# 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 Ai r Quality Act, O.C.G.A. Section 12-9-1, et seq and the Georgia Rules for Air Quality Control, Chapter 391-3-1, ado pted pursuant to and in effect under the Act, the P ermittee described above is issued a construction and operat ing permit for:

A nominal net 668 megawatt (MW) combined cycle powe r generation facility to consist of two natural gas fired and distillate fuel oil fired combustion turbines (CTs) and associated heat recovery steam generators (HRS Gs) including duct burners, one steam turbine, one fuel heater, one auxiliary boiler, one 10-cell mechanic al draft cooling tower, one six-cell mechanical draft coolin g tower and one distillate fuel oil storage tank.

This Permit Amendment is conditioned upon complianc e with all provisions of The Georgia Air Quality Ac t, 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. 4 911-103-0012-V-04-0. Unless modified or revoked, t his 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 Direc tor 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 applicatio ns upon which this Permit Amendment or Permit No. 4 911-103- 0012-V-04-0 are based; supporting data entered ther ein or attached thereto; or any subsequent submitta l or supporting data; or for any alterations affecting t he emissions from this source.

This Permit Amendment is further subject to and con ditioned upon the terms, conditions, limitations, s tandards, or schedules contained in or specified on the attached 35 pages, which pages are a part of this Permit Amendm ent, 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 COLLEC TION) ............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 prop osed project will consist of:

• Two (2) nominal 180-MW GE Model 7FA combustion turb ines (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-N Ox (DLN) combustor technology for natural gas combustion and water injection for fuel oil com bustion;

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

• The combined CT/HRSG stack is equipped with selecti ve catalytic reduction (SCR) and catalytic oxidation for control of nitrogen oxides (NO x 

### ) and carbon monoxide (CO)emissions, respectively;

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

• One (1) natural gas-fired auxiliary boiler with a h eat input capacity of 17 million British Thermal Units per hour (10 6 

### Btu/hr). The boiler will be equipped with low-NO x 

### burners (LNBs) to control NO x 

### emissions;

• One (1) natural gas-fired fuel gas heater with a he at input capacity of 8.75 x 10 6 

### Btu/hr. The heater will be equipped with low-NO x 

### burners (LNBs) to control NO x 

### 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 f or the inlet chiller systems. The tower has a mechanical draft counter flow design and equipped w ith 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.

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### PART 3.0 REQUIREMENTS FOR EMISSION UNITS

Note: Except where an applicable requirement specif ically 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) spec ified 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 10 6 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 NO x Combustor AB

FP2 Natural Gas-Fired Fuel

Gas Heater with a 8.75 x 10 6 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 NO x 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 NO x Combustor

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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 10 6 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 NO x Combustor

DB4 HRSG, for CTG4 with

Supplemental Natural Gas- Fired Duct Burner with a 470 x 10 6 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 th is permit may also apply to emission units listed a bove. The lists of applicable requirements/standards and corresponding permit conditions are intended as a compliance tool and may not be definitive.

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### 3.3 Equipment Federal Rule Standards

NEW CONDITIONS 3.3.11 The Permittee shall construct and operate th e 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 rul e. 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 appr oval 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 commenc ed 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 t ime. 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 comm encement date. [40 CFR 52.21(r)(2)]

3.3.13 The Permittee shall comply with all applicab le provisions of the Acid Rain Program as found in 40 CFR Part 72 “Permit Regulations”, 40 CF R Part 73 “Sulfur Dioxide Allowance System”, 40 CFR Part 75 “Continuous Emiss ions 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 applicab le 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 applicab le 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," f or operation of the Auxiliary Boiler with emission unit ID No. AB2. [40 CFR 60 Subparts A and Dc]

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### 3.3.16 The following stacks are defined for purpose s of this Permit: [40 CFR 52.21(j)]

a. Combustion Turbine with emission unit ID No. CTG 3 and Duct Burner with emission unit ID No. DB3 share a common stack.

b. Combustion Turbine with emission unit ID No. CTG 4 and Duct Burner with emission unit ID No. DB4 share a common stack.

3.3.17 The following definitions of startup and shu tdown, 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 hou rs.

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 c ombustion is zero to 300 minutes or the time for reception of an operating load of s eventy (70) percent of maximum load adjusted for ambient conditions.

iii. Time allocated to a cold startup for natural g as combustion is zero to 300 minutes or the time for the turbine to reach operat ing 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 le ss 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 c ombustion is zero to 155 minutes or the time for reception of an operating l oad of seventy (70) percent of maximum load adjusted for ambient conditions.

iii. Time allocated to a warm startup for natural g as combustion is zero to 155 minutes or the time for the turbine to reach operat ing stage equivalent to mode 6Q and ammonia injection has occurred.

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### 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 tur bine load is at least 10.4 percent of maximum load adjusted for ambient c onditions.

ii. Time allocated to a warm startup for fuel oil c ombustion is zero to 60 minutes or the time for reception of an operating l oad of seventy (70) percent of maximum load adjusted for ambient condit ions.

iii. Time allocated to a hot startup for natural ga s combustion is zero to 60 minutes or the time for the turbine to reach operat ing stage equivalent to mode 6Q and ammonia injection has occurred.

d. Unit shutdown is defined as the period of time f rom steady state operation to cessation of combustion turbine firing. Time alloc ated to a shutdown is zero to sixty minutes.

