CO2/MWh for all generation (includes nuclear); 

1,936.9 lb CO2/MWh for fossil fuel combustion

When compared, it can be seen that the proposed power blocks GHG emission rates that are significantly 

lower than the existing generation facilities in the region. Therefore, the GHG on a generation basis are 

much lower than the existing generation and when operated would likely displace less efficient generation 

resulting in overall GHG reduction. For example, when operational, if the project’s generation displaced 

non-baseload generation, with an overall CO2 emission rate of 862.4 lb/MWh, there would be an 

1,804,474 ton per year reduction [(1551.1 − 862.4) lb/MWh x 598.2 MW (overall power calculated from 

3760 hrs at 542.6 MW, 4000 hrs at 660.6 MW, and 1000 hours at 558 MW) x 8760 hrs/yr] in the SERC 

Southeastern sub-region emissions.

The conclusions from the comparisons for energy efficiency and GHG emissions are as follows:

 The proposed project will be one of the most efficient electric generating facilities in 

Georgia.

 The proposed project will result in GHG emissions that are of the lowest in the SERC 

sub-region and Georgia.
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 The proposed project will likely reduce GHG emissions in SERC sub-region and Georgia 

by displacing less efficient and greater GHG emitting technologies.

The use of natural gas and distillate fuel oil as backup and a combined cycle configuration for the project 

is proposed as BACT. This is consistent with the definition of BACT, which allows “a design, equipment, 

work practice, operational standard, or combination thereof, may be prescribed instead to satisfy the 

requirement for the application of best available control technology.” A numerical emission limit is not 

necessary or appropriate for GHG emissions based on the project’s design and fuel use.

1.3 Auxiliary Boiler

Mackinaw Power is proposing an auxiliary boiler with a maximum design heat input rating of 17 MMBtu/hr,

which will be exclusively fueled by pipeline quality natural gas. The boiler will be used during the startup 

sequences of the CTs to provide steam to the steam cycle and shorten the cold and warm start duration, 

thus decreasing start-up emissions. Mackinaw Power proposes to limit the hours of operation of the 

auxiliary boiler to 2,500 hr/yr. Using a CO2 emission factor of 116.86 lb/MMBtu (Table C-1; 40 CFR 98, 

Subpart C), the auxiliary boiler will have a potential to emit 1,987 lb/hr or approximately 1 ton/hr of CO2

emissions. The CO2 emissions potential is negligible.

Also, combustion of natural gas emits less CO2 than combusting oil or coal and is considered as clean 

fuel. The auxiliary boiler will be fired by natural gas only.

1.4 Fuel Gas Heater

The maximum heat input rate of the proposed fuel heater is 8.75 MMBtu/hr. Using the same CO2

emission factor as for the auxiliary boiler, the fuel heater will have a potential to emit 1,023 lb/hr or 

0.51 ton/hr of CO2 emissions. This rate is negligible.

The fuel heater will be fired by natural gas only, which will have the potential to emit less CO2 than firing 

other fossil fuel like oil.

1.5 Cooling Towers

The proposed cooling towers will not emit any GHGs.

1.6 Fuel Oil Storage Tank

The proposed fuel oil storage tank will not emit any GHGs.
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Per Unit Per Unit Per Unit

Heat Input Power Output Output Output Output

Unit (MMBtu/hr) (MW) (lb/hr) (tons/hr) (lb/MWh) (lb/hr) (tons/hr) (lb/GWh) (lb/hr) (tons/hr) (lb/GWh)

Scenario 1: Baseload, 59 F, Natural Gas-Firing, CT Only

CT1 1,859 173.80 118.86 (a) 220,901 110.5 2.20E-04 (b) 0.4 0.0002 2.2E-03 (b) 4.1 0.0020

CT2 1,859 173.80 118.86 (a) 220,901 110.5 2.20E-04 (b) 0.4 0.0002 2.2E-03 (b) 4.1 0.0020

ST (d) -- 195 -- -- -- -- -- -- -- -- --

3,717 542.6 441,803 220.9 814.2 1 0.0004 1.5 8 0.004 15.1

Scenario 2: Baseload, 59 F, Oil-Firing, CT Only

CT1 1,962 181.50 162.29 (c) 318,425 159.2 1.32E-03 (b) 2.6 0.0013 6.6E-03 (b) 13.0 0.0065

CT2 1,962 181.50 162.29 (c) 318,425 159.2 1.32E-03 (b) 2.6 0.0013 6.6E-03 (b) 13.0 0.0065

ST (d) -- 195 -- -- -- -- -- -- -- -- --

3,924 558.0 636,850 318.4 1,141.3 5 0.0026 9.3 26 0.013 46.5

Scenario 3: Baseload, 59 F, Natural Gas-Firing, CT and DB

CT1 1,859 173.80 118.86 (a) 220,901 110.5 2.20E-04 (b) 0.4 0.0002 2.2E-03 (b) 4.1 0.0020

CT2 1,859 173.80 118.86 (a) 220,901 110.5 2.20E-04 (b) 0.4 0.0002 2.2E-03 (b) 4.1 0.0020

DB1 (d) 470 59 118.86 (a) 55,864 27.9 2.20E-04 (b) 0.1 0.0001 2.2E-03 (b) 1.0 0.0005

DB2 (d) 470 59 118.86 (a) 55,864 27.9 2.20E-04 (b) 0.1 0.0001 2.2E-03 (b) 1.0 0.0005

ST (d) -- 195 -- -- -- -- -- -- -- -- --

4,657 660.6 553,531 276.8 837.9 1 0.0005 1.6 10 0.005 15.5

(a) Appendix G - Determination of CO2 Emissions, 40 CFR Part 75. Natural gas-firing CO2 lb/MMBtu = 1040 scf/MMBtu x (1/385) scf CO2/lb-mole x 44 lb/lb-mole = 118.86 lb/MMBtu.

(b) Table C-2, Subpart C, 40 CFR Part 98. Emission factors in kg/MMBtu were converted to lb/MMBtu by multiplying by 2.204.

(c) Appendix G - Determination of CO2 Emissions, 40 CFR Part 75. Oil-firing CO2 lb/MMBtu = 1420 scf/MMBtu x (1/385) scf CO2/lb-mole x 44 lb/lb-mole = 162.29 lb/MMBtu.

(d) Steam turbine power output and incremental power output due to duct burner firing were obtained from the actual operating data of a 4x1 power plant with GE 7FA CTs.

(e) N2O and CH4 emissions per unit output are presented in units of pound per gigawatt-hour (lb/GWh), where 1 GW = 1000 MW.

TABLE A-1

GHG EMISSIONS FOR THE PROPOSED 2X1 POWER BLOCK

EFFINGHAM PLANT EXPANSION PROJECT

CO2 Emissions N2O Emissions (e) CH4 Emissions (e)

Emission Rate

(lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

Emission Emission Emission

Factor Emission Rate Factor Emission Rate Factor

Table 2-4 & GHG Effingham Expansion Emissions.xlsx/GHG