3.3.18 The Permittee shall limit the hours of start up 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 opera tion (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 du ring fuel oil combustion. [40 CFR 52.21(j); and PSD Avoidance for SO 2 

### and Sulfuric Acid Mist]

3.3.20 The Permittee shall limit the hours of opera tion 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 opera tion of auxiliary boiler with emission unit

ID No. AB2 to 2,500 hours during any twelve consecu tive 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 emi ssion unit ID Nos. CTG3 and CTG4 a dry low NOx combustor for natural gas combus tion. [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 s team injection for distillate fuel oil combustion. [40 CFR 52.21(j)]

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### 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, s elective 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 emiss ions occurring during startup, shutdown, and malfunction, in excess of 210 tons du ring any twelve consecutive months during natural gas combustion.

b. Nitrogen Oxides (NOx) emissions, including emiss ions occurring during startup, shutdown, and malfunction, in excess of 67 tons dur ing any twelve consecutive months during fuel oil combustion.

c. Carbon Monoxide (CO) emissions, including emissi ons occurring during startup, shutdown, and malfunction, in excess of 236 tons du ring any twelve consecutive months during natural gas combustion.

d. Carbon Monoxide (CO) emissions, including emissi ons occurring during startup, shutdown, and malfunction, in excess of 46 tons dur ing 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 I D Nos. CTG3 and CTG4, each, while firing natural gas during all periods of oper ation, greenhouse gas (GHG, expressed as CO 2e 

### ) emissions in excess of 863,953 tons during any tw elve 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 I D Nos. CTG3 and CTG4, each, while firing fuel oil during all periods of operati on, greenhouse gas (GHG, expressed as CO 2e 

### ) emissions in excess of 159,603 tons during any tw elve consecutive months. [40 CFR 52.21(j)]

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### 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, green house gas (GHG, expressed as CO 2e 

### ) emissions in excess of 111,837 tons during any twel ve 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 CO 2e 

### ) 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 d uring all periods of operation, greenhouse gas (GHG, expressed as CO 2e 

### ) 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 duc t 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 e missions in excess of 0.060 lb SO 2 

### /MMBtu heat input; or

b. Any gases which contain SO 2 

### 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 SO 2 

### and Sulfuric Acid Mist; and 40 CFR 60.4365 (subsum ed for SO 2 

### )]

b. Ultra low sulfur diesel fuel that contains no mo re 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 SO 2 

### and Sulfuric Acid Mist; and 40 CFR 60.4365 (subsum ed for SO 2 

### )]

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### 3.3.34 The Permittee shall only fire pipeline quali ty 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 u nit 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, PM 10 

### , PM 2.5 

### for DB3, DB4, AB2, and FP2, 40 CFR 52.21(j) for VOC fro m AB2 and FP2; 391-3-1- .02(2)(d)(subsumed) for AB2 and FP1; 391-3-1-.02(g) (subsumed); PSD Avoidance for SO 2 

### 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 st ack 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 p pmvd, 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 pp mvd, corrected to 15% oxygen, on a 3-hour average. [40 CFR 52.21(j)]

c. Contain volatile organic compounds (VOC) in exce ss 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 st ack 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 s tartup and shutdown. [40 CFR 52.21(j) and 40 CFR 60.4320(a) for (subsume d)]

b. Contain carbon monoxide (CO) in excess of 2.0 pp mvd, corrected to 15% oxygen, on a 3-hour average, excluding periods of startup a nd shutdown. [40 CFR 52.21(j)]

c. Contain volatile organic compounds (VOC) in exce ss of 2.0 ppmvd, corrected to 15% oxygen, on a 3-hour average, excluding periods of startup and shutdown. [40 CFR 52.21]

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### d. Contain particulate matter (PM) in excess of the following numerical limits, on a 3-hour average, including periods of startup and sh utdown [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 (PM 10 

### ) in excess of the following numerical limits, on a 3-hour average, including pe riods 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 (PM 2.5 

### ) in excess of the following numerical limits, on a 3-hour average, including pe riods 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 great er than ten (10) percent opacity. [40 CFR 52.21(j); 391-3-1-.02(2)(b)(subsumed) for C TG3/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 i n 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

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### 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 o r CT4 equal to or greater than as determined to allow a drift eliminator effectivenes s of 0.0005% guaranteed. The cooling towers will utilize high efficiency drift e liminators as best available control technologies (BACT) to limit particulate matter emi ssions from the cooling towers. The limit of this permit condition applies during all t imes 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 manufactu rer for fuel storage tank with emission unit ID No. T01. This equipment shall be employed at all times applicable equipment is in operation, including sta rtup, shutdown, and malfunction.

b. Installation and operation of submerged fuel fil l pipes on the fuel storage tank with emission unit ID No. T01. This equipment shal l be employed at all times applicable equipment is in operation, including sta rtup, shutdown, and malfunction.

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

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### PART 4.0 REQUIREMENTS FOR TESTING

4.1 General Testing Requirements

NEW CONDITION 4.1.4 Performance and compliance tests shall be con ducted 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 w ith 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 determinati on 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 alterna tive,

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 samp ling time for each run shall be one hour,

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

i. Method 7E shall be used to determine the nitroge n 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 opa city,

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 con vert particulate matter, carbon monoxide, sulfur dioxide, and nitrogen oxide concen trations (i.e., grains/dscf for PM, ppm for gaseous pollutants), as determined usin g 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

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### 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 annua l 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 follo wing 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 s hall be used for the determination of fuel oil sulfur content.

o. Method 25A shall be used for the determination o f concentrations of volatile organic compounds. The concentration of formaldehyde measu red 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 sampli ng 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, sh all be used to determine concentrations of PM10 and PM2.5 to demonstrate com pliance with emission limits in Permit Condition 3.3.36d, 3.3.36e, and 3.3.36f.

Minor changes in methodology may be specified or ap proved by the Director or his designee when necessitated by process variables, ch anges in facility design, or improvement or corrections that, in his opinion, re nder 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 pr oduction rate at which each affected facility will be operated on natural gas , but not later than 180 days after the initial sta rtup of each affected facility, the Permittee shall cond uct 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 th e results of each performance tests:

a. For purposes of this condition, the term “affect ed facility” is defined as each combined cycle combustion turbine and duct burner system wit h 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.

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### [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 s atisfy the initial performance test requirements for SO 2 

### emissions in accordance with 40 CFR 60.4415. [40 CFR 60.4415 for SO 2 

### , PSD Avoidance for SO 2 

### and Sulfuric Acid Mist emissions]

The performance tests for carbon monoxide and volat ile organic compounds shall be conducted concurrently.

4.2.2 Within 60 days after achieving the maximum pr oduction rate at which each affected facility will be operated on fuel oil , but not later than 180 days after the initial sta rtup 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 res ults of each performance tests:

a. For purposes of this condition, the term “affect ed facility” is defined as each combined cycle combustion turbine and duct burner system wit h 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 affecte d 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 wi th Condition 3.3.36d.i. [40 CFR 52.21 and 391-3-1-.02(6)(b)1.(i)]

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### f. Performance tests on each affected facility for PM 10 

### 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 PM 2.5 

### 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 s atisfy the initial performance test requirements for SO 2 

### emissions in accordance with 40 CFR 60.4415. [40 CFR 60.4415 for SO 2 

### , PSD Avoidance for SO 2 

### and Sulfuric Acid Mist emissions]

The performance tests for carbon monoxide and volat ile organic compounds shall be conducted concurrently.

4.2.3 Subsequent SO 2 

### 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 wr itten report of the results of each performance tests: [40 CFR 60.4415]

a. For purposes of this condition, the term “affect ed facility” is defined as each combined cycle combustion turbine and duct burner system wit h 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 SO 2 

### 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 wr itten report of the results of each performance tests: [40 CFR 60.4415]

a. For purposes of this condition, the term “affect ed facility” is defined as each combined cycle combustion turbine and duct burner system wit h 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).

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### 4.2.5 All CEMS and continuous monitoring systems re quired 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 i n 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

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### PART 5.0 REQUIREMENTS FOR MONITORING (Related to Da ta Collection)

5.2 Specific Monitoring Requirements

NEW CONDITIONS 5.2.8 The Permittee shall install, calibrate, maint ain, 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 NO x 

### concentration and diluent concentration (either oxy gen 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 ox ides emissions rates shall also be recorded in pound per million Btu heat input, and p pm 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 C FR 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 burn er stack specified in Condition 3.3.16. The one-hour average carbon monoxide emiss ions rates shall also be recorded in pound per million Btu heat input, and ppm correc ted to 15 percent oxygen on a dry basis. The diluent concentration shall be expresse d in percent. Each CO diluent CEMS must be installed and certified according to P erformance Specification 4 and 4A in appendix B of The Procedures for Testing and Monitoring Sources o f 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-.0 2(6)(b)1)]

5.2.9 The Permittee shall install, calibrate, maint ain, and operate monitoring devices for the measurement of the indicated parameters on the foll owing equipment. Data shall be recorded at the frequency specified below. Where s uch performance specification(s) exist, each system shall meet the applicable perfor mance specification(s) of the Division's monitoring requirements.

a. The quantity of natural gas, in cubic feet, burn ed 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)]

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### c. The quantity of natural gas, in cubic feet, burn ed in each duct burner with emission unit ID Nos. DB3 and DB4. Data shall be recorded c ontinuously. [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, burn ed in the auxiliary boiler with emission unit ID No. AB2. Data shall be recorded m onthly. [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, burn ed 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 shutdo wn, for each combustion turbine with emission unit ID Nos. CTG3 and CTG4 while firi ng 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. Da ta 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 Monitorin g 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 ac quired by the carbon monoxide CEMS required by Condition 5.2.8b. The Permittee shall maintain records specifying the results of the daily CEMS dr ift tests and quarterly accuracy assessments under Appendix F, Procedure 1. In addi tion, 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. T he 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.

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### b. The Relative Accuracy Test Audit (RATA) shall be conducted annually or every four operating quarters (not to exceed eight calend ar quarters) whichever is greater. For the purpose of this condition an operating quar ter 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 requi red by Condition 5.2.8b, the Permittee may supplement the emissions data with da ta obtained by conducting sampling using the methods prescribed in Condition 4.1.4. T he Permittee shall maintain records, which identify periods during each calendar month f or which CO emissions data have not been obtained for 75 percent of the turbine operati ng hours during the month, include reasons for not obtaining sufficient data and a des cription 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 un it(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) li sted above with the regulatory citation 40 CFR 70.6(a)(3)(i) are included for the purpose o f 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 performa nce 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 O 2 (or CO 2 ) 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/modifie d 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 average s which is used to calculate a 3-hour rolling average

. 

### 5.2.14 The Permittee shall comply with the performa nce 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 O 2 are monitored with a CEMS that is certified under 40 CFR Part 75, Appendix A. B. Verification of Operational Status (new/modifie d 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 average s which is used to calculate a 3-hour rolling average

.

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### PART 6.0 OTHER RECORD KEEPING AND REPORTING REQUIRE MENTS

6.1 General Record Keeping and Reporting Requiremen ts

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 e missions, exceedances, and excursions shall be reported as it relates to the project spec ified 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 thi s Condition and Condition 6.1.4, any condition that is detected by monitoring or rec ord keeping which is specifically defined, or stated to be, excess emissions by an ap plicable requirement)

i. Any unit operating period in which the 30 unit o perating day rolling average NOx emission rate from each combined combustion tur bine/duct burner stack exceeds 15 ppmvd @ 15% oxygen while burning natural gas. The definition of a “30 unit operating day average NOx emission ra te” 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 tur bine/duct burner stack exceeds 42 ppmvd @ 15% oxygen while burning fuel oi l. 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 4 0 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 Con dition 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 tha t indicates that emissions (or opacity) do not meet the applicable emission limita tion or standard consistent with the averaging period specified for averaging the re sults of the monitoring)

i. Any twelve consecutive month total hours of oper ation of auxiliary boiler with emission unit ID No. AB2 which exceeds 2,500 hours during all periods of operation. [40 CFR 52.21]

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### ii. Any twelve consecutive month total hours of ope ration from burning ultra low sulfur diesel fuel, for each combustion turbine wit h emission unit ID No. CGT3 and/or CGT4 which exceeds 1,000 hours during a ll periods of operation. [40 CFR 52.21 and PSD Avoidance for SO 2 

### and Sulfuric Acid Mist]

iii. Any twelve consecutive month total hours of op eration for each duct burner with emission unit ID No. DB3 and/or DB4 which exce eds 4,000 hours during all periods of operation. [40 CFR 52.21]

iv. Any twelve consecutive month total hours of sta rtup 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 fol lowing emission units which has a sulfur content in excess of 0.5 grains per 10 0 standard cubic feet: combustion turbines (emission unit ID Nos. CTG3 and CTG4), duct burners (emission unit ID Nos. DB3 and DB4), boiler (emissi on 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 SO 2 

### and Sulfuric Acid Mist; and 40 CFR 60.4365(subsumed)]

vi. Any time fuel oil is burned in the combustion t urbines (emission unit ID Nos. CTG3 and CTG4) which has a weight percent sulfur co ntent 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 SO 2 

### and Sulfuric Acid Mist; and 40 CFR 60.4365(subsumed)]

vii. Any three-hour rolling average NOx emission ra te, determined in accordance with Condition 5.2.8a, which exceeds 2.0 ppmvd at 1 5% oxygen for each combined combustion turbine and duct burner stack s pecified in Condition 3.3.16 when the combustion turbine is fired with na tural gas, excluding periods of startup and shutdown. For purposes of t his 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 r ate, 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 s pecified in Condition 3.3.16 when the combustion turbine is fired with fu el oil excluding periods of startup and shutdown. For purposes of this conditi on, each clock hour begins a new one-hour average. [40 CFR 52.21 and 40 CFR 60.4320(a)(subsumed)]

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### ix. Any twelve consecutive month total NOx emission s (tons) from each combined combustion turbine and duct burner stack s pecified in Condition 3.3.16 when the combustion turbine is fired with na tural 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 s pecified in Condition 3.3.16 when the combustion turbine is fired with fu el 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 1 5% oxygen for each combined combustion turbine and duct burner stack s pecified in Condition 3.3.16 when the combustion turbine is fired with na tural gas excluding periods of startup and shutdown. For purposes of this cond ition, each clock hour begins a new one-hour average. [40 CFR 52.21]

xii. Any three-hour rolling average CO emission rat e, determined in accordance with Condition 5.2.8b, which exceeds 2.0 ppmvd at 1 5% oxygen for each combustion turbine and duct burner stack specified in Condition 3.3.16 when the combustion turbine is fired with fuel oil exclu ding periods of startup and shutdown. For purposes of this condition, each clo ck hour begins a new onehour average. [40 CFR 52.21]

xiii. Any twelve consecutive month total CO emissio ns (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 wh ich exceeds 236 tons during all periods of operation. [40 CFR 52.21]

xiv. Any twelve consecutive month total CO emission s (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 emission s (expressed as CO 2e 

### ) from each combustion turbine with emission unit ID Nos. CTG3 and CTG4 while firing natural gas which exceeds 863,953 tons durin g all periods of operation. [40 CFR 52.21]

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### xvi. Any twelve consecutive month total GHG emissio ns (expressed as CO 2e 

### ) from each combustion turbine with emission unit ID Nos. CTG3 and CTG4 while firing fuel oil which exceeds 159,603 tons during a ll periods of operation. [40 CFR 52.21]

xvii. Any twelve consecutive month total GHG emissi ons (expressed as CO 2e 

### ) from each duct burner with emission unit ID Nos. DB3 and DB4 while firing natural gas which exceeds 111,837 tons during all p eriods of operation. [40 CFR 52.21]

xviii. Any twelve consecutive month total GHG emiss ions (expressed as CO 2e 

### ) 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 emissio ns (expressed as CO 2e 

### ) from the fuel gas heater with emission unit ID No. FP2 w hile firing natural gas which exceeds 4,560 tons during all periods of oper ation. [40 CFR 52.21]

c. Excursions: (means for the purpose of this Condi tion and Condition 6.1.4, any departure from an indicator range or value establis hed for monitoring consistent with any averaging period specified for averaging t he results of the monitoring)

None to be reported.

6.2 Specific Record Keeping and Reporting Requireme nts

NEW CONDITIONS Recordkeeping Requirements 6.2.15 The Permittee shall monitor the sulfur conte nt 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 se miannual 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 SO 2 

### 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 uni t 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 SO 2 

### and Sulfuric Acid Mist]

a. Fuel oil receipts obtained from the fuel supplie r certifying that the fuel oil contains less than or equal to 0.0015 percent sulfur, by wei ght.

### 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 de monstrates that the fuel oil contains less than or equal to 0.0015 percent sulfu r, by weight.

6.2.17 The Permittee shall retain the following fue l usage records based on monitoring required by Condition 5.2.9. These records (including calcu lations) shall be maintained as part of the monthly record suitable for inspection or submi ttal. [391-3-1-.02(6)(b)1 and 40 CFR 70.6(a)(3)(i)]

a. Monthly natural gas usage in each combustion tur bine 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 wi th 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 turbin e 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 u sage 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 per iod plus the totals for the previous eleven consecutive months. [40 CFR 52.21]

e. The twelve consecutive month total natural gas u sage in each duct burner with emission unit ID Nos. DB3 and DB4. A twelve consec utive 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 usag e in each combustion turbine with emission unit ID Nos. CTG3 and CTG4. A twelve cons ecutive 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 u sage 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 pre vious 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 u sage in the fuel gas heater with emission unit ID No. FP2. A twelve consecutive mon th total shall be the total for a month in the reporting period plus the totals for t he 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 monitor ing 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 r ecords as they relate to the startup and shutdown of each combustion turbine with emission u nit 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, ty pe of startup (cold, warm or hot start), and the time (minutes) attributed to shutdo wn. If the turbine was not in operation on any given day, the record shall so not e.

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

c. The twelve consecutive month total hours attribu ted to startup and shutdown on a combined basis.

d. The turbine load at which the Permittee initiate d fuel oil combustion for each startup to verify compliance with Conditions 3.3.17 a.i, 3.3.17b.i, and 3.3.17c.i.

6.2.20 The Permittee shall use the hour meter requi red 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 eac h calendar month. A twelve consecutive month total shall be the total for a mo nth 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 s uitable 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 requi red 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 mo nth 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 s uitable 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 requi red 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 mon th total shall be the total for a month in the reporting period plus the totals for t he previous eleven consecutive months. These records (including calculations) shall be mai ntained 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 3 0-day rolling average NOx emission rate (in ppm at 15 percent oxygen) for each combustion turbi ne and its paired duct burner (emission unit ID Nos. CTG3/DB3 and CTG4/DB4), usin g the NOx hourly emission rate determined in accordance with Condition 5.2.8a. Fo r 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 (emis sion 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, d etermined 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 o f 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 c ombusted, in tons per month, of NOx, from each combustion turbine and its paired duct bu rner (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 mo nthly 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 oxid es emissions (in tons) from each combustion turbine and its paired duct burner (emis sion unit ID Nos. CTG3/DB3 and CTG4/DB4) for each fuel type combusted. A twelve c onsecutive 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) sha ll 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 paire d 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 (mill ion Btu per hour), determined in accordance with the procedures of Appendix F, 40 CF R 75, and the one-hour average carbon monoxide emission rate (pound per million Bt u), determined in accordance with Condition 5.2.8b. Only the one-hour carbon monoxid e emission rates (pound per million Btu) that have been determined to be valid hourly e mission 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 car bon monoxide mass emission rates (lb/hr) to determine and record in accordance with the require ments of Condition 6.2.27, and all hourly carbon monoxide mass emissions rates acquire d in order to meet the minimum data requirement of Condition 5.2.11 to determine the mo nthly carbon monoxide mass emission rate, in tons per month, from each combust ion turbine and its paired duct burner (emission unit ID Nos. CTG3/DB3 and CTG4/DB4) for e ach fuel type combusted. The monthly carbon monoxide mass emission rate from eac h turbine and duct burner combination shall be calculated as follows:

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

Where, ECO equals the total carbon monoxide mass em issions (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 tot al operating time (hours) of the combustion turbine/duct burner combination during t he month, and TGD equals the number of hours of valid emissions data including a ll hourly emissions data acquired to meet the minimum data requirement contained in Cond ition 5.2.12. These records (including calculations) shall be maintained as par t 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 monoxi de emissions (in tons) from each combustion turbine and its paired duct burner (emis sion unit ID Nos. CTG3/DB3 and CTG4/DB4) for each fuel type combusted. A twelve c onsecutive 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 calcu lations) shall be maintained as part of the monthly record suitable for inspection or submi ttal. [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 Li mits 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 (express ed as CO 2e 

### ), in tons, from each of the following units and fuel types during all periods o f operation. The Permittee shall use the applicable greenhouse gas emission factors and glob al 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. C TG3 and CTG4 while firing natural
gas.

b. Combustion turbines with emission unit ID Nos. C TG3 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 w hile firing natural gas.

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

These records (including calculations) shall be mai ntained 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 e missions (expressed as CO 2e 

### ), in tons, from each of the following units and fuel type duri ng all periods of operation. The Permittee shall use the applicable greenhouse gas e mission 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. C TG3 and CTG4 while firing natural
gas.

b. Combustion turbines with emission unit ID Nos. C TG3 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 w hile firing natural gas.

e. Fuel gas heater with emission unit ID Nos. FP2 w hile 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 mo nthly 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 Condit ion 3.3.40, the Permittee shall maintain records documenting that the drift eliminators on t he cooling tower with emission unit ID Nos. CT3 and CT4 have been designed to meet the app licable limit. Such records shall be submitted for review during the first quarterly rep ort 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 wri tten notification as follows:

[40 CFR 52.21 and 40 CFR 60.7]

a. A notification of the actual date of initial sta rtup of each combustion turbine (emission unit ID Nos. CTG3, CTG4), each duct burne r (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 (emi ssion 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 ac cordance with the application, plans, specifications and supporting documents subm itted 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 f ollowing information for each quarterly period ending March 31, June 30, September 30, and Decembe r 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 oper ation of boiler (emission unit ID No. AB2), each duct burner (emission unit ID Nos. D B3 and DB4), each combustion turbine (emission unit ID No. CTG3 and C TG4) 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 reta ined 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 combusti on turbines, for each month in the quarterly reporting period. The reports sha ll 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 combusti on turbines, for each month in the quarterly reporting period. The reports sha ll 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 CO 2e 

### 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 Cond ition 6.2.31.

g. The twelve consecutive month total GHG emissions (reported as CO 2e 

### in tons) from each combustion turbine with emission unit ID Nos. CTG3 and CTG4 while burning fuel oil for each month in the quarterly re porting 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 CO 2e 

### in tons) from each duct burner with emission unit ID Nos. DB 3 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 CO 2e 

### in tons) from the boiler with emission unit ID No. AB2 for e ach month in the quarterly reporting period. The reports shall be prepared fr om the records retained in Condition 6.2.31.

j. The twelve consecutive month total GHG emissions (reported as CO 2e 

### 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 p repared 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 wi th fuel sulfur content limitations as specified in Permit Conditions 3.3.33 and 3.3.34. The Permit tee shall submit the following as part of the quarterly report required by Permit Conditio n 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 SO 2 

### 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 transporta tion 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 ver ify and document that each shipment of ultra low sulfur distillate fuel oil received for c ombustion in CGT3 and/or CGT4 complies by either of the following means:

i. Fuel oil receipts obtained from the fuel supplie r 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 o f sampling and analysis which have been specified or approved by the Division whi ch 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 SO 2 

### Allowance Allocations and NO X 

### Requirements for each affected unit [40 CFR 73 (SO 2 

### ) and 40 CFR 76 (NOx)]

2012 2013 2014 2015 2016

SO 2 

### allowances, under Tables 2, 3, or 4 of 40 CFR part 73. 0 0 0 0 0 EMISSION UNIT ID

CTG1 EPA

ID

T1

NO X 

### limit This affected unit is not subject to the NO X



### requirements in 40 CFR part 76.

2012 2013 2014 2015 2016

SO 2 

### allowances, under Tables 2, 3, or 4 of 40 CFR part 73. 0 0 0 0 0 EMISSION UNIT ID

CTG2 EPA

ID

T2

NO X 

### limit This affected unit is not subject to the NO X



### requirements in 40 CFR Part 76.

2012 2013 2014 2015 2016

SO 2 

### allowances, under Tables 2, 3, or 4 of 40 CFR part 73. 0 0 0 0 0 EMISSION UNIT ID

CTG3 EPA

ID

T3

NO X 

### limit This affected unit is not subject to the NO X



### 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

SO 2 

### allowances, under Tables 2, 3, or 4 of 40 CFR part 73. 0 0 0 0 0 EMISSION UNIT ID

CTG4 EPA

ID

T4

NO X 

### limit This affected unit is not subject to the NO X



### requirements in 40 CFR Part 76.

Note: The number of allowances allocated to Phase I I 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 fro m the number allocated by U.S. EPA. Neither of the aforementioned conditions necessitat e a revision to the unit SO 2 

### 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 Appli cation

### 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 ApplicationY: \ Projects \ 2011 \ 113

- 87509 Mackinaw RAI \ 120310 RAI \ Final \ R032211_509 Effingham RAI.docx Golder Associates Inc. 6026 NW 1 st 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 S tationary Source Permitting Program Georgia Department of Natural Resources 4244 International Parkway, Suite 120 Atlanta, Georgia 30354

RE: APPLICATION NO. 1 9810 MACKINAW POWER

– EFFINGHAM COUNTY POW ER PLANT RESPONSE TO COMMENTS IN LETTERS OF DECEMB ER 3, 2010 AND JANUA RY 25, 2011

Dear Ms

. Jenkins :

Mackinaw Power received comments from the Georgia Env ironmental Protec tion Division ( EPD ) in letter s dated Dec ember 3 , 2010 and January 25, 2011

, regarding the Prevention of Significant Deterioration ( PSD ) A pplication for the Effingham County Power Plant expansion project submitted in July 2010

. Responses to Georgia EPD ’s comments are present ed as follows

. 

### RESPONSES TO DECEMBE R 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 (PM 10 ) and fine particulate matter (PM 2.5 ) in New Source Review (NSR) permits as of January 1, 2011

. Mackinaw Power notes that PM 10 and PM 2.5 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 PM 10 and PM 2.5 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

. D etailed calculation s of back

- ha lf emissions for the proposed emission units we re presented in App endix 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 (SO 2 ) converted to sulfur trioxide (SO 3 ) in the combustion turbine ( CT )

, in the duct burner

, and in the selective catalytic reduction ( SCR ) and assuming all SO 3 converts to ammonium sulfate. Potential hourly PM emissions presented in Table 2

- 1 and 2

- 2 for the C T 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 co oling 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

.Ms. Susan Jenkins March 22, 2011

Georgia EPD 2 113

- 87509

Y: \ Projects \ 2011 \ 113

- 87509 Mackinaw RAI \ 120310 RAI \ Final \ R032211_509 Effingham RAI.docx Comment 3

. Mackinaw Power proposes to combust fuel oil in the combustion turbines ( C Ts)

and natural gas in the duct burners

. Mackinaw Power has proposed best available control technology (BACT) emission limits fo r carbon monoxide (CO), volatile organic compounds (VOCs), and particulate matter (PM, PM 10 , and PM 2.5 ) 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 econo mic 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 : Th is scenario was not presented in the potential annual emissions calculation in Tabl e 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 3,00 0 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 emiss ions 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 worst

case 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 upd ate 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 . T herefore, the annual operating scenario that produces the worst

case potential annual emiss ions 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 ( O 2 ) 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 a nnual 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 ho urly emission rate of 153.6 pounds per hour (lb/hr) used in Table 4

- 8 should have be en 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. ”Ms. Susan Jenkins March 22, 2011

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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 mi nimum 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 (NO x ) emissions. DLN combustion is not used during fuel oil combustion.

b. The warm startup load of 23.7 percent is a time

- period average ins tead of the actual load value at the end of warm startup. Based on data from the existing CTs, t he actual load at the i nitiation of Mode 6Q was 112 MW or 68 percent load. The maximum percent load at the end of warm startup would be approximately 70 perce nt

.

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 circu mstances 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 approximate ly 60 percent of maximum load adjusted for ambient conditions.

e . For fuel oil, w ater injection is operational at approximate ly 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 emiss ion limits or work pra ctice standards for periods of startup and shutdown

. Response : a. For each natural gas and fuel oil

- firing scenario , BACT emission limits for NO x , CO, and volatile organic compound ( VOC ) emissions from the CTs with and without duct bu rner firing are based on the maximum exhaust concentration expected for normal steady operation . Therefore, the proposed limits apply at operating load s between approximately 50 percent load and base load. Similarly, for particulate matter equal to or le ss than 10 microns ( PM 10 ) a n d particulate matter equal to or less than 2.5 microns ( PM 2.5 ), 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 NO x , CO, VOC , and PM 10 /PM 2.5 BACT limits is a 24

- hour block average. Continuous compliance with CO and NO x emissions limit s will also be monitored with

c ontinuous e missions m onitoring s ystem s (CEMS).Ms. Susan Jenkins March 22, 2011

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- state normal operation between approximately 50

- percent load and base load. Even though s tartup and shutdown of the CTs are a normal part of the power plant operation, they are not part of the steady

- state CT operation

.
S tartup 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 steady

state fully operational mode. During the initial part of the startup, the CT must be h e ld 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 wi th SCR

, a post

- combustion NO x control technology. However, du ring 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 NO x . The use of SCR during startup will also increase ammonia slip. Since SCR cannot be operated, NO x emissions during startup are higher than normal operation.

In addition, incomplete combustion at lo w loads results in higher CO and VOC emission rates. P ost

combustion control

, such as the oxidation catalyst system

, require s 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, SO 2 and PM 10 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, SO 2 and PM 10 /PM 2.5 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 startup s and 300 shutdowns expected for the proposed CTs . The expected startup and sh utdown 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

- te rm BACT emissions limits (example: 12

- month rolling NO x 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 c ombustion turbines during startup and shutdown.

Response : At this time

, fuel oil startup and shutdown emissions data ha ve 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 operati on 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

.Ms. Susan Jenkins March 22, 2011

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. 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 c omplete 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, th e U.S. Environmental Protection Agency (EPA) proposed Maximum Achievable Control Technology standards for boilers (“Boiler MACT”)

. Th is rule

, which was finalized on February 21, 2011

, will reduce emissions of toxic air pollutants from existing and new ind ustrial, 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 t hat 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 , 201 1 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 l imit of 4.0 ppmvd at 15 percent oxygen

.

A s 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 t o 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 emiss ion 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.Ms. Susan Jenkins March 22, 2011 Georgia EPD 6 113-87509

Y:\Projects\2011\113-87509 Mackinaw RAI\120310 RAI\Final\R032211_509 Effingham RAI.docx As shown in Table 6-9 in the application, the project’s annual average NO 2 impacts were predicted to be lower than the annual average PSD Class II significant im pact level, using the 0. 75 factor for conversion of NO x to NO 2 emissions. This factor is recommended by EPA in the Guid elines on Air Quality Models (GAQM), updated through 2005 in Appendix W, 40 CFR 51.

For the 1-hour average NO 2 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, additi onal modeling was performed which including modeling background sources and adding in a non-modeled bac kground concentration provided by GEPD. As shown in Table 6-11 of the application, model results for the 1-hour average NO 2 concentrations are presented for 3 cases: modeling assumed 100 percent (1.0 factor) of predicted NO x concentrations were converted to NO 2 concentrations; modeling assumed 75 percent (0.75 factor) of NO x concentrations were converted to NO 2 concentrations, and modeling was based on using the plume volume molar ratio method (PVMRM) approach with NO 2 /NO x ambient equilibrium ratio of 0.90 and in-stack NO 2 /NO x ratio of 0.10.

In all cases, the maximum 1-hour average NO 2 concentrations were predicted to be less than the NAAQS even with the assumption that 100 percent of NO x concentrations were assumed to be NO 2 concentrations. For that case, the maximum total 1-hour average NO 2 concentration was predicted to be 130.4 micrograms per cubic meter (μg/m 3 ), less than the NAAQS of 188 μg/m 3 . For the other cases, the maximum total 1-hour average NO 2 concentrations were also predicted to be less than the NAAQS. Therefore, no additional modeling is requir ed to demonstrate compliance the NAAQS.

It should be noted that on Marc h 1, 2011, EPA released guidance memorandum for modeling NO 2 impacts (Additional Clarification R egarding Applications of Appendix W Modeling Guidance for the 1-hour NO 2 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 NO 2 standard under Tier 2 without additional justification. In addition, EPA recommended general ac ceptance of 0.50 as a default in-stack NO 2 /NO x 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/tzMarch 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 b 0 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 SO 2 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/PM 10 /PM 2.5 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 NO x 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 SO 2 5.1 6.3 6.2 7.4 0.8 2.2 0.2 22 25 25 25 20 20 PM/PM 10 19.3 27.1 35.6 36.5 4.5 12.8 1.3 84.6 100.1 108.3 104.9 90 86 NO x 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 ANNUALMarch 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 AMarch 2011 1 113

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### 1.0 BEST AVAILABLE CONTR OL TECHNOLOGY ANALYS IS

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 T itle 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 applic ability 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 (CO 2 )

 Nitrous oxide (N 2 O)

 Methane (CH 4 )

 Hydrofluorocarbons (HFCs)

 Perfluorocarbons (PF Cs)

 Sulfur hexafluoride (SF 6 )

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 CO 2 equivalent (CO 2 e) 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 c ontinuing thereafter, anyway PSD sources will remain subject to PSD. In addition, sources with the potential to emit 100,000 TPY CO 2 e 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 CO 2 e 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 variou s PSD requirements such as , they must apply Best Available Control Technology (BACT),March 2011 2 113

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This section presents the proposed BACT for these pollutants. The approach to the BACT analysis is based on the regulatory definiti ons 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 authori ties 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 ef fectiveness. 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 conside rations, 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 sho uld 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 Perform ance 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 modifi cation

– 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 BACTMarch 2011 3 113

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should be considered in BACT determinations for all regulated NSR pollutants (not just GHGs).

T he following sections provide the required BACT analysis.



### 1.2 Combined Cycle CTs

This section contains the BACT an alysis 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 practi ces) 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 cat egories:

 Inherently Lower

- Emitt ing Processes/Practices/Designs

 Add

- on Controls

 Combinations of Inherently Lower Emitting Processes/Practi ces/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 , CO 2 , N 2 O

, CH 4 , HFCs

, PFCs , and SF 6 . CO 2 emissions result from the oxidation of

carbon in the fuel. CH 4 emissions result from incomplete combustion and N 2 O emissions result primarily from low temperature combustion. CO 2 , N 2 O , and CH 4 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 CO 2 than oil, and just under 45 percent less
CO 2 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 doe s not need to include a clean fuel option that would fundamentallyMarch 2011 4 113

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EPA recommends that p ermit applicants and p ermitting 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
CO 2 – energy efficiency and carbon capture and storage (CCS).

Emissions of CH 4 and N 2 O from CTs are extremely low. As a result, control options for these pollutants are not discussed except the oxidation catalyst system, which controls CH 4 as an adde d benefit. Effingham is proposing to install oxidation catalyst system for each CT

.


### Energy Efficiency Energy efficiency f alls under the general category of lower

- polluting processes/practices

. A pplying 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 pollut ants . There are different categories of energy efficient improvements :

 T echnologies or processes that maximize the efficiency o f the individual emissions unit

 O ptions that could reduce emissions from a new green field facility by improving the utilization of thermal energy and electricity tha t 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 reduc ed air pollutant emissions (including CO 2 ). Several recent BACT determinations for GHG emissions concluded that high

efficiency power generation technology is the only available and feasible control technology. Efficient power generation is also consider ed 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 technolog ies that remove polluta nts from a facility ’ s emissions stream

. EPA classifies CCS as an

add

- on pollution control technology that is “ available ” for large CO 2 - emitting facilities including fossil fuel

fired power plants and industrial facilities with high

- purity CO 2 streams . As a result, EPA requires that
CCS be considered in Step 1 of the BACT analysis

.

CCS is composed of three main components: CO 2 capture and/or compression, transport, and storage

.

Carbon Capture

- Before CO 2 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, aMarch 2011 5 113

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- 6 percent CO 2 . For effective carbon sequestration, the
CO 2 in these exhaust gases must be separated and concentrated.

The most likely options currently identifiable for CO 2 separat ion and capture include:

 Abs orption (chemical and physical)

 Ads orption (physical and chemical)

 Low

- temperature disti llation

 Gas separation membranes

 Mineralization and biomineralization

Carbon Transport

– After the CO 2 is captured, it must be transported t o a carbon sequestration site. Pipelines are the most common method for transporting large quantities of CO 2 over long distances. Shipping CO 2 via pipeline involves compressing gaseous CO 2 to a pressure above 1,160 pounds per square inch (psi), to increa se CO 2 density and make it easier and less expensive to ship

. A CO 2 pipeline would be similar to a high pressure natural gas pipeline and is technically feasible. CO 2 also can be transported as a liquid in seagoing vessels or via tankers on roads or rail ways. In these instances, the
CO 2 is held in insulated tanks at low temperatures and relatively low pressures

.

Carbon Storage

– In a CCS system, CO 2 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 CO 2 is injected into the deep geologic formations through drilled wells

. Under high pressure, CO 2 turns to liquid and can move through

a formation as a fluid. Once injected, the liquid CO 2 tends to be buoyant and will flow upward until it

encounters a barrier of non

- porous rock, which can trap the CO 2 and prevent further upward migr ation

. When CO 2 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 CO 2 trapping as well: CO 2 molecules can dissolve in brine; react with minerals to form solid carbonates; or adsorb in the pores of the porous rock.

Deep saline f ormations , which are layers of porous rock saturated with brine present an enormous potential for geologic storage of CO 2 . However, the industry doesn ’ t have as much experi ence 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 s hale , which is a thin horizontal layer of sedimentary rock with low vert ical permeability and in b asalt f ormations , 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 CH 4 emissions. Oxidation catalysts operate at elevated temperatures. In the presence of an oxidation catalyst, excess O 2 in the exhaust reacts with CH 4 to form
CO 2 . 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 ca talyst. 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 Alternative s 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 a t 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 a t 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 te chnology 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 w hile CCS may be available acc ording 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 l and), the need for funding (including, for example, government subsidies), timing of available transportation infrastructure, and developing a site for secure long term storage. Not everyMarch 2011 7 113

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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

nea r 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 i s 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 comme rcially 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, cost

effective deployment of carbon capture and stor age (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 a pplied 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 C ontrol (UIC) for CO 2 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 stora ge, 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 sequestratio n . 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 formatio n 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 t o accomplish the compression, capture, and storage of GHGs are determined to be generally

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### Oxidation Catalyst Catalytic oxidation is a feasible control technology for CH 4 . As discussed in Section 1.1, oxidation catalyst s ystem is primarily designed to control CO emissions with the following reaction :

2CO + O 2 2 CO 2

The oxidation catalyst will reduce CH 4 with the following reaction :

CH 4 + 2O 2 CO 2 + 2H 2 O

Effingham is proposing to install oxidation catalyst system to control CO emissions , which will also reduce
CH 4 as an added benefi t

. H owever, there is a trade

- off between controlling CH 4 emissions and additional
CO 2 emissions generated . But since the global warming potential of CH 4 is 21 times the global warming

po tential of CO 2 , 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 c ontrol 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 technic ally 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 ca se. 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 consi der the potential trade

- offs between emissions of GHGs and emissions of other regulated NSR pollutants. For example, controlling CO

, VOC , or CH 4 emissions with an oxidation catalyst system creates GHG emissions in the form of CO 2 . But because of the high er global warming potential of
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, 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 elim inated 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 C O 2 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 so me cases where underground storage of the captured CO 2 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 pol lutant and emissions unit under review and included in the permit.



### BACT Energy efficiency, t he 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 p lays 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 u tilized 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 t he Annual Energy Review 2009, the approximate heat rate for electricity for fossil

- fueled power plants in the U.S. in 2009 wa s 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, t he 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/March 2011 10 113

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 Steam turbine

– 10,399 Btu/kW

- hr (32.8 percent efficiency)

 G as 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

estimat ed as follows :

 Gas

- firing only

– 6,8 52 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

– 7,0 51 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

– 7,0 32 (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 p ower
block can be estimated as 6,96 3 Btu

- kW

- hr (4 9 percent efficiency). T he se estimated heat rates are well

below the app roximate 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 type s of generation using natural gas, the pro posed power block will be 8 percent more efficient t han all generation using natural gas.

When compared to existing combined cycle generation, the pro posed 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 d esigned 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 CO 2 Emissions, the emission factor s for CO 2 are
11 8.86 lb CO 2 /MMBtu for natural gas and 1 62.29 lb CO 2 /MMBtu for distillate oil

. For individual operating

scenarios of the proposed power block, u sing the heat rate and the GHG emission factor s , GHGMarch 2011 11 113

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- firing

with no duct firing, natural gas

- firing with duct firing, and fuel oil

- firing, which are presented in Table A

- 1.

The CO 2 emission rates were determined to be as follows:

 Natural gas

- firing with no duct firing

– 814.2 lb CO 2 /MWh

 Natural gas

- firing with duct fi ring

– 837.9 lb CO 2 /MWh

 Fuel oil firing

– 1,141.3 lb CO 2 /MWh

 Overall

– 862.4 lb CO 2 /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 electri c 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 CO 2
on a gene ration 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 C O 2 /MWh

 SERC Southeastern Sub

- Region

– Non

- Baseload

– 1,551.1 lb CO 2 /MWh , 21.7 lb N 2 O/GWh, 28.5 lb CH 4 /GWh

 Georgia Power Company

– 1,617.5 lb CO 2 /M Wh for all generation (includes nuclear); 1,936.9 lb CO 2 /M Wh for fossil fuel combustion

When compared, i t 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 like ly displace less efficient gen eration resulting in overall GHG reduction. For example, when operational , if the project ’ s generation displaced

non

- baseload generation, with an overall CO 2 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

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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 a vailable 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 e missions. Mackinaw Power proposes to limit the hours of operation of the auxiliary boiler to 2,500 hr/yr. Using a CO 2 emission factor of 116

. 8 6 lb/MMBtu ( Table C

- 1; 40 CFR 98, Subpart C ), the auxiliary boiler will have a potential to emit 1,987 lb/hr or app roximately 1 ton/hr of CO 2 emissions. The CO 2 emissions potential is negligible.

Also, combustion of natural gas emits less CO 2 than combusting oil or c oal 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 CO 2 emission factor as for the auxiliary boiler, the fuel heater will have a potential to emit 1,0 23 lb/hr or

0.5 1 ton/hr of CO 2 emissions. This rate is negligible

.

The fuel heater will be fired by natural gas only, which will have the potential to emit less CO 2 than firing

other fossil fuel like oil.



### 1.5 C ooling Towers

Th e proposed cooling towers will not emit any GHGs

.



### 1.6 Fuel Oil Storage Tank

Th e proposed fuel oil storage tank will not emit any GHGs.March 2011 113-87509

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 CO 2 Emissions, 40 CFR Part 75. Natural gas-firing CO 2 lb/MMBtu = 1040 scf/MMBtu x (1/385) scf CO 2 /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 CO 2 Emissions, 40 CFR Part 75. Oil-firing CO 2 lb/MMBtu = 1420 scf/MMBtu x (1/385) scf CO 2 /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) N 2 O and CH 4 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

CO 2 Emissions N 2 O Emissions (e) CH 4 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